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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, 2010        Commission File Number 1-31690

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

Canada
(Jurisdiction of incorporation or organization)

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

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

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

TransCanada PipeLine USA Ltd., 717 Texas Street
Houston, Texas, 77002-2761; (832) 320-5201
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

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

Title of each class	Name of each exchange on which registered
Common Shares (including Rights under Shareholder Rights Plan)	New York Stock Exchange

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

For annual reports, indicate by check mark the information filed with this Form:
ý    Annual Information Form	ý    Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report.

At December 31, 2010, 696,229,462 common shares;
22,000,000 Cumulative Redeemable First Preferred Shares, Series 1;
14,000,000 Cumulative Redeemable First Preferred Shares, Series 3; and
14,000,000 Cumulative Redeemable First Preferred Shares, Series 5
were issued and outstanding

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

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).     Yes o            No o

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

Form	Registration No.
S-8		333-5916
S-8		333-8470
S-8		333-9130
S-8		333-151736
F-3		33-13564
F-3		333-6132
F-10		333-151781
F-10		333-161929

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

Except sections specifically referenced below which shall be deemed incorporated by reference herein and filed, no other portion of the TransCanada Annual Report to Shareholder except as otherwise specifically incorporated by reference in the TransCanada Annual Information Form shall be deemed filed with the U.S. Securities and Exchange Commission (the "Commission") as part of this report under the Exchange Act.

A.    Audited Annual Financial Statements

For audited consolidated financial statements, including the auditors' report, see pages 97 through 150 of the TransCanada 2010 Annual Report to Shareholders 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 attached as document 13.4.

B.    Management's Discussion & Analysis

For management's discussion and analysis, see pages 6 through 96 of the TransCanada 2010 Annual Report to Shareholders included herein under the heading "Management's Discussion & Analysis".

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

For information on management's internal control over financial reporting, see Management's Report on Internal Control Over Financial Reporting attached as document 13.6.

2

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 pages 83 and 84 of the TransCanada 2010 Annual Report to Shareholders.

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 2010 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 pages 31 and 30, respectively, of the TransCanada 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 62 of the TransCanada 2010 Annual Report to Shareholders.

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
E.L. Draper
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 TransCanada securityholders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada'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, projects, and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results and expected impact of future commitments and contingent liabilities. All forward-looking statements reflect TransCanada'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 TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of TransCanada's pipeline and energy assets, the availability and price of energy commodities, capacity payments, 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 economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed. The Company's material risks and assumptions are discussed further in TransCanada's Management's Discussion and Analysis filed as document 13.2 hereto including under the headings "Natural Gas Pipelines — Opportunities and Developments", "Natural Gas Pipelines — Business Risks", "Oil Pipelines — Opportunities and Developments", "Oil 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 TransCanada 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 not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada 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 CORPORATION
Per:	/s/ DONALD R. MARCHAND DONALD R. MARCHAND Executive Vice-President and Chief Financial Officer
	Date: February 16, 2011

DOCUMENTS FILED AS PART OF THIS REPORT

13.1	TransCanada Corporation Annual Information Form for the year ended December 31, 2010.
13.2	Management's Discussion and Analysis (included on pages 6 through 96 of the TransCanada 2010 Annual Report to Shareholders).
13.3	2010 Audited Consolidated Financial Statements (included on pages 97 through 150 of the TransCanada 2010 Annual Report to Shareholders), including the auditors' report thereon.
13.4	Related supplementary note entitled "Reconciliation to United States GAAP".
13.5	Independent Auditors' Report of Registered Public Accounting Firm on the 2010 Audited Consolidated Financial Statements and on the related supplementary note entitled "Reconciliation to United States GAAP".
13.6	Management's Report on Internal Control Over Financial Reporting.
13.7	Report of Independent Registered Public Accounting Firm on the effectiveness of TransCanada's Internal Control Over Financial Reporting, as at December 31, 2010.

EXHIBITS

23.1	Consent of KPMG LLP, Independent Registered Public 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 CORPORATION

ANNUAL INFORMATION FORM

February 14, 2011

TRANSCANADA CORPORATION  1

TABLE OF CONTENTS

	Page
TABLE OF CONTENTS	1
PRESENTATION OF INFORMATION	2
FORWARD-LOOKING INFORMATION	2
TRANSCANADA CORPORATION	3
Corporate Structure	3
Intercorporate Relationships	4
GENERAL DEVELOPMENT OF THE BUSINESS	4
Developments in the Natural Gas Pipelines Business	5
Developments in the Oil Pipelines Business	7
Developments in the Energy Business	8
BUSINESS OF TRANSCANADA	9
Natural Gas Pipelines Business	10
Oil Pipelines Business	12
Regulation of the Natural Gas and Oil Pipelines Businesses	13
Energy Business	13
GENERAL	15
Employees	15
Social and Environmental Policies	16
Environmental Protection	17
RISK FACTORS	18
Environmental Risk Factors	18
Other Risk Factors	20
DIVIDENDS	20
DESCRIPTION OF CAPITAL STRUCTURE	21
Share Capital	21
CREDIT RATINGS	23
DBRS Limited (DBRS)	23
Moody’s Investors Service, Inc. (Moody’s)	23
Standard & Poor’s (S&P)	24
MARKET FOR SECURITIES	24
DIRECTORS AND OFFICERS	25
Directors	25
Board Committees	27
Officers	28
Conflicts of Interest	29
CORPORATE GOVERNANCE	29
AUDIT COMMITTEE	29
Relevant Education and Experience of Members	29
Pre-Approval Policies and Procedures	30
External Auditor Service Fees	31
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	31
TRANSFER AGENT AND REGISTRAR	31
INTEREST OF EXPERTS	31
ADDITIONAL INFORMATION	31
GLOSSARY	33
SCHEDULE “A”	A-1
SCHEDULE “B”	B-1

2

PRESENTATION OF INFORMATION

Unless the context indicates otherwise, a reference in this Annual Information Form (“AIF”) to “TransCanada” or the “Company” includes TransCanada Corporation and the subsidiaries of TransCanada Corporation through which its various business operations are conducted. In particular, “TransCanada” includes references to TransCanada PipeLines Limited (“TCPL”). Where TransCanada is referred to with respect to actions that occurred prior to its 2003 plan of arrangement with TCPL, which is described below under the heading “TransCanada Corporation — Corporate Structure”, these actions were taken by TCPL or its subsidiaries. The term “subsidiary”, when referred to in this AIF, with reference to TransCanada means direct and indirect wholly owned subsidiaries of, and legal 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, 2010 (“Year End”). Amounts are expressed in Canadian dollars unless otherwise indicated. Financial information is presented in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”).

Certain portions of TransCanada’s Management’s Discussion and Analysis dated February 14, 2011 (“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 TransCanada’s profile.

The Canadian Institute of Chartered Accountants’ (“CICA”) Accounting Standards Board (“AcSB”) previously announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”), effective January 1, 2011. As a United States (“U.S.”) Securities and Exchange Commission (“SEC”) registrant, TransCanada prepares and files a “Reconciliation to United States GAAP” and has the option to prepare and file its consolidated financial statements using U.S. generally accepted accounting principles (“U.S. GAAP”). Previously, TransCanada disclosed that effective January 1, 2011, the Company expected to begin reporting under IFRS. As a result of the developments noted below, management expects that the Company will adopt U.S. GAAP effective January 1, 2012. The Company’s IFRS conversion project was proceeding as planned to meet the conversion date of January 1, 2011, prior to these developments. In accordance with Canadian GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. These rate-regulated accounting (“RRA”) standards allow the timing of recognition of certain expenses and revenues to differ from the timing that may otherwise be expected in a non-rate-regulated business under Canadian GAAP, in order to appropriately reflect the economic impact of regulators’ decisions regarding the Company’s revenues and tolls. In October 2010, the AcSB and the Canadian Securities Administrators (“CSA”) amended their policies applicable to Canadian publicly accountable enterprises that use RRA in order to permit these entities to defer the adoption of IFRS for one year. Due to the continued uncertainty around the timing, scope and eventual adoption of an RRA standard under IFRS, TransCanada will defer its adoption of IFRS accordingly and continue preparing its consolidated financial statements in 2011 in accordance with Canadian GAAP, as defined by Part V of the CICA Handbook, in order to continue using RRA. TransCanada will continue to actively monitor IASB developments with respect to RRA and other IFRS. The impact of adopting U.S. GAAP is consistent with that currently reported in the Company’s publicly filed “Reconciliation to United States GAAP”.Significant changes to existing systems and processes are not required to implement U.S. GAAP as the Company’s primary accounting standard. For more information on TransCanada’s conversion project, see TransCanada’s MD&A under the headings “Accounting Changes – Future Accounting Changes – International Financial Reporting Standards” and “Accounting Changes – Future Accounting Changes – U.S. GAAP Conversion Project”.

Information in relation to metric conversion can be found at Schedule “A” to this AIF. Terms defined throughout this AIF are listed in the Glossary found at the end of 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 TransCanada securityholders and potential investors with information regarding TransCanada and its subsidiaries, including management’s assessment of TransCanada’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 TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results and expected impact of future commitments and contingent liabilities. All forward-looking statements reflect TransCanada’s beliefs and assumptions based on information available at the time the statements were made.

TRANSCANADA CORPORATION   3

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 TransCanada 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, capacity payments, 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 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 the heading “Risk Factors”, which could cause TransCanada’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 TransCanada with Canadian securities regulators and with the SEC. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this AIF or otherwise, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada 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 CORPORATION

Corporate Structure

TransCanada’s head office and registered office are located at 450 – 1st Street S.W., Calgary, Alberta, T2P 5H1. TransCanada was incorporated pursuant to the provisions of the Canada Business Corporations Act (“CBCA”) on February 25, 2003 in connection with a plan of arrangement which established TransCanada as the parent company of TCPL. The arrangement was approved by TCPL common shareholders on April 25, 2003 and, following court approval and the filing of Articles of Arrangement, the arrangement became effective May 15, 2003. Pursuant to the arrangement, the common shareholders of TCPL exchanged each of their TCPL common shares for one common share of TransCanada (“Common Share(s)”). The debt securities and preferred shares of TCPL remained obligations and securities of TCPL. TCPL continues to hold the assets it held prior to the arrangement and continues to carry on business as the principal operating subsidiary of the TransCanada group of entities. TransCanada does not hold any material assets directly other than the common shares of TCPL and receivables from certain of TransCanada’s subsidiaries.

4

Intercorporate Relationships

The following diagram presents the name and jurisdiction of incorporation, continuance or formation of TransCanada’s principal subsidiaries as at December 31, 2010. Each of the subsidiaries shown has total assets that exceeded 10 per cent of the total consolidated assets of TransCanada or revenues that exceeded 10 per cent of the total consolidated revenues of TransCanada as at and for the year ended December 31, 2010. TransCanada owns, directly or indirectly, 100 per cent of the voting shares in each of each of these subsidiaries, with exception to TransCanada Keystone Pipeline, LP which TransCanada indirectly holds 100 per cent of the partnership interests thereof.

The above diagram does not include all of the subsidiaries of TransCanada. The assets and revenues of excluded subsidiaries in the aggregate did not exceed 20 per cent of the total consolidated assets or total consolidated revenues of TransCanada as at and for the year ended December 31, 2010.

GENERAL DEVELOPMENT OF THE BUSINESS

Commencing in 2011, TransCanada’s reportable business segments are “Natural Gas Pipelines”, “Energy” and “Oil Pipelines”. Natural Gas and Oil Pipelines are principally comprised of the Company’s respective natural gas and oil 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 and the non-regulated natural gas storage business in Canada.

TransCanada’s strategy in Natural Gas and Oil Pipelines is focused on growing its North American natural gas and crude oil transmission network and maximizing the long-term value of its existing pipeline assets. The Company has built a substantial energy business over the past decade and has achieved a major presence in power generation in selected regions of Canada and the U.S. More recently, TransCanada has also developed a substantial non-regulated natural gas storage business in Alberta.

Summarized below are significant developments that have occurred in TransCanada’s Natural Gas Pipelines, Oil Pipelines and Energy businesses, respectively, and the significant acquisitions, dispositions, events or conditions which have had an influence on that development, during the last three financial years.

TRANSCANADA CORPORATION  5

Developments in the Natural Gas Pipelines Business

Date	Description of Development
CANADIAN MAINLINE (“Canadian Mainline”)
March 2008	The National Energy Board (“NEB”) approved the amended interim tolls for Canadian Mainline effective April 1, 2008. TransCanada had filed an application with the NEB to increase the interim tolls previously approved in December 2007. This toll increase was a result of a significant decrease in forecasted flows on the system and was intended to allow TransCanada to meet its 2008 revenue requirement.
December 2009	The NEB approved TransCanada’s application for 2010 final tolls for Canadian Mainline, effective January 1, 2010. The 2010 calculated return on equity was 8.52 per cent. Reduced throughput and greater use of shorter distance transportation contracts resulted in an increase in its tolls for 2010 compared to 2009.
August 2010	TransCanada’s open season to transport Marcellus volumes on the Canadian Mainline closed. The open season was initiated at the request of prospective shippers.
December 2010	TransCanada filed an application with the NEB for approval of the interim 2011 tolls for the Canadian Mainline which contained certain changes to the tolling mechanism to reduce long haul tolls. The NEB decided not to approve the tolls as requested in the interim tolls application and set the current 2010 tolls as interim commencing January 1, 2011.
January 2011	TransCanada filed for revised interim tolls effective March 1, 2011 based on the existing 2007–2011 settlement with customers. If approved, the revised interim tolls will allow for collection of revenues that will more closely reflect TransCanada’s costs and forecast throughput in 2011. TransCanada is continuing its discussions with stakeholders with the intent of increasing the level of support for a potential settlement and expects to file a subsequent application for final 2011 tolls for the Canadian Mainline later in 2011.
ALBERTA SYSTEM (“Alberta System”)
April 2008	An expansion of the Alberta System in the Fort McMurray area was placed in service on its projected on-stream date.
February 2009	The NEB approved TransCanada’s June 2008 application for federal regulation of the Alberta System effective April 29, 2009.
June 2010	TransCanada reached a three year settlement agreement with the Alberta System shippers and other interested parties and filed a 2010-2012 Revenue Requirement Settlement Application with the NEB.
August 2010	The NEB approved TransCanada’s November 2009 application for the Alberta System’s Rate Design Settlement and the commercial integration of the ATCO Pipeline system with the Alberta System.
September 2010	The NEB approved the Alberta System’s 2010-2012 Revenue Requirement Settlement Application.
October 2010	The NEB approved final 2010 rates for the Alberta System, which reflect the Alberta System 2010-2012 Revenue Requirement Settlement and Rate Design Settlement.
December 2010	The NEB approved the interim 2011 tolls for the Alberta System reflecting the 2010-2012 Revenue Requirement Settlement and continuing to transition to the toll methodology approved in the Rate Design Settlement. TransCanada expects to file for final 2011 tolls on the Alberta System which will reflect the outcome of further discussions with stakeholders with respect to 2011 tolls and commercial integration of the ATCO Pipeline system.
North Central Corridor Expansion (“North Central Corridor”)
October 2008	The Alberta Utilities Commission (“AUC”), which previously regulated the Alberta System, approved TransCanada’s application for a permit to construct the North Central Corridor.
October 2008	Construction of the North Central Corridor commenced.
May 2009	The 140 kilometer (“km”) North Star section of the North Central Corridor was completed.
September 2009	Work on the final phase of the North Central Corridor commenced.
March 2010	The North Central Corridor was completed, on schedule and under budget.
Groundbirch Pipeline Project (“Groundbirch”)
March 2010	The NEB approved TransCanada’s application after a public hearing, to construct and operate Groundbirch.
August 2010	TransCanada received final regulatory approvals and commenced construction of Groundbirch.
December 2010	Groundbirch was completed on schedule and under budget, and began transporting natural gas from the Montenay shale gas formation into the Alberta System.

6

Date	Description of Development
Horn River Pipeline Project (“Horn River”)
February 2009	TransCanada announced the successful completion of a binding open season, securing support for firm transportation contracts of 378 million cubic feet per day (“MMcf/d”) for the pipeline.
February 2010	TransCanada filed an application with the NEB for approval to construct and operate the pipeline.
April 2010	The NEB announced that it would hold a public hearing process on TransCanada’s February 2010 application for approval to construct and operate the pipeline. The NEB hearing relating to the Horn River pipeline concluded in November 2010.
January 2011	TransCanada received approval from the NEB to construct the Horn River pipeline.
FOOTHILLS SYSTEM (“Foothills System”)
June 2010	TransCanada reached an agreement to establish a cost of capital for Foothills System. The NEB approved final tolls for 2010, effective July 1, 2010.
MACKENZIE GAS PIPELINE PROJECT (“Mackenzie Gas Project”)
December 2009	A Joint Review Panel of the Canadian government released a report on environmental and socio-economic factors in relation to the Mackenzie Gas Project. The report was submitted to the NEB as part of the review process for approval of the project.
December 2010	The NEB approved the proponents’ application to construct the Mackenzie Gas Project subject to numerous conditions.
ALASKA PIPELINE PROJECT (“Alaska Pipeline”)
December 2008	The Alaska Commissioners of Revenue and Natural Resources issued the Alaska Gasline Inducement Act (“AGIA”) license to TransCanada to advance the Alaska Pipeline. Subsequently, TransCanada commenced the engineering, environmental, field and commercial work. Under AGIA, the State of Alaska has agreed to reimburse a share of the eligible pre-construction costs to TransCanada to a maximum of US$500 million.
June 2009	TransCanada reached an agreement with ExxonMobil Corporation (“ExxonMobil”) to jointly advance the Alaska Pipeline. A joint project team is developing the engineering, environmental, aboriginal relations and commercial work.
April 2010	The Alaska Pipeline open season commenced.
Third Quarter 2010	Interested shippers on the proposed Alaska Pipeline project submitted conditional commercial bids in the open season that closed July 30, 2010. The project is now working with shippers to resolve those conditions within the project’s control.
BISON PIPELINE (“Bison”)
September 2008	TransCanada 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 Bison.
December 2010	Construction of Bison was completed.
January 2011	Bison was placed in commercial service upon receiving final regulatory approvals to commence operations.
GREAT LAKES SYSTEM (“Great Lakes System”)
November 2009	The U.S. Federal Energy Regulatory Commission (“FERC”) initiated an investigation to determine whether rates on the Great Lakes System were just and reasonable. In response, Great Lakes Gas Transmission Limited Partnership (“Great Lakes”) filed a cost and revenue study with the FERC in February 2010.
July 2010	FERC approved, without modification, the settlement stipulation agreement reached among Great Lakes, active participants and the FERC trial staff. As approved, the stipulation and agreement applies to all current and future shippers on the Great Lakes System.
NORTH BAJA SYSTEM (“North Baja System”)
July 2009	TransCanada completed the sale of North Baja Pipeline, LLC (“North Baja”) to its affiliate, TC PipeLines, LP. As part of the transaction, TransCanada agreed to amend its incentive distribution rights with TC PipeLines, LP. Under the amendment, TransCanada received additional common units in exchange for a resetting of its incentive distribution rights at a lower percentage which escalates with increases in TC PipeLines, LP distributions. The aggregate consideration received from the partnership included a combination of cash and common units totaling approximately US$395 million.
GUADALAJARA (“Guadalajara”)
May 2009	TransCanada announced that it was the successful bidder on a contract to build, own and operate the Guadalajara pipeline.
December 2010	The Guadalajara pipeline was 70 per cent complete at Year End.

TRANSCANADA CORPORATION   7

Further information about developments in the Natural Gas Pipelines business can be found in the MD&A under the headings “TransCanada’s Strategy”, “Natural Gas Pipelines – Highlights”, “Natural Gas Pipelines – Financial Analysis” and “Natural Gas Pipelines – Opportunities and Developments”.

Developments in the Oil Pipelines Business

Date	Description of Development
KEYSTONE
2008	TransCanada increased its equity ownership in TransCanada Keystone Pipeline, LP (“Keystone U.S.”) and TransCanada Keystone Pipeline Limited Partnership (“Keystone Canada”) to 79.99 per cent from 50 per cent with ConocoPhillips’ equity ownership being reduced concurrently to 20.01 per cent.
March 2008	Keystone U.S. received a Presidential Permit authorizing the construction, maintenance and operation of facilities at the U.S. and Canada border for the transportation of crude oil between the two countries. The Presidential Permit, was issued following the issuance by the U.S. Department of State of the Final Environmental Impact Statement on January 11, 2008 for the construction of the Keystone U.S. pipeline and its Cushing extension (the “Cushing Extension”).
June 2008	The NEB approved the application for additional pumping facilities required to expand the Canadian portion of Keystone (as defined below and referred to in this section as “Keystone”) from approximately 435,000 barrels per day (“Bbl/d”) to 591,000 Bbl/d to accommodate volumes to be delivered to the Cushing markets.
July 2008	TransCanada announced plans for Keystone U.S. Gulf Coast expansion (the “U.S. Gulf Coast Expansion”) to provide additional capacity in 2013 of 500,000 Bbl/d from Western Canada to the U.S. Gulf Coast, near existing terminals in Port Arthur, Texas.
October 2008	The Company successfully conducted an open season for the U.S. Gulf Coast Expansion by securing additional firm, long term transportation contracts.
August 2009	TransCanada became sole owner of Keystone project through the purchase of ConocoPhillips’ remaining interest (approximately 20 per cent) for US$553 million and the assumption of US$197 million of short-term debt.
March 2010	The NEB approved TransCanada’s application to construct and operate the Canadian portion of the U.S. Gulf Coast Expansion.
April 2010	The U.S. Department of State issued a Draft Environmental Impact Statement for the U.S. Gulf Coast Expansion.
June 2010	Keystone oil pipeline commenced operating at a reduced maximum operating pressure as the first phase of Keystone began delivering oil to Wood River and Patoka in Illinois (“Wood River/Patoka”).
November 2010	The open season for the Bakken Marketlink (“Bakken Marketlink”) project, which commenced in September 2010, closed successfully. The Company secured firm, five year shipper contracts of 65,000 Bbl/d.
November 2010	The open season for the Cushing Marketlink (“Cushing Marketlink”) project, which commenced in September 2010, closed successfully. The Company secured contractual support sufficient to proceed with the Cushing Marketlink project, which would when completed have the ability to provide 150,000 Bbl/d of crude oil from Cushing, Oklahoma to the U.S. Gulf Coast.
December 2010	The reduced maximum operating pressure restriction on the Canadian conversion phase of the base Keystone oil pipeline was removed by the NEB following the completion of in-line inspections.
Fourth Quarter 2010	Construction of the Cushing Extension was completed, and line fill commenced in late 2010.
January 2011	The required operational modifications were completed on the Wood River/Patoka phase of Keystone oil pipeline. As a result, the system was capable of operating at the approved design pressure and the Company commenced recording earnings for the Wood River/Patoka phase in February 2011.
February 2011	The commercial in service of the Cushing Extension commenced.

Further information about developments in the Oil Pipelines business can be found in the MD&A under the headings “TransCanada’s Strategy”, “Oil Pipelines – Highlights”, “Oil Pipelines – Financial Analysis” and “Oil Pipelines – Opportunities and Developments”.

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Developments in the Energy Business

Date	Description of Development
RAVENSWOOD GENERATING STATION (“Ravenswood”)
August 2008	TransCanada completed its acquisition of Ravenswood for US$2.9 billion, subject to certain post-closing adjustments, pursuant to a purchase agreement with KeySpan Corporation and certain subsidiaries.
BÉCANOUR (“Bécancour”)
June 2010	Hydro-Québec Distribution (“Hydro-Québec”) notified TransCanada it would exercise its option to extend the agreement to suspend all electricity generation from Bécancour throughout 2011. Hydro-Québec had previously announced that it would exercise its option to extend the agreement to suspend all electricity generation from Bécancour throughout 2010. Under the original agreement, Hydro-Québec has the option, subject to certain conditions, to extend the suspension on an annual basis until such time as regional electricity demand levels recover. TransCanada will continue to receive payments under the agreement similar to those that would have been received under the normal course of operation.
BRUCE POWER (“Bruce Power”)
January 2008	The sixteenth and final new steam generator was installed in Bruce A (as defined below and referred in this section as “Bruce A”) Units 1 and 2.
Fourth Quarter 2008	A review of the end of life estimates for Units 3 and 4 was completed. As a result of the review, Unit 3 was expected to be in commercial service until 2011, providing an additional two years of generation before refurbishment. After the refurbishment, the end of life estimate for Unit 3 was to be extended to 2038. The review also showed that Unit 4 was expected to remain in commercial service until 2016, providing seven years of generation before refurbishment, after which the end of life estimate for Unit 4 was expected to be extended to 2042.
July 2009	Bruce Power and the Ontario Power Authority (“OPA”) amended certain terms and conditions included in the Bruce Power Refurbishment Implementation Agreement. The amendments were consistent with the intent of the agreement, originally signed in 2005, and recognize the significant changes in Ontario’s electricity market. Under the original agreement, Bruce A committed to refurbish and restart the currently idle Units 1 and 2, extend the operating life of Unit 3 and replace the steam generators on Unit 4. An amendment in 2007 provided for a full refurbishment of Unit 4, which will extend the expected operating life of the unit. This most recent amendment included amendments to Bruce B (as defined below and referred in this section as “Bruce B”) floor price mechanism, the removal of a support payment cap for Bruce A, an amendment to the capital cost-sharing mechanism, and provision for deemed generation payments to Bruce Power at the contract prices under circumstances where generation from Bruce A and Bruce B is reduced due to system curtailments on the Independent Electricity System Operator controlled grid in Ontario.
October 2010	The last of the 960 calandria tubes were successfully installed in Bruce A Units 1 and 2.
December 2010	The last of the fuel channel assemblies into Bruce A Unit 2 were successfully installed.
February 2011	A maintenance outage of approximately three weeks commenced on February 1, 2011 on Bruce B Unit 8 and outages of approximately seven weeks each are scheduled to begin in mid-April 2011 for Bruce B Unit 7 and mid-October 2011 for Bruce B Unit 5. Bruce A expects an outage of approximately one week on Unit 3 in July 2011 and, following approval from the Canadian Nuclear Safety Commission the West Shift Plus outage of approximately six months is scheduled to commence in early November 2011 on Unit 3. The West Shift Plus outage is a key part of the life extension strategy for Unit 3 and is an extension of the West Shift program which was successfully executed in 2009. Subject to regulatory approval, Bruce Power expects to load fuel into Unit 2 in second quarter 2011 and achieve a first synchronization of the generator to the electrical grid by the end of 2011, with commercial operation expected to occur in first quarter 2012. Bruce Power expects to load fuel into Unit 1 in third quarter 2011, with a first synchronization of the generator during first quarter 2012 and commercial operation expected to occur during third quarter 2012. Plant commissioning and testing are underway and will accelerate in second quarter 2011 when construction activities are essentially complete.
February 2011	The Bruce Power Refurbishment Implementation Agreement was amended to reflect: the suspension date for contingent support payments on Bruce A output was extended to June 1, 2012 from December 31, 2011, and as a result, all output from Bruce A will receive spot prices from June 1, 2012 until the restart of Units 1 and 2 is complete; and a recovery of costs incurred by Bruce A in connection with development of fuel programs.
PORTLANDS ENERGY CENTRE (“Portlands Energy”)
April 2009	Portlands Energy was fully commissioned, ahead of time and under budget.
OAKVILLE GENERATING STATION
September 2009	The OPA advised TransCanada that it was awarded a 20 year Clean Energy Supply contract to build, own and operate a 900 MW a generating station in Oakville, Ontario.
October 2010	The Government of Ontario announced that it would not proceed with the Oakville generating station. TransCanada commenced negotiations with the OPA on a settlement which would terminate the Clean Energy Supply contract and compensate TransCanada for the economic consequences associated with the contract’s termination.

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Date	Description of Development
CARTIER WIND (“Cartier Wind”)
November 2008	The 109 MW Carleton wind farm, the third of five phases of Cartier Wind, became operational.
Third Quarter 2009	Construction activity began on the Cartier Wind’s 212 MW Gros-Morne and 58 MW Montagne-Sèche wind farms. The Montagne-Sèche project and phase one of the Gros-Morne project are expected to be operational in 2011, and phase two of the Gros-Morne project is expected to be operational in 2012, subject to the necessary approvals.
COOLIDGE (“Coolidge”)
May 2008	TransCanada announced that the Phoenix, Arizona based utility, Salt River Project Agricultural Improvement and Power District, signed a 20 year power purchase agreement to secure 100 per cent of the output from Coolidge.
December 2008	The Arizona Corporation Commission granted a Certificate of Environmental Compatibility approving Coolidge.
August 2009	TransCanada began construction of Coolidge.
December 2010	At Year End, construction of Coolidge was approximately 95 per cent complete and commissioning was approximately 80 per cent finished.
KIBBY WIND (“Kibby Wind”)
July 2008	Kibby Wind received unanimous final development plan approval from Maine’s Land Use Regulation Commission.
October 2009	The first phase of Kibby Wind, including 22 turbines capable of producing a combined 66 MW of power, was completed and placed in service ahead of schedule and under budget.
October 2010	The 66 MW second phase of the Kibby Wind was completed and placed in service. This phase included the installation of an additional 22 turbines, ahead of schedule and on budget.
SUNDANCE (“Sundance”)
February 2011	On February 8, 2011, TransCanada received from TransAlta Corporation (“TransAlta”) notice under the Sundance A power purchase arrangement that TransAlta has determined that the Sundance 1 and 2 generating units cannot be economically repaired, replaced, rebuilt or restored and that TransAlta therefore seeks to terminate the power purchase arrangement in respect of those units. TransCanada has not received any information that would validate TransAlta’s determination that the units cannot be economically restored to service. TransCanada has 10 business days from the date of TransAlta’s notice to either agree with or dispute TransAlta’s determination that the Sundance 1 and 2 generating units cannot be economically repaired, replaced, rebuilt or restored. TransCanada will assess any information provided by TransAlta during this 10-day period. If TransCanada disputes TransAlta’s determination, the issue will be resolved using the dispute resolution procedure under the terms of the power purchase arrangement. In December 2010, the Sundance 1 and 2 generating units were withdrawn from service for testing. In January 2011, these same units were subject to a force majeure claim by TransAlta under the power purchase arrangement. TransCanada has received insufficient information to make an assessment of TransAlta’s force majeure claim and therefore has recorded revenues under the power purchase arrangement as though this event was a normal plant outage.
Second Quarter 2010	Sundance B Unit 3 experienced an unplanned outage related to mechanical failure of certain generator components that the facility operator, TransAlta, has asserted is a force majeure event. TransCanada has received no information that validates a claim of force majeure and therefore has recorded revenues under the power purchase arrangement as though this event was a normal plant outage. TransCanada is pursuing the remedies available to it under the terms of the power purchase arrangement.
HALTON HILLS GENERATING STATION (“Halton Hills”)
September 2010	Halton Hills, which was constructed pursuant to a 20 year Clean Energy Supply contract with the OPA in November 2006, was completed and placed in service.
ZEPHYR (“Zephyr”) AND CHINOOK (“Chinook”) POWER TRANSMISSION LINES
February 2009	The FERC approved the application filed by TransCanada in December 2008 requesting approval to charge negotiated rates and to proceed with open seasons in the spring of 2009 for Zephyr and Chinook, respectively. Zephyr is a proposed 1,609 km (1,000 mile), 500 kilovolt high voltage direct current (“HVDC”) line that would be capable of delivering primarily wind generated power from Wyoming to Nevada. Chinook is a proposed 1,609 km (1,000 miles), 500 kilovolt HVDC line that would be capable of delivering primarily wind generated power to markets from Montana to Nevada. The open seasons commenced in October 2009.
May 2010	TransCanada concluded a successful open season for Zephyr. Support from key markets and a positive regulatory environment are necessary before the significant siting and permitting activities required to construct Zephyr will commence and TransCanada anticipates making a decision on whether to proceed in 2011.
December 2010	TransCanada closed the open season for Chinook without allocating capacity to Montana shippers. TransCanada continues to advance the Chinook project, and discussions with Montana wind developers and other market participants is ongoing.

Further information about developments in the Energy business can be found in the MD&A under the headings “TransCanada’s Strategy”, “Energy – Highlights”, “Energy – Financial Analysis” and “Energy – Opportunities and Developments”.

BUSINESS OF TRANSCANADA

TransCanada is a leading North American energy infrastructure company focused on Natural Gas Pipelines, Oil Pipelines and Energy. At Year End, Natural Gas Pipelines accounted for approximately 54 per cent of revenues and 51 per cent of TransCanada’s total assets, Oil Pipelines had not yet recorded any revenues but accounted for 18 per cent of TransCanada’s total assets and Energy accounted for approximately 46 per cent of revenues and 28 per cent of TransCanada’s total assets.  The following is a description of each of TransCanada’s three main areas of operation.

The following table shows TransCanada’s revenues from operations by segment, classified geographically, for the years ended December 31, 2010 and 2009.

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Revenues From Operations (millions of dollars)	2010	2009
Natural Gas Pipelines
Canada - Domestic	$2,125	$2,389
Canada - Export(1)	837	755
United States and other	1,411	1,585
	4,373	4,729
Oil Pipelines	Nil	Nil
Energy(2)
Canada – Domestic	2,243	2,690
Canada - Export(1)	1	1
United States and other	1,447	761
	3,691	3,452
Total Revenues(3)	$8,064	$8,181

(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.

Natural Gas Pipelines Business

TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and regulated gas storage facilities. TransCanada’s network of wholly owned natural gas pipelines extends more than 60,000 km (37,000 miles), and its partially owned natural gas pipelines extend more than 8,800 km (5,500 miles), tapping into virtually all major gas supply basins in North America. TransCanada has substantial Canadian and U.S. natural gas pipeline and related holdings, including those listed below.  The following natural gas pipelines are owned 100 per cent by TransCanada unless otherwise stated.

TransCanada has the following natural gas pipelines and related holdings in Canada:

·TransCanada’s Canadian Mainline is a 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.

·TransCanada’s Alberta System is a natural gas transmission system in Alberta and Northeast British Columbia (“B.C.”) which gathers natural gas for use within the province of Alberta and delivers it to provincial boundary points for connection with the Canadian Mainline and the Foothills System and with third party natural gas pipelines. The 24,187 km (15,029 mile) Alberta System is one of the largest carriers of natural gas in North America.  During the  past three completed financial years TransCanada has enhanced the Alberta System as follows:

oNorth Central Corridor, which extends the northern section of the Alberta System, was completed in March 2010; and

oTransCanada continues to advance further pipeline development in B.C. and Alberta to transport unconventional shale gas supply as follows:

·Groundbirch was completed in December 2010, connecting the Alberta System to natural gas supplies from the Montney shale gas formation in Northeast B.C. TransCanada has entered into firm transportation agreements with Groundbirch pipeline customers for 1.24 billion cubic feet per day (“Bcf/d”) by 2014;

·TransCanada has applied to build the proposed Horn River pipeline, an extension of the Alberta System to serve production from the new shale gas supply in the Horn River basin north of Fort Nelson, B.C. TransCanada received approval from the NEB to construct the Horn River pipeline in January 2011. The Horn River pipeline is scheduled to be operational in second quarter 2012 with commitments for contracted natural gas of over 634 MMcf/d by 2014; and

·the Company has received requests for additional natural gas transmission service throughout the northwest portion of the Western Canadian Sedimentary Basin, including the Horn River and Montney areas of B.C. These new requests are expected to result in the need for further extensions and expansions of the Alberta System.

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·TransCanada’s Foothills System is a 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.

·TransCanada Pipeline Ventures LP owns a 161 km (100 mile) pipeline and related facilities that supply natural gas to the oil sands region near Fort McMurray, Alberta as well as a 27 km (17 mile) pipeline that supplies natural gas to a petrochemical complex at Joffre, Alberta.

·TQM (“TQM”) is 50 per cent owned by TransCanada. TQM is a 572 km (355 mile) pipeline system that connects with the Canadian Mainline near the Québec/Ontario border and transports natural gas to markets in Québec, and connects with the Portland System. TQM is operated by TransCanada.

·The Mackenzie Gas Project is a proposed natural gas pipeline extending 1,196 km (743 mile) that would connect northern onshore natural gas fields with North American markets. TransCanada has the right to acquire an equity interest in the project.

TransCanada has the following natural gas pipeline and related holdings in the U.S.:

·The proposed Alaska Pipeline is a 4.5 Bcf/d natural gas pipeline and treatment plant. The pipeline would extend 2,737 km (1,700 miles) from the natural gas treatment plant at Prudhoe Bay, Alaska to Alberta, or an alternative pipeline to Valdez, Alaska. TransCanada received approval of its plan to conduct an open season from the FERC in March 2010. An open season commenced at the end of April 2010, and continued until July 2010. TransCanada is continuing to negotiate with potential shippers from the initial open season. The Alaska Pipeline project is a joint effort between TransCanada and ExxonMobil pursuant to the AGIA.

·TransCanada’s ANR System (“ANR System”) is a 17,000 km (10,563 mile) natural gas transmission system which transports natural gas from producing fields located in the Texas and Oklahoma panhandle regions, from the offshore and onshore regions of the Gulf of Mexico, and from the U.S. Midcontinent region to markets located mainly in Wisconsin, Michigan, Illinois, Indiana and Ohio. ANR System 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 American Natural Resources Company and ANR Storage Company (collectively, “ANR”) provide regulated gas storage services to customers on the ANR System and the Great Lakes System in upper Michigan. In total, the ANR business unit owns and operates natural gas storage facilities throughout the State of Michigan with total natural gas storage capacity of 250 billion cubic feet (“Bcf”).

·The GTN System (“GTN System”) is TransCanada’s 2,178 km (1,353 miles) natural gas transmission system that transports Western Canada Sedimentary Basin and Rocky Mountain sourced natural gas to third party natural gas pipelines and markets in Washington, Oregon and California, and connects with the Tuscarora Gas Transmission Company (“Tuscarora”) pipeline.

·The Bison pipeline is a 487 km (303 mile) natural gas pipeline from the Powder River Basin in Wyoming connecting to the Northern Border Pipeline System (“NBPL System”) in Morton County, North Dakota. The Company commenced construction of the Bison pipeline in July 2010 and the pipeline became operational in January 2011. The Bison pipeline has long term shipping commitments for 407 MMcf/d.

·The Great Lakes System is a 3,404 km (2,115 mile) natural gas transmission system connecting to the Canadian Mainline and serves markets primarily in Eastern Canada and the Northeastern and Midwestern U.S. TransCanada operates the Great Lakes System and effectively owns 71.3 per cent of the system through its 53.6 per cent ownership interest and its indirect ownership, which it has through its 38.2 per cent interest in TC PipeLines, LP.

·The 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. TransCanada operates and effectively owns 19.1 per cent of the NBPL System through its 38.2 per cent interest in TC PipeLines, LP.

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·Tuscarora is 100 per cent owned by TC PipeLines, LP. TransCanada operates the Tuscarora System (“Tuscarora System”) a 491 km (305 mile) pipeline system transporting natural gas from the GTN System at Malin, Oregon to Wadsworth, Nevada, with delivery points in Northeastern California and Northwestern Nevada. TransCanada effectively owns 38.2 per cent of the system through its 38.2 per cent interest in TC PipeLines, LP.

·North Baja is 100 per cent owned by TC PipeLines, LP. TransCanada operates the North Baja System, a natural gas transmission system which extends 138 km (86 miles) from Ehrenberg, Arizona to a point near Ogilby, California on the California/Mexico border and connects with a third party natural gas pipeline system in Mexico.  TransCanada effectively owns 38.2 per cent of the same through its 38.2 per cent interest in TC PipeLines, LP.

·The Iroquois System (“Iroquois System”) is a gas transmission system that connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to customers in the Northeastern U.S. TransCanada has a 44.5 per cent ownership interest in this 666 km (414 mile) pipeline system.

·The Portland System (“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. TransCanada has a 61.7 per cent ownership interest in the Portland System and operates this pipeline.

·TransCanada holds a 38.2 per cent interest in TC PipeLines, LP, a publicly held limited partnership of which a subsidiary of TransCanada 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, 46.4 per cent in the Great Lakes System, 100 per cent of the  Tuscarora System and 100 per cent of the North Baja System.

TransCanada 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. TransCanada holds a 46.5 per cent ownership interest in this pipeline.

·Owned 30 per cent by TransCanada, Gas Pacifico is a 540 km (336 mile) natural gas pipeline extending from Loma de la Lata, Argentina to Concepción, Chile. TransCanada 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.

·Tamazunchale is a 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.

·The proposed Guadalajara pipeline is under construction and when completed will extend approximately 305 km (190 miles) transporting natural gas from a LNG terminal under construction near Manzanillo on Mexico’s Pacific coast to Guadalajara, the second largest city in Mexico. The Guadalajara pipeline is supported by a twenty-five year contract for its entire capacity with Comisión Federal de Electridad, Mexico’s state-owned electric power company. Guadalajara pipeline has an expected in service date of mid-2011 and was 70 per cent complete at Year End.

Further information about the Company’s pipeline holdings, developments and opportunities and significant regulatory developments which relate to Natural Gas Pipelines can be found in the MD&A under the headings “Natural Gas Pipelines”, “Natural Gas Pipelines – Opportunities and Developments” and “Natural Gas Pipelines – Financial Analysis”.

Oil Pipelines Business

With increasing production from crude oil sands in Alberta and new crude oil discoveries in the U.S., including the Bakken shale play in Montana and North Dakota, along with growing demand for secure, reliable sources of energy, TransCanada has identified opportunities to develop new oil pipeline capacity. The Company’s Keystone crude oil pipeline and other opportunities in TransCanada’s oil pipeline business are described below.

Keystone (“Keystone”) is a crude oil pipeline system designed to initially carry 1.1 million Bbl/d which is comprised of the completed 3,467 km (2,154 mile) Wood River/Patoka and Cushing Extension phases, and the proposed 2,673 (1,661 mile) U.S. Gulf Coast Expansion. The Wood River/Patoka phase transports crude oil from Hardisty, Alberta to U.S. Midwest markets at

TRANSCANADA CORPORATION   13

Wood River and Patoka, Illinois and is designed for an initial nominal capacity of 435,000 Bbl/d. The Wood River/Patoka phase was placed in service in June 2010. The Cushing Extension extends the pipeline to Cushing, Oklahoma and increases nominal capacity to 591,000 Bbl/d  if design capacity is achieved. The Cushing Extension was placed in service in February 2011. The proposed U.S. Gulf Coast Expansion, which would expand and extend Keystone from Hardisty to a delivery point near existing terminals in Port Arthur, Texas, is expected to provide additional pipeline capacity in 2013, pending U.S. regulatory approval.

The Company is pursuing the opportunity to transport growing Bakken shale crude oil production from the Williston Basin in Montana and North Dakota for delivery to major U.S. refining markets. Following an open season conducted in the second half of 2010, the Company secured firm, five year shipper contracts totaling 65,000 Bbl/d for its proposed Bakken Marketlink project, which would transport U.S. crude oil from Baker, Montana to Cushing, Oklahoma on facilities that form part of the U.S. Gulf Coast Expansion. Following an open season conducted in the second half of 2010, the Company secured contractual support sufficient to proceed with the Cushing Marketlink project, which would when completed transport up to 150,000 Bbl/d of crude oil from Cushing, Oklahoma to the U.S. Gulf Coast on facilities that form part of the U.S. Gulf Coast Expansion. With these commitments, TransCanada will file for the necessary regulatory approvals in the U.S. to construct and operate the Bakken and Cushing Marketlink pipelines. Commercial in service is anticipated in 2013.

Further information about the Company’s pipeline holdings, developments and opportunities and significant regulatory developments which relate to Oil Pipelines can be found in the MD&A under the headings “Oil Pipelines”, “Oil Pipelines – Opportunities and Developments” and “Oil Pipelines – Financial Analysis”.

Regulation of the Natural Gas and Oil Pipelines Businesses

Canada

Under the terms of the National Energy Board Act (Canada), the Canadian Mainline, TQM, and the Foothills and Alberta systems (collectively referred to in this section as the “Systems”) are regulated by the NEB (the Alberta System became subject to federal jurisdiction on April 29, 2009 following NEB approval of an application by TransCanada). The NEB sets tolls which provide TransCanada the opportunity to recover projected costs of transporting natural gas, including the return on the average investment base for each of the Systems. In addition, new facilities are approved by the NEB before construction begins and the NEB regulates the operations of each of the Systems. Net earnings of the Systems may be affected by changes in investment base, the allowed return on equity, the level of deemed common equity and any incentive earnings.

The NEB regulates the terms and conditions of service, including rates, and the physical operation of the Canadian portion of Keystone. NEB approval is also required for facility additions, such as the Canadian portion of the proposed U.S. Gulf Coast Expansion project which was approved by the NEB in March 2010.

United States

TransCanada’s wholly owned and partially owned U.S. pipeline systems, including the ANR, GTN, Great Lakes, Iroquois, Portland, NBPL, North Baja and Tuscarora systems, are considered “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 transportation rates, on the U.S. portion of Keystone system. Certain states in which Keystone has right of ways also regulate construction and siting of Keystone.

Energy Business

The Energy segment of TransCanada’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

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energy and industrial customers, the development, construction and ownership and operation of non-regulated natural gas storage in Alberta.

The electrical power generation plants and power supply that TransCanada has an interest in, including those under development, in the aggregate, represent more than 10,800 MW of power generation capacity. Power plants and power supply in Canadian power account for approximately 65 per cent of this total, and power plants in U.S. power account for the balance, being approximately 35 per cent.

TransCanada owns and operates the following facilities:

·Ravenswood generating station, 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 20 per cent of New York City’s peak load.

·Halton Hills, a 683 MW natural gas-fired power plant in Halton Hills, Ontario, which was placed in service in September 2010. All of the power produced by the facility is sold to the OPA under a 20 year Clean Energy Supply contract.

·Kibby Wind, a 132 MW wind farm located in the Kibby and Skinner Townships in Maine. The first 66 MW phase of Kibby Wind was place in service in October 2009 and the second 66 MW phase was placed in service in October 2010.

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

·Ocean State Power (“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 under a 20 year power purchase agreement expiring in 2026.  Steam is also sold to an industrial customer for use in commercial processes. Since 2008, electricity generation at the Bécancour power plant has been temporarily suspended under an agreement entered into with Hydro-Québec. Under the agreement, TransCanada receives payments that are similar to those that would have been received under the normal course of operation.

·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 on the site of the Irving Oil Limited oil refinery in Saint John, New Brunswick. Irving Oil Limited is under a 20 year tolling arrangement that expires in 2025, to supply fuel for the plant and to contract 100 per cent of the plant’s heat and electricity output.

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

·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 MMcf/d of natural gas. Edson has a working natural gas storage capacity of approximately 50 Bcf.

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

·TransCanada 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 arrangement that expires in 2017. TransCanada also has the rights to 50 per cent of the generating capacity of the 706 MW Sundance B facility under a power purchase arrangement, which expires in 2020. The Sundance A and Sundance B facilities are located in South Central Alberta.

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·The Sheerness (“Sheerness”) facility, which consists of two coal-fired thermal power generating units, is located in Southeastern Alberta. TransCanada has the rights to 756 MW of generating capacity from the Sheerness power purchase arrangement that expires in 2020.

TransCanada has interests in the following:

·Two nuclear power generating stations, Bruce A, which is owned 48.8 per cent by TransCanada and has four 750 MW reactors, of which two are currently operating and two are being refurbished, and Bruce B, which is owned 31.6 per cent by TransCanada and has four operating reactors with a combined capacity of approximately 3,200 MW. Bruce Power is two partnerships with generating facilities and offices located on 2,300 acres northwest of Toronto, Ontario on which are housed Bruce A and Bruce B. The two units of Bruce A which are being refurbished are expected to re-commence commercial operations in first quarter and third quarter 2012.

·A 60 per cent ownership in CrossAlta, which is a 68 Bcf underground natural gas storage facility connected to the Alberta System near Crossfield, Alberta. The facility’s central processing system is capable of maximum injection and withdrawal rates of 550 MMcf/d of natural gas.

·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.

·Portlands Energy, a 550 MW, combined-cycle natural gas power plant located in Toronto, Ontario is 50 per cent owned by TransCanada. This facility, which was fully commissioned in April 2009, provides electricity under a 20 year Accelerated Clean Air Energy Supply contract with the OPA.

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

·The Cartier Wind energy project consists of five wind projects in the Gaspé region of Québec contracted by Hydro-Québec representing a total of 590 MW when complete. Three of the wind farms are in service, and two are currently under construction. The Montagne-Sèche project and phase one of the Gros-Morne project (101 MW) are expected to be operational in 2011, and phase two of the Gros-Morne project (111 MW) is expected to be operational in 2012, subject to the necessary approvals. Cartier Wind is 62 per cent owned by TransCanada. All of the power produced by Cartier Wind is sold to Hydro-Québec under a 20 year power purchase agreement.

·Coolidge is a simple-cycle, natural gas-fired peaking power generation station under construction in Coolidge, Arizona. Based on optimal operating conditions, TransCanada expects an electrical output of approximately 575 MW from this facility, designed to provide a quick response to peak power demands. Construction commenced in August 2009 and was approximately 95 per cent complete at Year End. The generating station is expected to be placed in service in accordance with its 20 year power purchase agreement with the Salt River Project Agricultural Improvement and Power District in second quarter 2011.

Further information about TransCanada’s energy holdings and significant developments and opportunities in relation to Energy can be found in the MD&A under the headings “Energy”, “Energy – Highlights”, “Energy – Financial Analysis” and “Energy – Opportunities and Developments”.

GENERAL

Employees

At Year End, TransCanada’s principal operating subsidiary, TCPL, had approximately 4,230 full time active employees, substantially all of whom were employed in Canada and the U.S., as set forth in the following table.

Calgary	1,862
Western Canada (excluding Calgary)	460
Houston	453
U.S. Midwest	453
U.S. Northeast	409
Eastern Canada	264
U.S. Southeast/Gulf Coast	233

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U.S. West Coast	86
Mexico and South America	10
Total	4,230

Social and Environmental Policies

Health, safety and environment (“HS&E”) are top priorities in all of TransCanada’s operations and activities. These areas are guided by the Company’s HS&E Commitment Statement, which outlines guiding principles for a safe and healthy environment for TransCanada’s employees, contractors and the public, and for TransCanada’s commitment to protect the environment. All employees are responsible for TransCanada’s HS&E performance. TransCanada 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. TransCanada 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. TransCanada endeavors to do business with companies and contractors that share its perspective on HS&E performance and to influence them to improve their collective performance. TransCanada is committed to respecting the diverse environments and cultures in which it operates and to support open communication with its stakeholders.

The Health, Safety and Environment Committee of the Board of Directors (the “Board”) monitors compliance with the Company’s HS&E corporate policy through regular reporting.  TransCanada’s HS&E management system is modeled on the International Organization for 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. TransCanada’s HS&E management system and performance are assessed by an independent outside firm every three years. The most recent assessment occurred in December 2009 and did not identify any material issues.  The HS&E management system is subject to ongoing internal review to ensure that it remains effective as circumstances change.

As one of TransCanada’s priorities, safety is an integral part of the way its employees work. In 2010, one of TransCanada’s objectives was to sustain health and safety performance. Overall, TransCanada’s safety frequency rates in 2010 continued to be better than most industry benchmarks.

The safety and integrity of the Company’s existing and newly developed infrastructure also continued to be top priorities. All new assets are designed, constructed and commissioned with full consideration given to safety and integrity, and are brought into service only after all necessary requirements have been satisfied. The Company expects to spend approximately $250 million in 2011 for pipeline integrity on its wholly owned pipelines, an increase of approximately $95 million over 2010 primarily due to increased levels of in-line pipeline inspection on all systems and pipeline enhancements in areas of population encroachment. Under the approved regulatory models in Canada, non-capital pipeline integrity expenditures on NEB regulated pipelines are treated on a flow-through basis and, as a result, these expenditures have no impact on TransCanada’s earnings. Under the Keystone contracts, pipeline integrity expenditures are recovered through the tolling mechanism and, as a result, these expenditures have no impact on TransCanada’s earnings. Expenditures for GTN System may also be recovered through a cost recovery mechanism in its rates if threshold expenditures are achieved. TransCanada’s pipeline safety record in 2010 continued to be above industry benchmarks. TransCanada experienced no pipeline breaks in 2010. 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.

Aboriginal and Stakeholder Relations

TransCanada has recognized the enhanced level of engagement of a wide variety of stakeholders in its business activities that can have a significant impact on the Company’s ability to obtain approvals for new assets and to maintain its licences to operate.  TransCanada has adopted a code of business ethics which applies to the Company’s employees that is based on the Company’s four core values of integrity, collaboration, responsibility and innovation, which guide the interaction between and among the Company’s employees and serve as a standard for TransCanada in its dealings with all stakeholders. The code, which may be viewed on TransCanada’s website at www.transcanada.com, sets out the fundamental principles of compliance with the law, fair dealing and a commitment to HS&E.

TransCanada’s approach to stakeholder engagement is based on building relationships, mutual respect and trust while recognizing the unique values, needs and interests of each community. Key principles that guide TransCanada’s engagement include: the Company’s respect for the diversity of Aboriginal/Native American communities and recognition of the importance of the land to these communities; and the Company’s belief in engaging stakeholders from the earliest stages of its projects, through the project development process and into operations.

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Environmental Protection

TransCanada’s facilities are subject to stringent federal, provincial, state and local environmental statutes and regulations regarding environmental protection, including requirements that establish compliance and remedial obligations.  Such laws and regulations generally require facilities to obtain and comply with a wide variety of environmental restrictions, licences, permits and other approvals.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial requirements, and/or the issuance of orders respecting future operations. TransCanada has ongoing inspection programs designed to keep all of its facilities in compliance with environmental requirements.

At December 31, 2010, TransCanada recorded liabilities of approximately $84 million (2009 - $91 million) for remediation obligations and compliance costs associated with environmental regulations. 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.

TransCanada is not aware of any material outstanding orders, claims or lawsuits against it in relation to the release or discharge of any material into the environment or in connection with environmental protection.

In 2010, the Company owned assets in four regions , Alberta, Québec, B.C., and the Northeastern U.S., where regulations exist to address industrial greenhouse gas (“GHG”) emissions. TransCanada has procedures in place to address these regulations. In Alberta, under the Specified Gas Emitters Regulation, industrial facilities emitting GHGs over an intensity threshold level are required to reduce GHG emissions intensities by 12 per cent below an average baseline. TransCanada’s Alberta-based facilities are subject to this regulation, as are the Sundance and Sheerness coal-fired power facilities with which TransCanada has power purchase arrangements. As an alternative to reducing emissions intensities, compliance can be achieved through acquiring offsets or making payments to a technology fund at a cost of $15 per tonne of carbon dioxide (“CO2”) equivalents in excess of the mandated reduction. A program is in place to manage the compliance costs incurred by these assets as a result of regulation. Compliance costs on the Alberta System are recovered through tolls paid by customers. Some of the compliance costs from the Company’s power generation facilities in Alberta are recovered through market pricing and contract flow-through provisions. TransCanada has estimated and recorded related costs of $22 million for 2010, after contracted cost recovery.

In Québec, the natural gas distributor collects the hydrocarbon royalty on behalf of the provincial government through a green fund contribution charge on gas consumed. In 2010, the cost pertaining to the Bécancour facility arising from the hydrocarbon royalty was less than $1 million as a result of an agreement between TransCanada and Hydro-Québec to temporarily suspend the facility’s power generation. The cost is expected to increase substantially when the plant returns to service.

The carbon tax in B.C., which came into effect in mid-2008, applies to CO2 emissions 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 in 2010 were estimated at $4 million.  As specified by this law, the cost per tonne of CO2 will increase in July 2011 to $25.00 from $20.00.

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 in January 2009. Under the RGGI, both the Ravenswood and Ocean State Power generation facilities will be required to submit allowances following the end of the first compliance period on December 31, 2011. TransCanada participated in the quarterly auctions of allowances for the Ravenswood and Ocean State Power generation facilities and incurred related costs of approximately $5 million in 2010.  These costs were generally recovered through the power market and the net impact on TransCanada was not significant.

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RISK FACTORS

Environmental Risk Factors

Environmental Risks

Environmental risks from TransCanada’s operating facilities typically include: air emissions, such as nitrogen oxides, particulate matter and GHGs; potential impacts on land, including land reclamation or restoration following construction; the use, storage and 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.

As mentioned above, TransCanada’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, and with damage claims arising from the contamination of properties. It is not possible for TransCanada to estimate the amount and timing of all future expenditures related to environmental matters due to:

·uncertainties in estimating pollution control and clean up costs, including at 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 the Company’s 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 of them; and

·the potential for litigation on existing or discontinued assets.

Oil Leaks and Spills

In 2010, the Wood River/Patoka phase of Keystone became operational. Steel pipelines are a safe, efficient and economical method of transporting crude oil. The equipment and procedures put in place with respect to Keystone provide the capability to contain oil leaks quickly and safely.

TransCanada’s pipelines are designed, constructed and operated to the highest industry standards and meet or exceed all regulatory requirements. Keystone is continuously monitored and is fully automated with remotely started secure pumps and valves. A variety of methods are used to detect and prevent leaks. In the unlikely event of a leak or spill, valves can be closed to isolate the leak and limit spill volumes.

The Company has established emergency response plans to be enacted in the unlikely event of a leak or spill along TransCanada’s operational crude oil pipeline. The plans encompass the necessary personnel and equipment to respond to any size of spill as well as clean-up and remediation operations to minimize any effects on the environment. The plan outlines specific environmental features in the vicinity of the pipeline and containment and remediation efforts are based on practices that are well-understood and tested. In addition, TransCanada has an on-going program to provide local emergency responders with the information and training necessary to ensure their preparedness for responding to events.

Changing Legislation and Regulations

The impact of new or proposed provincial, state and/or federal safety and environmental laws, regulations, guidelines and enforcement in Canada and the U.S. on TransCanada’s business is not yet certain. TransCanada makes assumptions about possible expenditures to safety and environmental matters based on current laws and regulations and interpretations thereof. If the laws or regulations or the interpretation thereof changes, the Company’s assumptions may change.  Incremental costs may or may not be recoverable under existing rate structures or commercial agreements. Proposed changes in environmental policy, legislation or regulation are routinely monitored by TransCanada, and where the risks are potentially large or uncertain, the Company works independently or through industry associations to comment on proposals.

In April 2010, the Environmental Protection Agency (“EPA”) published an “Advanced Notice of Proposed Rulemaking” to solicit comments with respect to EPA’s reassessment of current regulations under the Toxic Substances Control Act, governing

TRANSCANADA CORPORATION   19

the authorized use of polychlorinated biphenyls (“PCBs”) in certain equipment. The proposed changes could require notification to the EPA when PCBs are discovered in any pipeline system, a phase out and eventual elimination of PCB use in pipeline systems and air compressor systems and the immediate elimination of the storage of PCB equipment for reuse. If finalized as proposed, these changes are likely to have significant cost implications for the Company’s U.S. assets.

Regulation of air pollutant emissions under the U.S. Clean Air Act (“CAA”) and state regulations continue to evolve. A number of EPA initiatives could lead to impacts ranging from requirements to install emissions control equipment, to additional administrative and reporting requirements. At this time, there is insufficient detail to accurately determine the potential impacts of these initiatives. While the majority of the proposals are not expected to be material to TransCanada, the Company anticipates additional future costs related to the monitoring and control of air emissions.

In addition to those climate change policies already in force, there are also several federal (Canada and U.S.), regional and provincial initiatives currently in development. While recent political and economic events may significantly affect the scope and timing of new policies, TransCanada anticipates that most of the Company’s facilities in Canada and the U.S. are or will be subject to federal and/or regional climate change regulations to manage industrial GHG emissions. Certain of these initiatives are outlined below.

The Canadian government has continued to express interest in pursuing a harmonized continental climate change strategy. In January 2010, Environment Canada submitted a revised GHG reduction target to the United Nations Framework Convention on Climate Change as part of its submission for the Copenhagen Accord. The revised target represents a 17 per cent reduction in GHG emissions by 2020 relative to 2005 levels. In June 2010, the Federal government initiated consultation on its policy for coal-fired power operations with the stated intention of publishing the draft regulatory framework in Canada Gazette in early 2011. TransCanada participated in this consultation process directly through meetings with government officials and through the Canadian Electricity Association. The new regulations to reduce GHG emissions for coal-fired operations are expected to come into effect in July 2015.

In the U.S., the EPA is proceeding towards regulating industrial GHG emissions under the CAA. In May 2010, the EPA issued its final version of the Tailoring Rule which outlines emissions thresholds and a schedule for phasing in certain permitting requirements under the CAA. Under this rule, the Prevention of Significant Deterioration program stipulates the air pollution protection criteria a company must meet to obtain a construction permit. Requirements will apply to GHG emissions starting in January 2011. The second phase of the program will commence in July 2011, with new rulemaking in 2012 to establish emission thresholds and permitting requirements to take effect in 2013. In addition to the Prevention of Significant Deterioration requirements, the Tailoring Rule sets comparable emissions thresholds and timetables for new and existing facilities to obtain operating permits under Title V of the CAA. The regulation of GHG emissions by the EPA under the CAA would have implications for TransCanada with respect to permitting for existing, new and modified facilities.

The Western Climate Initiative (“WCI”) continues to work toward implementing a regional cap-and-trade program expected to come into effect in 2012. The cap-and-trade program would be a key component of the plan to help WCI members reach their goal of reducing GHG emissions 15 per cent below 2005 by 2020. Beginning in 2012, the cap would cover utilities and large industrial sectors, and expand by 2015 to cover transportation fuels, and commercial and residential fuels. The WCI comprises seven Western states and four Canadian provinces. While TransCanada has assets located in all four Canadian member provinces (B.C., Manitoba, Ontario and Québec) and five of the member states (California, Oregon, Washington, Montana and Arizona), the cap-and-trade program is proposed to begin in 2012 in California and the Canadian provinces of B.C., Québec, and Ontario. The programs would cover TransCanada’s pipeline and power facilities, however, TransCanada expects the cost of compliance would be largely recoverable on the facilities that trigger emissions thresholds.

TransCanada 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.

With respect to business opportunities, the Company has well established processes and criteria for assessing new business opportunities including those that may arise as a result of climate change policies. These processes have been and continue to be key contributors to TransCanada’s financial strength and success. Governments in North America are developing long-term plans for limiting GHG emissions. These plans, combined with a shift in consumer attitude and demand for low-emissions fuels, will require changes in energy supply and infrastructure. With the Company’s experience in pipeline transmission and power generation, TransCanada is well-positioned to participate in these opportunities.

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With respect to physical risks arising from climate change, TransCanada has in place a set of procedures to manage its response to natural disasters such as forest fires, tornadoes, earthquakes, floods, volcanic eruptions and hurricanes regardless of cause. These procedures are included in TransCanada’s Operating Procedures and are part of the Company’s Incident Management System. The procedures ensure that the health and safety of the Company’s employees and the environment are not compromised during natural disasters.

TransCanada’s assets are located throughout North America and the Company’s facility design must deal with different geographical areas. In northern regions, changing permafrost levels due to warmer temperatures have been experienced, however, very few kilometers of TransCanada’s pipeline systems are currently in permafrost regions. If TransCanada builds new facilities in northern areas, the Company’s facility designs will take into account the potential for changing permafrost levels.

Other Risk Factors

A discussion of the Company’s risk factors can be found in the MD&A under the headings “Natural Gas Pipelines – Opportunities and Developments”, “Natural Gas Pipelines – Business Risks”, “Natural Gas Pipelines – Outlook”, “Oil Pipelines – Opportunities and Developments”, “Oil Pipelines – Business Risks”, “Oil Pipelines – Outlook”, “Energy – Opportunities and Developments”, “Energy – Business Risks”, “Energy – Outlook” and “Risk Management and Financial Instruments”.

DIVIDENDS

The Board has not adopted a formal dividend policy. The Board reviews the financial performance of TransCanada quarterly and makes a determination of the appropriate level of dividends to be declared in the following quarter. Currently, TransCanada’s payment of dividends is primarily funded from dividends TransCanada receives as the sole common shareholder of TCPL. Provisions of various trust indentures and credit arrangements to which TCPL is a party restrict TCPL’s ability to declare and pay dividends to TransCanada under certain circumstances and, if such restrictions apply, they may, in turn, have an impact on TransCanada’s ability to declare and pay dividends. In the opinion of TransCanada’s management, such provisions do not currently restrict or alter TransCanada’s ability to declare or pay dividends.

Holders of cumulative redeemable first preferred shares, series 1 (“Series 1 Preferred Shares”) are entitled to receive fixed cumulative dividends, at an annual rate of $1.15 per share, payable quarterly, as and when declared by the Board, for the initial five year period ending December 31, 2014. For the period from issuance on September 30, 2009 to December 31, 2009, dividends in the amount of $0.2899 per share were declared and paid on the Series 1 Preferred Shares. For the period January 1, 2010 to December 31, 2010, dividends in the amount of $1.15 per share were declared and paid on the Series 1 Preferred Shares. The dividend on the Series 1 Preferred Shares will reset on December 31, 2014 and every five years thereafter to a rate equal to the sum of the then five year Government of Canada bond yield and 1.92 per cent.  The holders of Series 1 Preferred Shares have the right to convert their shares into cumulative redeemable first preferred shares, series 2 (the “Series 2 Preferred Shares”) as set out under the heading “First Preferred Shares” below.

Holders of cumulative redeemable first preferred shares, series 3 (“Series 3 Preferred Shares”) are entitled to receive fixed cumulative dividends, at an annual rate of $1.00 per share, payable quarterly, as and when declared by the Board, for the initial five year period ending June 30, 2015. For the period from issuance on March 12, 2010 to December 31, 2010, dividends in the amount of $0.8041 per share were declared and paid on the Series 3 Preferred Shares. The dividend on the Series 3 Preferred Shares will reset on June 30, 2015 and every five years thereafter to a rate equal to the sum of the then five year Government of Canada bond yield and 1.28 per cent.  The holders of Series 3 Preferred Shares have the right to convert their shares into cumulative redeemable first preferred shares, series 4 (the “Series 4 Preferred Shares”) as set out under the heading “First Preferred Shares” below.

Holders of cumulative redeemable first preferred shares, series 5 (“Series 5 Preferred Shares”) are entitled to receive fixed cumulative dividends, at an annual rate of $1.10 per share, payable quarterly, as and when declared by the Board, for the initial five and a half year period ending January 30, 2016. For the period from issuance on June 29, 2010 to December 31, 2010, dividends in the amount of $0.6457 per share were declared and dividends in the amount of $0.3707 per share were paid, on the Series 5 Preferred Shares. The dividend on the Series 5 Preferred Shares will reset on January 30, 2016 and every five years thereafter to a rate equal to the sum of the then five year Government of Canada bond yield and 1.54 per cent.  The holders of Series 5 Preferred Shares have the right to convert their shares into cumulative redeemable first preferred shares, series 6 (the “Series 6 Preferred Shares”) as set out under the heading “First Preferred Shares” below.

The dividends declared per Common Share of TransCanada during the past three completed financial years are set forth in the following table:

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	2010	2009	2008
Dividends declared on Common Shares	$1.60	$1.52	$1.44

DESCRIPTION OF CAPITAL STRUCTURE

Share Capital

TransCanada’s authorized share capital consists of an unlimited number of Common Shares, of which 696,229,462 were issued and outstanding at Year End, and an unlimited number of first preferred shares and second preferred shares, issuable in series, of which 22 million Series 1 Preferred Shares, 14 million Series 3 Preferred Shares and 14 million Series 5 Preferred Shares are issued and outstanding. The following is a description of the material characteristics of each of these classes of shares.

Common Shares

The Common Shares entitle the holders thereof to one vote per share at all meetings of shareholders, except meetings at which only holders of another specified class of shares are entitled to vote, and, subject to the rights, privileges, restrictions and conditions attaching to the first preferred shares and the second preferred shares, whether as a class or a series, and to any other class or series of shares of TransCanada which rank prior to the Common Shares, entitle the holders thereof to receive (i) dividends if, as and when declared by the Board out of the assets of TransCanada properly applicable to the payment of the dividends in such amount and payable at such times and at such place or places as the Board may from time to time determine and (ii) the remaining property of TransCanada upon a dissolution.

TransCanada has a Shareholder Rights Plan (the “SR Plan”) that is designed to ensure, to the extent possible, that all shareholders of TransCanada are treated fairly in connection with any take-over bid for the Company. The SR Plan creates a right attaching to each Common Share outstanding and to each Common Share subsequently issued. Each right becomes exercisable ten trading days after a person has acquired, or commences a take-over bid to acquire, 20 per cent or more of the Common Shares, other than by an acquisition pursuant to a take-over bid permitted under the terms of the SR Plan. Prior to a flip-in event (as described below), each right permits registered holders to purchase from the Company Common Shares of TransCanada at the exercise price equal to three times the market price of such shares, subject to adjustments and anti-dilution provisions (the “Exercise Price”). The beneficial acquisition by any person of 20 percent or more of the Common Shares, other than by way of a take-over bid permitted under the terms of the SR Plan, is referred to as a “Flip-in Event”. Ten trading days after a Flip-in Event, each TransCanada right will permit registered holders to receive, upon payment of the exercise price, the number of Common Shares with an aggregate market price equal to twice the exercise price. The SR Plan was reconfirmed at the 2010 annual and special meeting of shareholders and must be reconfirmed every third annual meeting thereafter.

TransCanada has a Dividend Reinvestment and Share Purchase Plan which permits common and preferred shareholders of TransCanada and preferred shareholders of TCPL, to elect to reinvest their cash dividends in additional Common Shares of TransCanada. These Common Shares may be provided to the participants at a discount to the average market price in the five days before dividend payment. The discount was set at three per cent in 2009 and 2010, and was reduced to two per cent commencing with the dividends declared in February 2011. The discount was set at two per cent for 2008 and was increased to three per cent commencing with the dividend declared in February 2009. Participants may also make additional cash payments of up to $10,000 per quarter to purchase additional Common Shares, which optional purchases are not eligible for any discount on the price of Common Shares. Participants are not responsible for payment of brokerage commissions or other transaction expenses for purchases made pursuant to the Dividend Reinvestment and Share Purchase Plan.

TransCanada also has stock-based compensation plans (the “SOPs”) that allow some employees to purchase Common Shares of TransCanada. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. Options granted under the SOPs are generally fully exercisable after three years and expire seven years after the date of grant.

First Preferred Shares

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, the provisions described below.

The first preferred shares of each series rank on a parity with the first preferred shares of every other series, and are entitled to preference over the Common Shares, the second preferred shares and any other shares ranking junior to the first preferred shares

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with respect to the payment of dividends, the repayment of capital and the distribution of assets of TransCanada in the event of a liquidation, dissolution or winding up of TransCanada.

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

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

The Series 1 Preferred Shares are entitled to the payment of dividends as set out above under the heading “Dividends”. The Series 1 Preferred Shares are redeemable by TransCanada in whole or in part on or after December 31, 2014, by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon. The holders of Series 1 Preferred Shares have the right to convert their shares into cumulative redeemable Series 2 Preferred Shares, subject to certain conditions, on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 2 Preferred Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the Board, at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 1.92 per cent. In the event of liquidation, dissolution or winding up of TransCanada, the holders of Series 1 Preferred Shares shall be entitled to receive $25.00 per Series 1 Preferred Share plus all accrued and unpaid dividends thereon in preference over the Common Shares or any other shares ranking junior to the Series 1 Preferred Shares.

The Series 3 Preferred Shares are entitled to the payment of dividends as set out above under the heading “Dividends”. The rights, privileges, restrictions and conditions attaching to the Series 3 Preferred Shares are substantially identical to those attaching to the first preferred shares, except as outlined below. The Series 3 Preferred Shares are redeemable by TransCanada in whole or in part on or after June 30, 2015, by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon. The holders of Series 3 Preferred Shares have the right to convert their shares into cumulative redeemable Series 4 Preferred Shares, subject to certain conditions, on June 30, 2015 and on June 30 of every fifth year thereafter. The holders of Series 4 Preferred Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the Board, at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 1.28 per cent. In the event of liquidation, dissolution or winding up of TransCanada, the holders of Series 3 Preferred Shares shall be entitled to receive $25.00 per Series 3 Preferred Share plus all accrued and unpaid dividends thereon in preference over the Common Shares or any other shares ranking junior to the Series 3 Preferred Shares.

The Series 5 Preferred Shares are entitled to the payment of dividends as set out above under the heading “Dividends”. The rights, privileges, restrictions and conditions attaching to the Series 5 Preferred Shares are substantially identical to those attaching to the first preferred shares, except as outlined below. The Series 5 Preferred Shares are redeemable by TransCanada in whole or in part on or after January 30, 2016, by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon. The holders of Series 5 Preferred Shares have the right to convert their shares into cumulative redeemable Series 6 Preferred Shares, subject to certain conditions, on January 30, 2016 and on January 30 of every fifth year thereafter. The holders of Series 6 Preferred Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the Board, at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 1.54 per cent. In the event of liquidation, dissolution or winding up of TransCanada, the holders of Series 5 Preferred Shares shall be entitled to receive $25.00 per Series 5 Preferred Share plus all accrued and unpaid dividends thereon in preference over the Common Shares or any other shares ranking junior to the Series 5 Preferred Shares.

Except as provided by the CBCA, the respective holders of the Series 1, 2, 3, 4, 5 and 6 Preferred Shares are not entitled to receive notice of, attend at, or vote at any meeting of shareholders unless and until TransCanada shall have failed to pay eight quarterly dividends, whether or not consecutive, in which case the respective holders of Series 1, 2, 3, 4, 5 and 6 Preferred Shares shall have the right to receive notice of and to attend each meeting of shareholders at which directors are to be elected and which take place more than 60 days after the date on which the failure first occurs, and to one vote with respect to resolutions to elect directors for each Series 1, 2, 3, 4, 5 and 6 Preferred Share, respectively, until all arrears of dividends have been paid.

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Second Preferred Shares

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

CREDIT RATINGS

Although TransCanada has not issued debt to the public, it has been assigned credit ratings by Moody’s Investors Service, Inc. (“Moody’s”) and Standard and Poor’s (“S&P”). Moody’s has assigned an issuer rating of Baa1 with a stable outlook and S&P has assigned a long-term corporate credit rating of A- with a stable outlook  TransCanada does not presently intend to issue debt securities to the public in its own name and any future debt financing requirements are expected to continue to be funded primarily through its subsidiary, TCPL. The following table sets out the current credit ratings assigned to those outstanding classes of securities of TCPL which have been rated by DBRS Limited (“DBRS”), Moody’s and 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	P-2
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.

The following information concerning the Company’s credit ratings relates to the Company’s financing costs, liquidity and operations. The availability of TransCanada’s funding options may be affected by certain factors, including the global capital market environment and outlook as well as the Company’s financial performance. TransCanada’s access to capital markets at competitive rates is dependent on its credit rating and rating outlook, as determined by credit rating agencies such as DBRS, Moody’s and S&P, and if TransCanada’s ratings were downgraded the Company’s financing costs and future debt issuances could be unfavorably impacted. A description of the rating agencies’ credit ratings listed in the table above is set out below.

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 all rating categories other than AAA and D. 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 in the third highest of ten rating categories and indicates good credit quality. The overall strength is not as favourable as higher rating categories, but any qualifying negative factors that exist are considered manageable. The A rating assigned to TCPL’s senior unsecured debt is in the third highest of ten categories for long-term debt. Long-term debt rated A is good credit quality. The capacity for the payment of interest and principal is substantial, but the degree of strength is less than that of AA rated securities. The BBB (high) rating assigned to junior subordinated notes is in the fourth highest of the ten categories for long-term debt. Long-term debt rated BBB is of adequate credit quality. The capacity for the payment of interest and principal is considered acceptable, but it may be vulnerable to future events. The Pfd-2 (low) rating assigned to TCPL’s and TransCanada’s preferred shares is in 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. In general, Pfd-2 ratings correspond with long-term debt rated in the A category.

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 from Aa through Caa, with 1 being the highest and 3 being the lowest. The A3 rating assigned to TCPL’s senior unsecured debt is in the third highest of nine rating categories for long-term obligations. Obligations rated A are

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considered upper medium grade and are subject to low credit risk. The Baa1 and Baa2 ratings assigned to TCPL’s junior subordinated debt and preferred shares, respectively, are in the fourth 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 from AA through CCC 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 in 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 and P-2  ratings assigned to TCPL’s junior subordinated notes and TCPL’s and TransCanada’s preferred shares exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation.

MARKET FOR SECURITIES

TransCanada’s Common Shares are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange (“NYSE”) under the symbol “TRP”. TransCanada’s Series 1 Preferred Shares, Series 3 Preferred Shares and Series 5 Preferred Shares have been listed for trading on the TSX since September 30, 2009, March 12, 2010 and June 29, 2010, respectively under the symbols “TRP.PR.A”, “TRP.PR.B”, and “TRP.PR.C”, respectively. The following tables set forth the reported monthly high, low, and month-end closing trading prices and monthly trading volumes of the Common Shares of TransCanada on the TSX and the NYSE, and the respective Series 1 Preferred Shares, Series 3 Preferred Shares and Series 5 Preferred Shares on the TSX, for the period indicated:

Common Shares

	TSX (TRP)				NYSE (TRP)
Month	High ($)	Low ($)	Close ($)	Volume Traded	High (US$)	Low (US$)	Close (US$)	Volume Traded
December 2010	38.71	36.53	37.99	36,564,145	38.44	35.86	38.04	8,743,709
November 2010	38.04	35.49	36.20	47,122,180	37.72	34.77	35.33	8,000,248
October 2010	39.28	37.06	37.67	24,452,953	38.59	36.33	36.95	6,887,287
September 2010	38.88	37.25	38.17	35,287,579	37.75	36.00	37.12	5,548,775
August 2010	38.45	35.75	38.00	23,551,406	36.53	34.23	35.64	6,079,595
July 2010	37.25	35.50	36.33	30,315,925	35.85	32.86	35.35	8,077,360
June 2010	37.31	34.57	35.61	30,159,655	36.69	33.02	33.43	8,154,916
May 2010	36.92	30.01	35.50	32,936,332	36.47	25.80	33.17	9,235,485
April 2010	38.16	35.18	35.84	30,450,870	38.01	34.92	35.20	6,424,836
March 2010	37.87	34.75	37.22	42,951,844	37.11	33.20	36.76	5,806,751
February 2010	35.30	33.96	34.78	25,627,521	33.68	31.58	33.00	5,669,857
January 2010	36.44	34.00	34.17	23,180,090	35.07	31.85	31.91	6,314,623

TRANSCANADA CORPORATION   25

Series 1 Preferred Shares

	TSX (TRP.PR.A)
Month	High ($)	Low ($)	Close ($)	Volume Traded
December 2010	26.00	25.50	26.00	559,051
November 2010	26.79	25.95	25.97	583,072
October 2010	26.45	26.13	26.29	528,964
September 2010	27.89	25.90	26.24	613,195
August 2010	26.11	25.80	26.00	623,916
July 2010	25.95	25.35	25.95	454,853
June 2010	25.90	25.15	25.45	552,510
May 2010	25.45	25.00	25.11	1,147,115
April 2010	25.85	25.06	25.25	619,658
March 2010	26.59	25.08	25.69	1,289,162
February 2010	26.29	25.80	25.95	727,716
January 2010	27.15	25.80	26.15	1,561,414

Series 3 Preferred Shares

	TSX (TRP.PR.B)
Month	High ($)	Low ($)	Close ($)	Volume Traded
December 2010	25.59	24.65	25.57	219,795
November 2010	25.98	24.85	24.98	342,225
October 2010	25.48	24.85	25.10	522,319
September 2010	25.66	24.95	25.36	431,061
August 2010	25.20	24.85	24.98	533,912
July 2010	25.00	24.60	24.94	291,835
June 2010	24.75	24.16	24.65	425,787
May 2010	24.84	23.99	24.20	458,273
April 2010	25.07	23.90	23.90	497,079
March 2010	25.08	24.83	25.02	1,817,221

Series 5 Preferred Shares

	TSX (TRP.PR.C)
Month	High ($)	Low ($)	Close ($)	Volume Traded
December 2010	26.26	25.00	25.81	351,359
November 2010	26.45	25.50	25.65	397,725
October 2010	26.17	25.36	25.56	499,857
September 2010	26.50	25.28	25.69	597,352
August 2010	25.82	25.20	25.70	613,671
July 2010	25.41	24.84	25.30	1,084,450
June 2010	24.98	24.75	24.95	944,707

In addition, TransCanada’s subsidiary, TCPL, has cumulative redeemable first preferred shares, series U and series Y listed on the TSX under the symbols “TCA.PR.X”, and “TCA.PR.Y”, respectively.

DIRECTORS AND OFFICERS

As of February 14, 2011, the directors and officers of TransCanada as a group beneficially owned, or exercised control or direction, directly or indirectly, over an aggregate of 517,667, Common Shares of TransCanada. This constitutes less than one per cent of TransCanada’s Common Shares. TransCanada collects this information from its directors and officers but otherwise has no direct knowledge of individual holdings of its securities.

Directors

Set forth below are the names of the thirteen directors who served on the Board at Year End, together with their jurisdictions of residence, all positions and offices held by them with TransCanada and its significant affiliates, their principal occupations or

26

employment during the past five years and the year from which each director has continually served as a director of TransCanada and, prior to the arrangement, with TCPL. Positions and offices held with TransCanada are also held by such person at TCPL. Each director holds office until the next annual meeting 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 DeWinton, Alberta Canada	President and Chief Executive Officer, Laidlaw International, Inc. (transportation services) from June 2003 to October 2007. Director, Emergency Medical Services Corporation.	2005
Derek H. Burney(1), O.C. Ottawa, Ontario Canada	Senior strategic advisor at Ogilvy Renault LLP (law firm). Chair (not a Director), International Advisory Board for Garda World Consulting & Investigation, a division of Garda World Security Corporation since 2008. Chair, Canwest Global Communications Corp. (communications) from August 2006 (director since April 2005) to October 2010 and Lead Director at Shell Canada Limited (oil and gas) from April 2001 to May 2007.	2005
Wendy K. Dobson Uxbridge, Ontario Canada	Professor, Rotman School of Management. Director, Institute for International Business, University of Toronto and Director, the Toronto-Dominion Bank. Vice Chair, Canadian Public Accountability Board until February 2010 and Chair of the Audit Committee of the same organization from 2003 to 2009.	1992
E. Linn Draper Lampasas, Texas U.S.	Director, Alliance Data Systems Corporation (data processing and services) and Director, Alpha Natural Resources, Inc. (mining). Chair, NorthWestern Corporation (conducting business as NorthWestern Energy) (oil and gas). Lead Director, Temple-Inland Inc. (materials).	2005
The Hon. Paule Gauthier, P.C., O.C., O.Q., Q.C. Québec, Québec Canada	Senior Partner, Stein Monast LLP (law firm). Director, Metro Inc., RBC Dexia Investor Services Trust, Royal Bank of Canada and Care Canada. Director, Institut Québecois des Hautes Études Internationales, Laval University from 2002 until 2009.	2002
Russell K. Girling Calgary, Alberta Canada	President and Chief Executive Officer, TransCanada since July 1, 2010. Chief Operating Officer from July 2009 to June 30, 2010 and President, Pipelines from June 2006 to June 30, 2010. Prior to June 2006, Chief Financial Officer and Executive Vice-President, Corporate Development. Director, Agrium Inc.	2010
Kerry L. Hawkins Winnipeg, Manitoba Canada	Director, NOVA Chemicals Corporation until July 2009. President, Cargill Limited (agricultural) from September 1982 to December 2005.	1996
S. Barry Jackson Calgary, Alberta Canada	Chair of the Board, TransCanada since April 2005. Director, Nexen Inc. (oil and gas) and Director, WestJet Airlines Ltd. Chair, Resolute Energy Inc. (oil and gas) from January 2002 to April 2005. Chair of Deer Creek Energy Limited (oil and gas) from April 2001 to September 2005.	2002
Paul L. Joskow New York, New York U.S.	Economist and President of the Alfred P. Sloan Foundation. Professor of Economics, Emeritus, 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, Exelon Corporation (energy), and a trustee of Putnam Mutual Funds.	2004
John A. MacNaughton(2), C.M. Toronto, Ontario Canada	Chair of the Business Development Bank of Canada. Chair, CNSX Markets Inc. (formerly the Canadian Trading and Quotation System Inc.) (stock exchange) from 2006 to July 2010. Director, Nortel Networks Corporation and Nortel Networks Limited (the principal operating subsidiary of Nortel Networks Corporation) (technology) from 2005 to September 2010. Chair of the Independent Nominating Committee of the Canada Employment Insurance Financing Board since 2008. Founding President and Chief Executive Officer of the Canada Pension Plan Investment Board from 1999 to 2005.	2006

TRANSCANADA CORPORATION   27

Name and Place of Residence	Principal Occupation During the Five Preceding Years	Director Since
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, and Enerplus Corporation. Member of the Science, Technology and Innovation Council of Canada.	2001
W. Thomas Stephens Greenwood Village, Colorado U.S.	Chair and Chief Executive Officer of Boise Cascade, LLC from November 2004 to November 2008. Director, Boise Inc. until April 2010. Trustee, Putnam Mutual Funds.	2007(4)
D. Michael G. Stewart Calgary, Alberta Canada	Director, Canadian Energy Services & Technology Corp. (previously Canadian Energy Services LP (Director, Canadian Energy Services Inc., the GP)), Pengrowth Energy Corporation (previously Pengrowth Corporation (the administrator of Pengrowth Energy Trust)) and C&C Energia Ltd. Director, Orleans Energy Ltd. from October 2008 to December 2010. Chairman and a trustee of Esprit Energy Trust (oil and gas) from August 2004 to October 2006. Director, 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)Canwest Global Communications Corp. (“Canwest”) voluntarily entered into, and successfully obtained an Order from the Ontario Superior Court of Justice (Commercial Division) commencing proceedings under the Companies’ Creditors Arrangement Act (“CCAA”) on October 6, 2009. Although no cease trade orders were issued, following the filing Canwest shares were de-listed from trading on the TSX and now trade on the TSX Venture Exchange. Canwest emerged from CCAA protection and its newspaper business was acquired by Postmedia Network on July 13, 2010 and its broadcast media business was acquired by Shaw Communications Inc. on October 27, 2010.  Mr. Burney ceased to be a director of Canwest on October 27, 2010.

(2)Nortel Networks Limited is the principal operating subsidiary of Nortel Networks Corporation (collectively referred to as “Nortel”). 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. On January 14, 2009, Nortel, and certain of Nortel’s other Canadian subsidiaries filed for creditor protection under the CCAA.

(3)Air Canada filed for protection under the CCAA and applicable bankruptcy protection statutes in the U.S. in April 2003. Mr. O’Brien resigned as a director of Air Canada on November 26, 2003.

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

Board Committees

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

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

The charters of the Audit Committee, Governance Committee, the Health, Safety and 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”.

Further information about the Board committees and corporate governance can also be found on TransCanada’s website.

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Officers

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

Executive Officers

Name	Present Position Held	Principal Occupation During the Five Preceding Years
Russell K. Girling	President and Chief Executive Officer	Prior to July 2010, Chief Operating Officer since July 2009 and President, Pipelines since June 2006. Prior to June 2006, Executive Vice-President, Corporate Development, since March 2003 and Chief Financial Officer, since August 1999.
Gregory A. Lohnes	Executive Vice-President and President, Natural Gas Pipelines	Prior to July 2010, Executive Vice-President and Chief Financial Officer. Prior to June 2006, President and Chief Executive Officer of Great Lakes Gas Transmission Company, since August 2000.
Donald R. Marchand	Executive Vice-President and Chief Financial Officer	Prior to July 2010, Vice-President, Finance and Treasurer, since September 1999.
Dennis J. McConaghy	Executive Vice-President, Corporate Development	Prior to July 2010, Executive Vice-President, Pipeline Strategy and Development. Prior to June 2006, Executive Vice-President, Gas Development, since May 2001.
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 2006. Prior to June 2006, Vice-President, Transactions, Power Division, TCPL, since April 2003.
Alexander J. Pourbaix	President, Energy and Oil Pipelines	President, Energy from June 2006 to June 2010 and Executive Vice-President, Corporate Development from July 2009 to June 2010. Prior to June 2006, Executive Vice-President, Power, since March 2003.
Sarah E. Raiss	Executive Vice-President, Corporate Services	Executive Vice-President, Corporate Services, since January 2002.
Donald M. Wishart	Executive Vice-President, Operations and Major Projects	Prior to July 2009, Executive Vice-President, Operations and Engineering, since March 2003.

Corporate Officers

Name	Present Position Held	Principal Occupation During the Five Preceding Years
Sean M. Brett	Vice-President and Treasurer	Prior to July 2010, Vice-President, Commercial Operations of TC Pipelines GP, Inc., and Director, LP Operations of TCPL. Prior to November 2009, Director, Joint Venture Management, Keystone Pipeline Project of TCPL. Prior to December 2008, Vice-President and Treasurer of TC Pipelines GP, Inc. Prior to January 2007, Mr. Brett held a number of positions of increasing responsibility with TransCanada’s Finance and Treasury Group.
Ronald L. Cook	Vice-President, Taxation	Vice-President, Taxation, since April 2002.
Donald J. DeGrandis	Vice-President and Corporate Secretary	Prior to February 2009, Corporate Secretary. Prior to June 2006, Associate General Counsel, Corporate Services, since June 2004.

TRANSCANADA CORPORATION   29

Lee G. Hobbs	President, U.S. Natural Gas Pipelines	Senior Vice-President and General Manager, U.S. Pipelines, Pipelines Division, TCPL, June 2009 to July 2010. Vice-President and General Manager, U.S. Pipelines Central, Pipelines Division, TCPL, March 2007 to June 2009. President, Great Lakes Gas Transmission Company and Great Lakes Gas Transmission Limited Partnership, September 2006 to March 2007. Prior to September 2006, Vice-President and Controller, TCPL, since July 2001.
Joel E. Hunter	Vice-President, Finance	Director, Corporate Finance, January 2008 to July 2010. Prior to January 2008, Senior Analyst, Corporate Finance. Prior to January 2007 Mr. Hunter held a number of positions of increasing responsibility with TransCanada’s Finance and Treasury Group.
Garry E. Lamb	Vice-President, Risk Management	Vice-President, Risk Management, since October 2001.
G. Glenn Menuz	Vice-President and Controller	Prior to June 2006, Assistant Controller, since October 2001.

Conflicts of Interest

Directors and officers of TransCanada and its subsidiaries are required to disclose the existence of existing or potential conflicts in accordance with TransCanada policies governing directors and officers and in accordance with the CBCA. Although some of the directors sit on boards or may be otherwise associated with companies that ship natural gas on TransCanada’s pipeline systems, TransCanada, 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, TransCanada 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 generally absents himself or herself from the meeting during the consideration of the matter, and does not vote on the matter.

CORPORATE GOVERNANCE

The Board and the members of TransCanada’s management are committed to the highest standards of corporate governance. TransCanada’s corporate governance practices comply with the governance rules of the CSA, those of the NYSE and of the SEC applicable to foreign issuers. As a non-U.S. company, TransCanada 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. TransCanada is in compliance with the CSA’s National Instrument 52-110, Audit Committees; National Policy 58-201, Corporate Governance Guidelines; and National Instrument 58-101, Disclosure of Corporate Governance Practices. Further information about TransCanada’s corporate governance can be found on TransCanada’s website at www.transcanada.com under the heading “Corporate Governance” or at Schedule “B” to TransCanada’s Management Proxy Circular dated February 14, 2011.

AUDIT COMMITTEE

TransCanada has an Audit Committee which is responsible for assisting the Board in overseeing the integrity of TransCanada’s financial statements and compliance with legal and regulatory requirements and in ensuring the independence and performance of TransCanada’s internal and external auditors. The 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, E. Linn Draper, 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

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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 TransCanada, of each member of the Audit Committee that is relevant to the performance of his 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 The Insurance Corporation of British Columbia and has served on other public company boards and on the audit committees of certain of those 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 Chair and Chief Executive Officer of Bell Canada International Inc. Mr. Burney was the lead director at Shell Canada Limited until May 2007 and was the Chair of Canwest Global Communications Corp. until October 2010. He has served on one other organization’s audit committee.

E. Linn Draper

Dr. Draper holds a Bachelor of Science in Chemical Engineering from Rice University and a Ph.D. in Nuclear Science and Engineering from Cornell University. Dr. Draper was Chair, President and Chief Executive Officer of American Electric Power Co., Inc. until 2004. He previously served as Chair, President and Chief Executive Officer of Gulf States Utilities Company. Dr. Draper has served and continues to serve on several other public company boards.

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 a Ph.D. in Economics from Yale University. He is currently the President of the Alfred P. Sloan Foundation and a Professor of Economics, Emeritus, at 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 Chair of the Business Development Bank of Canada, and was Chair of CNSX Markets Inc. (formerly Canadian Trading and Quotation System Inc.) until July 2010. 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 has served on the audit committee of other public companies.

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 37 years.

Pre-Approval Policies and Procedures

TransCanada’s Audit Committee has adopted a pre-approval policy with respect to permitted non-audit services. Under the policy, the Audit Committee has granted pre-approval for specified non-audit services. 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

TRANSCANADA CORPORATION   31

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, TransCanada 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 2010 and 2009 fiscal years.

Fee Category	2010	2009	Description of Fee Category
	(millions of dollars)
Audit Fees	$6.5	$7.2	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	$0.2	$0.2	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 Company pension plans.
Tax Fees	$1.0	$1.1	Aggregate fees rendered for tax planning and tax compliance advice. The nature of these services consisted of domestic and international tax planning advice and tax compliance matters including the review of income tax returns and other tax filings.
All Other Fees	$0.2	$0.4	Aggregate fees for products and services other than those reported elsewhere in this table. The nature of these services primarily consisted of advice and training primarily related to IFRS.
Total	$7.9	$8.9

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

TransCanada and its subsidiaries are subject to various 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 TransCanada’s favour, it is the opinion of TransCanada’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.

TRANSFER AGENT AND REGISTRAR

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

INTEREST OF EXPERTS

TransCanada’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 TransCanada may be found under TransCanada’s profile on SEDAR at www.sedar.com.

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

32

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

TRANSCANADA CORPORATION   33

GLOSSARY

AcSB	Accounting Standards Board
AGIA	Alaska Gasline Inducement Act
AIF	Annual Information Form of TransCanada Corporation dated February 14, 2011
Alaska Pipeline	A proposed natural gas pipeline extending from Prudhoe Bay, Alaska to either Alberta or Valdez, Alaska
Alberta System	A natural gas transmission system in Alberta and Northeast B.C.
ANR	American Natural Resources Company and ANR Storage Company, collectively
ANR System	A natural gas transmission system extending from producing fields located primarily in Texas, Oklahoma, the Gulf of Mexico and U.S. Midcontinent region to markets located primarily in Wisconsin, Michigan, Illinois, Ohio and Indiana, and regulated underground natural gas storage facilities in Michigan
AUC	Alberta Utilities Commission
Bakken Marketlink	A proposed pipeline that would transport crude oil from Baker, Montana to Cushing on facilities that form part of the U.S. Gulf Coast Expansion
Bbl/d	Barrels per day
B.C.	British Columbia
Bcf	Billion cubic feet
Bcf/d	Billion cubic feet per day
Bécancour	A natural gas-fired cogeneration plant near Trois-Rivières, Québec
Bison	A natural gas pipeline extending from the Powder River Basin in Wyoming to the NBPL System in North Dakota
Board	TransCanada’s Board of Directors
Bruce A	A partnership interest in a nuclear power generation facility consisting of Units 1 to 4 of Bruce Power (Bruce Power A L.P.)
Bruce B	A partnership interest in a nuclear power generation facility consisting of Units 5 to 8 of Bruce Power (Bruce Power L.P.)
Bruce Power	A nuclear power generating facility located northwest of Toronto, Ontario (Bruce A and Bruce B, collectively)
CAA	Clean Air Act
Canadian GAAP	Canadian generally accepted accounting principles
Canadian Mainline	A natural gas transmission system extending from the Alberta/Saskatchewan border east into Québec
Canwest	Canwest Global Communications Corp.
Cartier Wind	Five wind farms in Gaspé, Québec, three of which are operational and two under construction
CBCA	Canada Business Corporations Act
CCAA	Companies’ Creditors Arrangement Act
Chinook	A proposed power transmission line project originating in Montana and terminating in Nevada
CICA	Canadian Institute of Chartered Accountants
CO2	Carbon dioxide
Common Shares	Common shares of TransCanada
Coolidge	A simple-cycle, natural gas-fired peaking power generation station under construction in Coolidge, Arizona
CSA	Canadian Securities Administrators
Cushing Extension	The second phase of the Keystone oil pipeline delivering crude oil to Cushing, Oklahoma
Cushing Marketlink	A proposed pipeline that would provide crude oil from Cushing, Oklahoma to the U.S. Gulf Coast on facilities that form part of the U.S. Gulf Coast Expansion
DBRS	DBRS Limited
Energy	As defined in this AIF under the heading “General Development of the Business”
EPA	Environmental Protection Agency (U.S.)
Exercise Price	As defined in this AIF under the heading “Description of Capital Structure”
ExxonMobil	ExxonMobil Corporation
FERC	Federal Energy Regulatory Commission (U.S.)
Foothills System	A natural gas transmission system extending from central Alberta to the B.C./U.S. border and to the Saskatchewan/U.S. border
GHG	Greenhouse gas
Great Lakes	Great Lakes Gas Transmission Limited Partnership
Great Lakes System	A natural gas transmission system that connects to the Canadian Mainline and serves markets in Eastern Canada and the Northeastern and Midwestern U.S.
Groundbirch	A phase of the Alberta System, connecting natural gas supply primarily from the Montney shale gas formation in Northeast B.C. to existing infrastructure in Northwest Alberta
GTN System	A natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border, traversing Idaho, Washington and Oregon
Guadalajara	A natural gas pipeline under construction in Mexico extending from Manzanillo, Colima to Guadalajara, Jalisco
Halton Hills	A natural gas-fired, combined cycle power plant in Halton Hills, Ontario
Horn River	A proposed extension of the Alberta System that would connect new shale gas supply in the Horn River basin north of Fort Nelson, B.C.
HS&E	Health, safety and environment
HVDC	High voltage direct current
Hydro-Québec	Hydro-Québec Distribution
IASB	International Accounting Standards Board
IFRS	International Financial Reporting Standards
Iroquois System	A natural gas transmission system connects with the Canadian Mainline near Waddington, New York and delivers natural gas in the Northeastern U.S.
ISO	International Organization for Standardization
Keystone Canada	TransCanada Keystone Pipeline Limited Partnership

34

Keystone	Wood River/Patoka, the Cushing Extension and the U.S. Gulf Coast Expansion, collectively
Keystone U.S.	TransCanada Keystone Pipeline, LP
Kibby Wind	A wind farm located in Kibby and Skinner townships in northwestern Franklin County, Maine
km	Kilometer(s)
LNG	Liquefied Natural Gas
Mackenzie Gas Project	A proposed natural gas pipeline extending from a point near Inuvik, Northwest Territories to the northern border of Alberta
MD&A	TransCanada’s Management’s Discussion and Analysis dated February 14, 2011
MIT	Massachusetts Institute of Technology
MMcf/d	Million cubic feet per day
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatt(s)
Natural Gas Pipelines	As defined in this AIF under the heading “General Development of the Business”
NBPL	Northern Border Pipeline Company
NBPL System	A natural gas transmission system extending from a point near Monchy, Saskatchewan to the U.S. Midwest
NEB	National Energy Board
Nortel	Nortel Networks Limited and Nortel Networks Corporation
North Baja System	A natural gas transmission system extending from Arizona to the Baja California, Mexico/California border
North Central Corridor	A phase of the Alberta System which extends the northern section thereof
NYSE	New York Stock Exchange
Ocean State Power	A natural gas-fired, combined-cycle plant in Burrillville, Rhode Island
Oil Pipelines	As defined in this AIF under the heading “General Development of the Business”
OPA	Ontario Power Authority
OSC	Ontario Securities Commission
PCBs	Polychlorinated biphenyls
Portland System	A natural gas transmission system that extends from a point near East Hereford, Québec to the Northeastern U.S.
Portlands Energy	A natural gas-fired combined-cycle power plant near downtown Toronto, Ontario
Ravenswood	A natural gas-and oil-fired generating facility located in Queens, New York
RGGI	Regional Greenhouse Gas Initiative
RRA	Rate-regulated accounting
S&P	Standard and Poor’s
SEC	U.S. Securities and Exchange Commission
Series 1 Preferred Shares	TransCanada’s cumulative, redeemable, first preferred shares, series 1
Series 2 Preferred Shares	TransCanada’s cumulative, redeemable, first preferred shares, series 2
Series 3 Preferred Shares	TransCanada’s cumulative, redeemable, first preferred shares, series 3
Series 4 Preferred Shares	TransCanada’s cumulative, redeemable, first preferred shares, series 4
Series 5 Preferred Shares	TransCanada’s cumulative, redeemable, first preferred shares, series 5
Series 6 Preferred Shares	TransCanada’s cumulative, redeemable, first preferred shares, series 6
Sheerness	A coal-fired power generating facility near Hanna, Alberta
SOPs	TransCanada’s stock-based compensation plans
SR Plan	TransCanada’s Shareholder Rights Plan
Subsidiary	As defined in this AIF under the heading “Presentation of Information”
Sundance	Two coal-fired power generating facilities near Wabamun, Alberta (Sundance A and Sundance B, collectively)
Systems	As defined in this AIF under the heading “Regulation of the Pipeline Business”
TCPL	TransCanada PipeLines Limited
TQM	A natural gas pipeline that connects with the Canadian Mainline near the Québec/Ontario border and transports natural gas to markets in Québec, and connects with the Portland System
TransCanada or the Company	TransCanada Corporation
TransAlta	TransAlta Corporation
TSX	Toronto Stock Exchange
Tuscarora	Tuscarora Gas Transmission Company
Tuscarora System	A natural gas transmission system extending from Malin, Oregon to Wadsworth, Nevada
U.S. or US	United States
U.S. GAAP	U.S. generally accepted accounting principles
U.S. Gulf Coast Expansion	A proposed extension and expansion of the Keystone crude oil pipeline to the U.S. Gulf Coast
WCI	Western Climate Initiative
Wood River/Patoka	The first phase of the Keystone oil pipeline delivering crude oil to Wood River and Patoka in Illinois
Year End	December 31, 2010
Zephyr	A proposed power transmission line project originating in Wyoming and terminating in Nevada

TRANSCANADA CORPORATION     A-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 Celsiussubtract 32 degrees, then divide by 1.8

*       The conversion is based on natural gas at a base pressure of 101.325 kilopascals and at a base temperature of 15 degrees Celsius.

TRANSCANADA CORPORATION     B-1

SCHEDULE “B”

CHARTER OF THE AUDIT COMMITTEE

1.Purpose

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

·Company’s financial accounting and reporting process;

·integrity of the financial statements

·Company’s internal control over financial reporting;

·external financial audit process;

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

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

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

2.Roles and Responsibilities

I.Appointment of the Company’s External Auditors

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

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

II.Oversight in Respect of Financial Disclosure

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

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

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

TRANSCANADA CORPORATION     B-2

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

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

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

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

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

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

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

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

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

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

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

III.Oversight in Respect of Legal and Regulatory Matters

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

IV.Oversight in Respect of Internal Audit

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

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

TRANSCANADA CORPORATION     B-3

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

(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;

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;

TRANSCANADA CORPORATION     B-4

(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 the implementation and amendments to policies and program initiatives deemed advisable by management or the Audit Committee with respect to the Company’s codes of business ethics and Risk Management and Financial Reporting policies;

(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;

TRANSCANADA CORPORATION     B-5

VIII.Oversight in Respect of Financial Aspects of the Company’s Canadian Pension Plans (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 in relation 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 the policy and 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).

TRANSCANADA CORPORATION     B-6

4.Appointment of Audit Committee Members

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

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)make suggestions and provide feedback from the Audit Committee to management regarding information that is or should be provided to the Audit Committee;

(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.

TRANSCANADA CORPORATION     B-7

13.Procedure, Records and Reporting

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

14.Review of Charter and Evaluation of Audit Committee

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

15.Outside Experts and Advisors

The Audit Committee is authorized, when deemed necessary or desirable, to retain 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.

2010 Annual Report Realizing our vision

Realizing our Vision In order to be successful, a company must have a vision. TransCanada’s remains committed to becoming North America’s leading energy infrastructure company. We focus on businesses that we know and understand - pipelines and power generation - in regions where we have an existing competitive advantage or can develop one. Large scale, long life assets are the priority - assets that provide attractive and sustainable returns over a number of decades. Over the past 10 years, TransCanada has made significant investments in high quality energy infrastructure assets, investments that have allowed the company to move forward in achieving its vision. Today, we play a significant role in the safe development and reliable operation of critical North American energy infrastructure. We are the largest natural gas transmission company in North America, the third largest natural gas storage company on the continent and the largest private sector power company in Canada. And TransCanada is poised to become a very significant player in the oil transmission business. TransCanada will be the leading energy infrastructure company in North America.

15 12 3 13 11 12 1 1 21 20 2 3 16 4 16 18 18 18 2 5 8 10 7 6 11 17 18 14 13 15 4 5 19 10 8 9 4 9 7 17 14 6 22 19 19 Natural Gas Pipeline Natural Gas Pipeline (Under Construction) Natural Gas Pipeline (In Development) Natural Gas Pipeline (Proposed) Oil Pipeline Oil Pipeline (In Development) Power Generation Facility Natural Gas Storage Facility

Pipelines Natural Gas Pipelines Alberta System Canadian Mainline Great Lakes (71.3%) ANR GTN Tuscarora (38.2%) North Baja (38.2%) Foothills Northern Border (19.1%) Bison TQM (50%) Portland (61.7%) Iroquois (44.5%) Tamazunchale Guadalajara (under construction) Alaska Pipeline Project (proposed) Mackenzie Gas Pipeline Project (proposed by producers) Oil Pipeline Keystone Keystone U.S. Gulf Coast Expansion (in development) Regulated Natural Gas Storage ANR Natural Gas Storage All assets wholly owned except as noted Energy Natural Gas Power Generation Bear Creek MacKay River Redwater Carseland Cancarb Portlands Energy (50%) Halton Hills Bécancour Grandview Ocean State Power Ravenswood Coolidge (under construction) Coal Power Purchase Arrangements Sundance A PPA Sundance B PPA (50%) Sheerness PPA Nuclear Power Generation Bruce Power (Bruce A – 48.8%, Bruce B – 31.6%) Wind Power Generation Cartier Wind (62%) 3 of 5 stages complete Kibby Wind Hydro Power Generation TC Hydro Unregulated Natural Gas Storage Edson CrossAlta (60%) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 1 2 3 10 13 7 8 9 11 14 12 15 16 17 18 20 4 5 6 19

Building for Growth We have a $47 billion asset base that includes 60,000 kilometres (37,000 miles) of natural gas pipelines that move 14 billion cubic feet a day (Bcf/d) across North America - 20 per cent of the natural gas consumed each day. We have 19 power plants that produce 10,800 megawatts (MW) of electricity – enough to meet the needs of nearly 11 million homes. Our energy portfolio is very diverse, producing power from sources such as natural gas, nuclear, coal, hydro and wind. We have 380 Bcf of natural gas storage capacity in Michigan and Alberta – that is vital in maintaining reliability of supply year round. This amount of gas gives TransCanada the ability to meet the needs of four million homes annually. And we have approximately 6,100 kilometres of oil pipeline operating and in development – the Keystone Pipeline System. When the entire project is complete, Keystone will have the capacity to move 1.1 million barrels per day (Bbl/d) of crude oil to refining centres in the U.S. Midwest and Gulf Coast. We do all of this with 4,200 dedicated employees, individuals who have to be at their very best in order to manage the company’s large asset base in seven Canadian provinces, 33 U.S. states and Mexico. It is their dedication and hard work that allows the company to operate safely and reliably and ensure projects are completed on time and on budget. The work is technically challenging but our employees have the experience, the expertise and the skills to accomplish our goals. We safely and reliably operate $47 billion of critical infrastructure.

Halfway There TransCanada has made great strides in advancing its $20 billion capital program – a program that is nearly half complete. TransCanada is about halfway through its current capital program with approximately $10 billion of assets having recently started or about to start commercial operations in the first half of 2011. Start-up of a number of large scale projects in 2010 and 2011 (Keystone, North Central Corridor, Groundbirch, Bison, Kibby, Halton Hills, Guadalajara and Coolidge) should produce approximately $1 billion of earnings before interest, taxes, depreciation and amortization (EBITDA) in 2011. That EBITDA is expected to grow to about $2 billion as we complete the Horn River Pipeline Project, the final phases of Cartier Wind, the Bruce Power restart project, and the Keystone U.S. Gulf Coast Expansion which is targeted for completion in 2013. This unprecedented capital program is expected to drive long-term growth in earnings, cash flow and dividends.

Oil Pipelines An historic milestone was achieved by the company with the start of crude oil deliveries on the Keystone Pipeline System to Wood River and Patoka, Illinois. A celebration was held to recognize the thousands of employees, contractors and suppliers across North America who turned the Keystone project into a successful reality. The first phase of Keystone went into operation in June 2010. The completion of the Cushing extension in February 2011 extended the pipeline south from Steele City, Nebraska, to Cushing, Oklahoma and increased its capacity to 591,000 Bbl/d. This capacity is supported by contracted volumes of 530,000 Bbl/d. The next important phase of the US$13 billion project is the Keystone U.S. Gulf Coast Expansion, also known as Keystone XL, which will deliver crude oil to markets in the U.S. Gulf Coast. Keystone XL has a capacity of 500,000 Bbl/d, 75 per cent or 380,000 Bbl/d is contracted with shippers for an average term of 17 years. The Gulf Coast Expansion will increase Keystone’s overall capacity to 1.1 million Bbl/d – 83 per cent of that capacity or 910,000 Bbl/d is firmly contracted for approximately 18 years. Once all permits are received, it is expected Keystone XL would be operational in 2013. Keystone will play an important role in linking a secure and growing supply of Canadian crude oil with the largest refining markets in the United States, substantially improving North America’s energy security. TransCanada will also transport American crude oil from Montana, North Dakota and Cushing, Oklahoma to market following the conclusion of successful open seasons for both the Bakken and Cushing Marketlink projects. These projects have a combined capacity of 250,000 Bbl/d and will use facilities which form part of the Keystone pipeline system to transport the crude oil to market. The oil and gas industry came under more scrutiny in 2010. TransCanada is working to ensure Keystone is one of the safest and most technologically-advanced pipelines ever built. Our company continues to be a leader with one of the best pipeline safety and operating records in the industry. TransCanada is poised to become a very significant player in the oil transmission business.

Natural Gas Pipelines Early in 2010, TransCanada finished its North Central Corridor natural gas pipeline in Northern Alberta. This expansion of the Alberta System provided needed capacity to handle increasing natural gas supply in northwest Alberta and northeast B.C. and growing Alberta markets. The $800 million project was completed on schedule and under budget. Late in 2010 gas began to flow through TransCanada’s Groundbirch pipeline. The $155 million pipeline connects the Alberta System to the prolific Montney shale gas play in northeastern B.C. Groundbirch has contracts for 1.24 Bcf/d of natural gas by 2014. Groundbirch complements the nearby Horn River Project, another pipeline designed to bring B.C. shale gas to market. The National Energy Board approved the project in late January 2011. This $310 million pipeline is expected to be operational in the second quarter of 2012 and has contracted capacity of 634 million cubic feet per day (MMcf/d). TransCanada has received additional requests to move approximately 2.3 Bcf/d of Canadian shale gas to market by 2015. This is expected to lead to further expansions of the Alberta System and contribute to higher volumes and lower tolls on downstream pipelines including the Canadian Mainline. Halfway There TransCanada is the largest natural gas transmission company in North America.

TransCanada’s vast pipeline network is also well positioned to connect other new sources of supply – U.S. shale gas, northern gas and liquefied natural gas (LNG) – to growing North American markets. The company’s Bison pipeline began moving gas from the Powder River Basin in Wyoming to the Northern Border pipeline system in North Dakota in January 2011. The US$630 million project has shipping commitments for 407 MMcf/d. TransCanada is expanding its natural gas pipeline footprint in Mexico with the construction of the Guadalajara pipeline. The pipeline will move gas from an LNG facility in Manzanillo to Guadalajara, Mexico’s second largest city. The project is expected to begin shipping natural gas in the second quarter of 2011. The first open season ever conducted in the 30-year history of working to develop Alaska’s North Slope gas was held in 2010. Multiple conditioned bids from major industry players were received for significant volumes. The project team continues to work with shippers to resolve the conditions within its control. The US$32 to US$41 billion pipeline would carry natural gas from Prudoe Bay, Alaska through Alberta and on to North American markets. An alternate route would see natural gas transported from the North Slope to Valdez, liquefied and shipped to North American and international markets. The project could be operational in 2020. The National Energy Board approved the Mackenzie Gas Pipeline Project late in 2010 subject to certain conditions. The project’s backers continue fiscal discussions with the Canadian Federal Government to further advance the project. TransCanada believes gas from both Alaska and Mackenzie will be needed in the future. We are well positioned to connect major shale gas plays in Canada and the United States.

In the fall of 2010, a pair of power projects marked their official start of operations. The $700 million Halton Hills Generating Station in Ontario was completed on time and on budget and can generate enough power to meet the needs of 700,000 homes. Operating under a 20-year power purchase arrangement with the Ontario Power Authority, the 683 MW facility uses state-of-the-art low emissions technology to meet high environmental standards. The facility also supports the Ontario Government’s goal of retiring its coal-fired plants by 2014. New England’s largest wind power project – Kibby Wind – was also completed. The 44 wind turbines that sit atop Kibby Mountain generate 132 MWs of electricity, enough renewable power to meet the needs of 50,000 Maine homes. Construction continues on the five-stage 590 MW Cartier Wind Energy project in Québec. The Montagne-Sèche project and phase one of the Gros-Morne wind farm are expected to be operational in December 2011. Gros-Morne phase two is expected to be operational in December 2012. These are the fourth and fifth Québec-based wind farms of Cartier Wind Energy, which is 62 per cent owned by TransCanada. Designed to provide a quick response to peak power demands, construction of the Coolidge Generating Station in Arizona is virtually complete. The US$500 million, 575 MW power facility should be operational in the second quarter of 2011. The Coolidge plant will operate under a 20-year power purchase arrangement with the Salt River Project, one of the largest utilities in Arizona. Refurbishment of units one and two at the Bruce Power nuclear facility continues to progress. Bruce expects to begin commissioning unit two in the second quarter of 2011 and it should be operational in the first quarter of 2012. Commissioning of unit one should begin in the third quarter of 2011, with full operation scheduled for the third quarter of 2012. TransCanada’s share of the total capital cost is expected to be $2.4 billion. Once the refurbishment is complete, Bruce Power will be the second largest nuclear power plant in the world, generating 6,200 MW of emissions free power. With our industry expertise, experience and diverse energy asset base, TransCanada is well positioned to benefit in an evolving energy future. Energy Halfway There Our energy portfolio is very diverse, producing power from sources such as natural gas, nuclear, coal, hydro and wind.

Fiscally Prudent – Financially Strong Looking forward, once TransCanada completes its current $20 billion capital program in 2013, we expect to generate approximately $4 billion of funds from operations. This will provide us with significant financial capacity to invest in our core businesses, continue to increase dividends to shareholders and further enhance our financial strength and flexibility. Our decisions will continue to be guided by our desire to maximize long-term shareholder value. By 2013 TransCanada expects to generate approximately $4 billion of funds from operations.

2010 Financial Highlights Net Income Applicable to Common Shares $1.2 billion or $1.78 per share Comparable Earnings (1) $1.4 billion or $1.97 per share Comparable Earnings before Interest, Taxes, Depreciation and Amortization (1) $3.9 billion Funds Generated from Operations (1) $3.3 billion Capital Expenditures $5.0 billion invested in core businesses Common Share Dividends Declared $1.60 per share 3,331 Comparable Earnings per Share(1) (dollars) 06 07 08 09 10 Dividends Declared per Share (dollars) 06 07 08 09 10 Common Shares Outstanding – Average (millions of shares) 06 07 08 09 10 Comparable EBITDA(1) (millions of dollars) Capital Expenditures and Acquisitions (millions of dollars) Net Income Applicable to Common Shares (millions of dollars) 1,227 1,374 1,079 1,223 1,440 06 07 08 09 10 Comparable Earnings(1) (millions of dollars) 06 07 08 09 10 06 07 08 09 10 Funds Generated from Operations(1) (millions of dollars) 06 07 08 09 10 06 07 08 09 10 Market Price – Close Toronto Stock Exchange (dollars) 06 07 08 09 10 (1) Non-GAAP measure that does not have any standardized meaning prescribed by generally accepted accounting principles (GAAP). For more information see Non-GAAP Measures in the Management’s Discussion and Analysis of the 2010 Annual Report. Net Income per Share – Basic (dollars) 06 07 08 09 10 1,361 1,325 925 1,100 1,279 3,941 4,107 4,125 3,527 3,919 3,080 2,378 2,621 3,021 5,036 6,319 2,042 5,874 6,363 1.78 2.11 2.21 2.31 2.53 1.97 2.03 1.90 2.08 2.25 1.60 1.52 1.28 1.36 1.44 691 652 488 530 570 37.99 36.19 40.61 40.54 33.17

Financial
Highlights

Year ended December 31 (millions of dollars)	2010		2009		2008	2007	2006
Income
Net income applicable to common shares
Continuing operations	1,227		1,374		1,440	1,223	1,051
Discontinued operations	–		–		–	–	28
	1,227		1,374		1,440	1,223	1,079
Cash Flow
Funds generated from operations	3,331		3,080		3,021	2,621	2,378
(Increase)/decrease in operating working capital	(249	)	(90	)	135	63	(506	)
Net cash provided by operations	3,082		2,990		3,156	2,684	1,872
Capital expenditures and acquisitions	5,036		6,319		6,363	5,874	2,042
Balance Sheet
Total assets	46,589		43,841		39,414	30,330	25,909
Long-term debt	17,028		16,186		15,368	12,377	10,887
Junior subordinated notes	985		1,036		1,213	975	–
Preferred shares	1,224		539		–	–	–
Common shareholders' equity	15,503		15,220		12,898	9,785	7,701
Common Share Statistics Year ended December 31	2010		2009		2008	2007	2006
Net income per share – Basic
Continuing operations	$1.78		$2.11		$2.53	$2.31	$2.15
Discontinued operations	–		–		–	–	0.06
	$1.78		$2.11		$2.53	$2.31	$2.21
Net income per share – Diluted
Continuing operations	$1.77		$2.11		$2.52	$2.30	$2.14
Discontinued operations	–		–		–	–	0.06
	$1.77		$2.11		$2.52	$2.30	$2.20
Dividends declared per share	$1.60		$1.52		$1.44	$1.36	$1.28
Common shares outstanding (millions)
Average for the year	690.5		651.8		569.6	529.9	488.0
End of year	696.2		684.4		616.5	539.8	489.0

TRANSCANADA CORPORATION        1

Chairman's
Message
An inspiring leader can be difficult to replace, and this was one of the challenges we faced in 2010 with the retirement of Hal Kvisle. For more than a decade, Hal inspired others by demonstrating his and the company's values – delivering results.


Orchestrating a smooth transition was a critical task for us, one that was a joint undertaking for both the Board and the CEO. Importantly, and to his credit, Hal communicated his impending departure and worked tirelessly grooming executives in the company.

We engaged external resources, and broadened the experience base of candidates allowing us a clear view of their capabilities. It was no accident that Russ Girling was positioned to succeed. His placement in high-level leadership positions over the last number of years ensured a smooth transition would occur when the time came for him to sit in the President and CEO's chair.

Succession is always important and the process in TransCanada is well crafted.

The Board and I wish Hal the best in his retirement and look forward to Russ continuing to grow long-term value for our shareholders, with the support of an experienced and capable executive leadership team.

This is an exciting time to guide TransCanada. Execution of the company's ambitious $20 billion capital program, managing the issues surrounding the low gas price environment and the political challenges of cross border pipelines are not insignificant. Fortunately, the strategies for success have been set by Hal and other leaders – strategies Russ was instrumental in developing over the last decade.

Successful execution of those strategies for any company involves creating the right work environment. TransCanada received important recognition on this front in 2010. The company was included in Canada's top 100 employers, Alberta's top 50 employers for 2011, best employer for new Canadians and best diversity employer. TransCanada also maintained its ranking on the Dow Jones Sustainability Index for the ninth consecutive year – one of only two Canadian energy companies to attain this recognition.

Beyond the internal support, the Board must also ensure the needs for retention and fair compensation for TransCanada's leadership team are balanced with actual performance and creation of shareholder value. Accommodating equity support for projects that deliver results beyond the term of compensation programs while diluting short term metrics requires some finesse. These are not formula driven tasks and I believe the Board has exercised prudent judgment in that balance.

To support that view, this year, the company has made a concerted effort to ensure shareholders understand the thorough processes at work in TransCanada. Often, actual practice surpasses the disclosure in the annual documents. To further exhibit transparency, much of the disclosure has been enhanced to more effectively close this gap.

There are many definitions of success but any form of success is dependent on dedication and effort. TransCanada continues to benefit from the daily, ongoing efforts of its 4,200 employees. It is the sum of these efforts that equals true success and for that I and my fellow Board members offer our thanks. Similarly, we offer our sincere thanks to Kerry Hawkins for his ongoing contributions as he is retiring from the Board after 15 years of dedicated service to shareholders and management.

On behalf of the Board of Directors;

S. Barry Jackson

2        CHAIRMAN'S MESSAGE

Letter
to Shareholders
Strategies to Ensure Lasting, Long Term Value

A company's vision sets its direction for business planning, drives the right strategy and unites employees in achieving a common goal. But to achieve the vision, it must be executed with passion, hard work, discipline and exceptional decision-making at every level of the organization.

TransCanada's vision is unchanged over the last decade – our goal is to become North America's leading energy infrastructure company. The company has clear priorities to ensure this goal is met – priorities I have shared with the Board of Directors, the financial community and the many other stakeholders of our company. I would like to share with you the significant progress we made during 2010 and some of the opportunities for the years ahead.

Priority #1: TransCanada will focus on maximizing the value of its existing assets and ensure they continue to operate safely and reliably, delivering solid results.

Our base businesses generate approximately $4 billion of earnings before interest, taxes, depreciation and amortization (EBITDA)⁽¹⁾ each year. Our top priority is to protect the long term value of these assets and position them for future growth to ensure they continue to deliver stable and growing cash flow for decades to come.

In our pipeline businesses we continue to connect new supply to growing markets across North America. By maximizing the volume of natural gas and oil flowing through our pipelines we lower our unit costs and enhance our competitiveness and profitability.

This year we continued to successfully position our U.S. pipeline network to move U.S. shale gas, contracted approximately 200 MMcf/d of Marcellus gas to our Eastern Canada/U.S. delivery system, contracted approximately 2 Bcf/d of Northeast B.C. shale gas to our Alberta System and added significant U.S. crude oil volumes from the Bakken and Cushing areas to our Keystone pipeline.

We continue to develop new, cost competitive services to attract additional supply and meet our customers' changing needs. Importantly, today we are working with our customers on toll structure changes which will lower tolls, better reflect system usage and flow patterns and improve the competitiveness of the Canadian Mainline and the Western Canadian Sedimentary Basin. The Mainline is critical to moving North American gas supply to market.

In our power business we continue to maximize the long term profitability of our power plants through life extensions, higher plant availability, and increasing the output and the revenue we receive for the electricity we produce. During the year, we were able to implement plans that will significantly extend the operating life of Bruce A Units 3 and 4 and we increased the available capacity of Unit 30 at Ravenswood.

While our low-cost, base-load operations in Alberta and the U.S. Northeast have been impacted over the last few years by lower power prices, they remain very profitable and are well positioned to benefit as the economy recovers and commodity prices improve. In addition, the percentage of fixed price power sold under contract will increase over time as new power projects in our portfolio are completed and placed into service.

Ensuring we receive the maximum value from our assets over the long term requires the optimal balance of continuous cost improvement and reinvestment in maintenance capital to ensure the life of our assets is maximized. Properly done, our assets will be able to provide low cost, reliable service for decades to come. In 2010, we invested approximately $200 million in maintenance capital, at the same time capturing operating cost improvements across our assets from increased automation, improved processes and innovation. I am confident we have the right balance.

Doing all of this safely and without injury is an imperative. Our philosophy is every employee and contractor goes home safe – every day. In 2010, our injury frequency rates were among the lowest in our industry. While we are very proud of this accomplishment, we believe a zero injury rate is possible and we will continue to strive to achieve that objective.

Priority #2: Complete the company's $20 billion capital program on time and on budget and ensure the cash flow associated with these assets comes on stream.

TransCanada is in the midst of an unprecedented $20 billion capital program that will see a number of attractive, low-risk pipeline and power projects placed into service over the next three years.

LETTER TO SHAREHOLDERS        3

Today we are about halfway through this program, with approximately $10 billion of assets having recently started or about to commence commercial operations.

Our company's largest and most ambitious project – the Keystone pipeline – took a major step forward as it began flowing oil for the first time to refineries in Illinois in the summer of 2010.

Keystone marked a further milestone in February 2011 as the Cushing extension began transporting oil to market. At the same time Keystone's nominal capacity expanded to 591,000 Bbl/d.

The next step for the US$13 billion project is the U.S. Gulf Coast Expansion or Keystone XL. This portion of the pipeline system is expected to be operational in 2013. When completed, Keystone's overall commercial capacity will rise to 1.1 million Bbl/d – with close to 1.0 million Bbl/d of that capacity contracted for an average term of 17 years. As volumes of Canadian and U.S. supplies grow, Keystone can very economically expand by another 400,000 Bbl/d, resulting in a total capacity of 1.5 million Bbl/d. This enormous project has significant energy security, employment and economic benefits to Canada and the United States and I remain confident we will obtain all major approvals this year.

Early in 2011, the US$630 million Bison pipeline began shipping natural gas from the U.S. Rockies to market. Just a few weeks prior to this, the $155 million Groundbirch pipeline went into service, delivering natural gas from Northeast B.C. through the Alberta System and on to North American markets. And in the spring of 2010, the $800 million North Central Corridor natural gas pipeline was finished on time and under budget.

In the fall of 2010, two major Energy projects were completed – the second phase of the US$350 million Kibby Wind project in Maine and the $700 million Halton Hills Generating Station in Ontario.

Other major projects that are expected to become operational in 2011 include the US$360 million Guadalajara pipeline in Mexico and Arizona's US$500 million Coolidge Generating Station. Both are expected to begin operating in the second quarter. Construction of the remaining stages of the Cartier Wind Energy project in Québec is progressing and they are expected to be operational in late 2011 and 2012.

The Bruce Power refurbishment involving Units 2 and 1 is scheduled to be complete in the first and third quarters of 2012 respectively.

While it has taken significantly longer and cost more to complete the re-start than originally anticipated, we are confident in our current estimates and schedule. In recent months, significant progress has been made and we are now in the home stretch of completing the project. Despite the challenges, once Units 1 and 2 are returned to service they will generate 1,500 MW of much needed, emissions free power for the residents of Ontario and deliver attractive, long-term returns for our shareholders.

Priority #3: Maintain our financial strength and flexibility to ensure we can continue to fund the existing capital program and invest in our growth prospects as we move forward.

In 2010, TransCanada continued to deliver strong financial and operating results. Comparable earnings⁽¹⁾ were $1.4 billion or $1.97 per share. Net income applicable to common shares totalled $1.2 billion or $1.78 per share. Funds generated from operations⁽¹⁾ increased to a record $3.3 billion on the strength of our diverse portfolio of North American energy infrastructure assets.

For the eleventh consecutive year, in February 2011 TransCanada's Board of Directors increased the dividend on common shares. The new quarterly dividend of $0.42 per common share equates to $1.68 per share on an annualized basis – an increase of five per cent over 2010.

Over the past decade, we have continuously strengthened our balance sheet to ensure we have the capacity to fund our capital program and on-going growth in all economic environments. This strategy served the company well during the turbulence of the economic downturn experienced over the past few years and allowed us to maintain 'A' grade credit ratings.

Since the onset of the financial crisis in the second half of 2008, TransCanada has raised approximately $11.5 billion in the capital markets, including $3 billion of common equity, to fund our $20 billion capital program.

Our success in issuing US$2.25 billion of long-term debt and $700 million of preferred shares in 2010 at very attractive rates is a testament to the company's continued financial strength.

While we recognize issuing both debt and equity to fund a long cycle capital program has had an impact on our reported earnings per share over the last two years, these investments will deliver long term growth in cash flow, earnings and dividends.

4        LETTER TO SHAREHOLDERS

As we complete our current capital program between now and 2013, we expect to generate an additional $2 billion of EBITDA⁽¹⁾ annually, bringing our forecast total to approximately $6 billion per year.

This, in turn, is expected to lead to a robust increase in discretionary cash flow. By 2013 we expect to generate approximately $4 billion of funds from operations⁽¹⁾ per year. This will provide us with significant financial capacity to invest in our core businesses; continue to increase dividends to shareholders; and to further enhance our financial strength and flexibility. Our decisions will be guided by our desire to maximize long-term shareholder value while 'living within our means'.

Priority #4: Reinvest TransCanada's growing cash flow in high quality, low risk projects.

Going forward, TransCanada has three large platforms for growth – Natural Gas Pipelines, Oil Pipelines and Energy. All three have strong long-term fundamentals.

Over the next decade, the demand for natural gas in North America is expected to grow by approximately 10 Bcf/d, powered by the expected growth in demand for electricity. Today, our pipeline network taps into virtually every major North American natural gas supply basin on the continent and provides our customers with unparalleled access to premium markets. Looking forward, we are very well positioned to connect shale gas, conventional gas, LNG in Mexico and, in the longer term, northern gas to growing markets.

We have captured the pre-eminent position to move growing supplies of crude oil from Western Canada and the Williston Basin in the United States to the largest refining centres in North America.

Western Canadian crude oil supply is expected to grow by approximately 1.1 million Bbl/d over the next decade. At the same time, industry experts project that production from the Williston Basin could grow by as much as 200,000 Bbl/d between now and 2015.

TransCanada is well positioned to move growing oil production from both these areas to large refining centres in the U.S. Midwest and Gulf Coast regions through the Keystone Oil Pipeline and our related Bakken and Cushing Marketlink projects.

In Energy, power demand is expected to grow at an average annual rate of approximately one per cent over the next ten years. While coal, nuclear and hydro will remain key components of the supply mix, it is likely that gas-fired generation, renewables and nuclear refurbishments will play a major role in meeting future demand as the North American market transitions to a less carbon intensive mix. Our proven track record in the development of natural gas, hydro, wind and nuclear will allow us to continue to capture high quality long term opportunities in our core markets.

We have enjoyed tremendous success over the past decade under the leadership of Hal Kvisle. We have focused on businesses in which we have considerable expertise and in geographies where we have distinct competitive advantage. The 4,200 employees of this company are the best in their fields and they deliver superior results – every day. Together, they accomplish big things and they do it safely and with great care. I thank them all for their accomplishments. I am very proud and honoured to have the opportunity to work with them.

Going forward, I believe we have the right people, the right skills, the right assets, the right strategy and the financial capacity to compete and win a significant share of the quality opportunities available in our core markets and ultimately realize our vision to be North America's leading energy infrastructure company. I am very excited about our future. As the TransCanada leadership team, along with its 4,200 employees, moves these priorities forward, we will increase cash flow, increase earnings and grow our dividend – resulting in continued long term, sustainable growth for our shareholders.

Russell K. Girling
President and Chief Executive Officer

(1)

Non-GAAP measure that does not have any standardized meaning prescribed by generally accepted accounting principles. For more information see Non-GAAP Measures in the Management's Discussion and Analysis of the 2010 Annual Report.

LETTER TO SHAREHOLDERS        5

TABLE OF CONTENTS

TRANSCANADA OVERVIEW		7
TRANSCANADA'S STRATEGY		9
CONSOLIDATED FINANCIAL REVIEW		10
	Selected Three-Year Consolidated Financial Data	10
	Highlights	11
	Reconciliation to Net Income Applicable to Common Shares	12
	Results of Operations	14
FORWARD-LOOKING INFORMATION		15
NON-GAAP MEASURES		16
OUTLOOK		16
PIPELINES MAP		18
NATURAL GAS PIPELINES		20
	Highlights	20
	Results	21
	Financial Analysis	22
	Opportunities and Developments	25
	Business Risks	29
	Outlook	30
	Natural Gas Throughput Volumes	32
OIL PIPELINES		32
	Highlights	32
	Financial Analysis	32
	Opportunities and Developments	33
	Business Risks	34
	Outlook	35
ENERGY		36
	Map	36
	Highlights	38
	Power Plants – Nominal Generating Capacity and Fuel Type	39
	Results	40
	Financial Analysis	41
	Opportunities and Developments	51
	Business Risks	53
	Outlook	54
CORPORATE		55
OTHER INCOME STATEMENT ITEMS		55
LIQUIDITY AND CAPITAL RESOURCES		56
	Summarized Cash Flow	56
	Highlights	57
	Cash Flow and Capital Resources	57
CONTRACTUAL OBLIGATIONS		62
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS		66
	Financial Risks and Financial Instruments	66
	Other Risks	78
CONTROLS AND PROCEDURES		83
SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES		84
ACCOUNTING CHANGES		86
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA		88
FOURTH QUARTER 2010 HIGHLIGHTS		90
SHARE INFORMATION		93
OTHER INFORMATION		93
GLOSSARY OF TERMS		94

6        MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's Discussion and Analysis (MD&A) dated February 14, 2011 should be read in conjunction with the accompanying audited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) and the notes thereto for the year ended December 31, 2010 which are prepared in accordance with Canadian generally accepted accounting principles (GAAP). This MD&A covers TransCanada's financial position and operations as at and for the year ended December 31, 2010. "TransCanada" or "the Company" includes TransCanada Corporation and its subsidiaries, unless otherwise indicated. Amounts are stated in Canadian dollars unless otherwise indicated. Abbreviations and acronyms not defined in this MD&A are defined in the Glossary of Terms in the Company's 2010 Annual Report.

TRANSCANADA OVERVIEW

With more than 50 years experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure, including natural gas and oil pipelines, power generation and natural gas storage facilities.

In pursuing its vision to be the leading energy infrastructure company in North America, TransCanada strives to execute on its portfolio of large, attractive growth projects. Each of these new projects is supported by strong business fundamentals and long-term contracts.

With assets of approximately $47 billion and a substantial growth portfolio, TransCanada believes it is well positioned to build on its track record of strong and sustainable earnings and cash flow.

At December 31, 2010, TransCanada had completed construction and placed in service, or will place in service in early 2011, approximately $10 billion of its $20 billion capital growth program. In 2010, TransCanada spent $2.3 billion to advance or complete construction of several major Natural Gas Pipeline and Energy projects, including placing five projects in service. In addition, the Company completed the first two phases of the Keystone crude oil pipeline with capital expenditures of $2.7 billion.

TransCanada's 2010 Key Accomplishments

The Company advanced a significant portion of the Keystone oil pipeline extending from Hardisty, Alberta to markets in the United States (U.S.) Midwest, including the following:

•

commenced operating at a low operating pressure as the first phase of Keystone began delivering oil to Wood River and Patoka in Illinois (Wood River/Patoka) in June 2010; and

•

completed construction of the extension to Cushing, Oklahoma (Cushing Extension) and commenced line fill in late 2010. The Cushing Extension was in service at the beginning of February 2011.

The Company completed construction, placed in service and advanced the following initiatives in natural gas pipelines, which included connecting new shale and unconventional natural gas supply:

•

completed the final portion of the $800 million North Central Corridor (NCC) pipeline in northern Alberta in early 2010, providing capacity to shippers on the Alberta System to address increasing natural gas supply in northwestern Alberta and northeastern British Columbia (B.C.). The project was completed on schedule and under budget;

•

completed the US$630 million Bison pipeline in late December 2010, delivering natural gas from the Powder River Basin in Wyoming. The pipeline was placed in service in January 2011;

•

completed the $155 million Groundbirch pipeline in December 2010, on schedule and under budget, and began transporting natural gas from the Montney shale gas formation into the Alberta System;

•

received approval from the National Energy Board (NEB) in January 2011 to construct the approximate $310 million Horn River natural gas pipeline, which is expected to transport natural gas from the Horn River shale gas formation starting in second quarter 2012; and

•

advanced construction of the Guadalajara pipeline, which will move natural gas from Manzanillo to Guadalajara in Mexico and was 70 per cent complete as of December 31, 2010. The US$360 million project is expected to be operational in second quarter 2011.

MANAGEMENT'S DISCUSSION AND ANALYSIS        7

The Company completed, placed in service and advanced the following power generation assets:

•

completed the $700 million, 683 megawatt (MW) Halton Hills generating station, on time and on budget, in the fall of 2010 when it began delivering low-emission, natural gas-sourced power to the Ontario market;

•

completed the US$350 million Kibby Wind project, a 44 turbine, 132 MW wind farm in Maine ahead of schedule and on budget; and

•

advanced construction of the US$500 million Coolidge generation station, which is approximately 95 per cent complete, with commissioning approximately 80 per cent finished. Coolidge is anticipated to be in service in second quarter 2011.

TransCanada's Businesses Are Organized Into Three Segments – Natural Gas Pipelines, Oil Pipelines and Energy

The Natural Gas Pipelines and Oil Pipelines businesses consist of large-scale natural gas and crude oil pipelines, respectively, primarily situated in Canada and the U.S. TransCanada is also the general partner of TC PipeLines, LP (PipeLines LP), a limited partnership that owns interests in U.S. natural gas pipelines.

Natural Gas Pipelines

TransCanada's natural gas pipeline systems consist of a network of more than 60,000 kilometres (km) (37,000 miles) of wholly owned and operated natural gas pipelines, and more than 8,800 km (5,500 miles) of partially owned natural gas pipelines. The network connects major natural gas supply basins and markets, transporting approximately 20 per cent of the natural gas consumed in North America or 14 billion cubic feet (Bcf) of natural gas per day, which is delivered to local distribution companies, power generation facilities and other businesses in markets across North America. The Company's U.S. Natural Gas Pipelines also include regulated natural gas storage facilities in Michigan with a total capacity of 250 Bcf.

TransCanada is also pursuing additional natural gas pipelines projects to diversify the supply side of the business and add incremental value to existing assets. Key areas of focus include greenfield development opportunities to connect TransCanada's natural gas pipelines to emerging Canadian and U.S. shale gas and other supplies, and over the longer term, to northern natural gas reserves. TransCanada is also pursuing opportunities to optimize its existing natural gas pipelines systems to respond to the changing flow patterns of natural gas supply in North America.

Oil Pipelines

With increasing production of crude oil in Alberta and new crude oil discoveries in the U.S., including the Bakken shale play in Montana and North Dakota, along with growing demand for secure, reliable sources of energy, TransCanada has identified opportunities to develop new oil pipeline capacity. The Keystone oil pipeline complements the Company's natural gas transmission business and draws on its pipelines experience. This large-scale crude oil pipeline system, designed to initially carry 1.1 million barrels per day (Bbl/d), comprises the completed 3,467 km (2,154 miles) Wood River/Patoka and Cushing Extension phases, and a proposed 2,673 km (1,661 miles) U.S. Gulf Coast Expansion project (collectively, Keystone). Future expansions could increase the capacity of Keystone to 1.5 million Bbl/d.

Energy

TransCanada's Energy business primarily consists of a portfolio of essential power generation assets in select regions of Canada and the U.S., and unregulated natural gas storage assets in Alberta.

TransCanada owns, controls or is developing more than 10,800 MW of power generation, comprising a diverse portfolio that includes power sourced from natural gas, nuclear, coal, hydro and wind assets. TransCanada's power business is primarily located in Alberta, Ontario and Québec and in the northeastern U.S., mainly in the New England states, and New York. The assets are largely underpinned by long-term tolling contracts or represent low-cost baseload generation and essential capacity.

From offices in Western Canada, Ontario and the northeastern U.S., TransCanada complements these assets by conducting wholesale and retail electricity marketing and trading throughout North America.

8        MANAGEMENT'S DISCUSSION AND ANALYSIS

In addition to power generation assets in the Energy business, TransCanada owns or controls approximately 130 Bcf of unregulated natural gas storage capacity in Alberta, or approximately one-third of all storage capacity in the province. Combined with the regulated natural gas storage in Michigan included in Natural Gas Pipelines, TransCanada provides natural gas storage and related services for approximately 380 Bcf of capacity.

TRANSCANADA'S STRATEGY

TransCanada's vision is to be the leading energy infrastructure company in North America, focusing on pipeline and power generation opportunities in regions where it has or can develop a significant competitive advantage. TransCanada's key strategies continue to evolve with the Company's growth and development and its changing business environment. TransCanada's corporate strategy integrates four fundamental value-creating activities:

1.

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

2.

Commercially develop and physically execute new asset investment programs

3.

Cultivate a focused portfolio of high-quality development options

4.

Maximize TransCanada's competitive strengths

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

TransCanada relies on a low-risk business model to maximize the full-life value of its existing assets and commercial positions. In the Natural Gas Pipelines and Oil Pipelines businesses, large-scale natural gas and crude oil pipelines connect long-life supply basins with stable and growing markets, generating predictable, sustainable cash flows and earnings of a long-term nature. In the Energy business, highly efficient, large-scale power generation facilities supply markets through long-term power purchase and sale agreements and low-volatility, shorter-term commercial arrangements. TransCanada's growing investments in natural gas, nuclear, wind and hydro-power generating facilities demonstrate the Company's commitment to sustainable, clean energy. Long-life infrastructure assets and long-term commercial arrangements will continue as cornerstones of TransCanada's business model.

Commercially develop and physically execute new asset investment programs

TransCanada's expertise, scale and financial capacity enable access to attractive commercial, financing and input cost arrangements that underpin the quality of growth projects, notably the current $20 billion capital program that began generating revenue in 2010. The remainder of these projects will provide further contributions to the Company's earnings over the next three years as they are put in service. Success in this capital program requires effective performance in engineering and in project and operational set-up and delivery. It also requires regulatory, legal and financing support. TransCanada's model for managing construction risks and maximizing capital productivity helps ensure disciplined attention to quality, cost and schedule that produces service for its customers and returns to its shareholders. Many of these functional capabilities also form the basis for successful acquisition and integration of new energy and pipeline facilities, an important dimension of the Company's growth strategy.

Cultivate a focused portfolio of high-quality development options

The Company's core regions within North America are the focus of pipelines and energy growth initiatives. TransCanada will continue to pursue opportunities to connect long-life shale and conventional natural gas resources in Western Canada, Northern Canada, Alaska, the U.S. Rockies, the U.S. midcontinent and the U.S. Gulf Coast supply regions. TransCanada will also continue to pursue opportunities to connect growing crude oil volumes from the Alberta oil sands and U.S. sources, including the Bakken formation of the Williston basin, to preferred North American markets. In addition, the Company will continue to assess energy infrastructure acquisition opportunities that complement its existing assets and provide access to new supply and market regions. In the Energy business, the Company will continue to focus on low-cost, long-life baseload power generating and natural gas storage assets supported by firm, long-term contracts with creditworthy counterparties. Selected opportunities will advance to full development and construction when market conditions are appropriate and project risks are manageable.

Maximize TransCanada's competitive strengths

TransCanada continues to build competitive strength in areas that directly drive long-term shareholder value. The Company relies on its scale, presence, operating capabilities, leadership and teams to compete effectively and deliver value to customers. A disciplined approach to capital investment combined with access to sizeable amounts of competitive-cost capital allows the Company to create shareholder value from its large capital projects. TransCanada recognizes that constructive relationships with key customers and stakeholders are critically important in the long-term energy infrastructure business.

MANAGEMENT'S DISCUSSION AND ANALYSIS        9

CONSOLIDATED FINANCIAL REVIEW

SELECTED THREE-YEAR CONSOLIDATED FINANCIAL DATA

(millions of dollars except per share amounts)		2010		2009		2008
Income Statement
Revenues		8,064		8,181		8,547
Comparable EBITDA(1)		3,941		4,107		4,125
Net Income		1,272		1,380		1,440
Preferred Share Dividends		45		6		–
Net Income Applicable to Common Shares		1,227		1,374		1,440
Comparable Earnings(1)		1,361		1,325		1,279
Per Share Data
Net Income per Common Share
	Basic	$1.78		$2.11		$2.53
	Diluted	$1.77		$2.11		$2.52
Comparable Earnings per Common Share(1)		$1.97		$2.03		$2.25
Dividends Declared
	Per Common Share	$1.60		$1.52		$1.44
	Per Class 1 Preferred Share(2)	$1.15		$0.2899		–
	Per Class 3 Preferred Share(2)	$0.8041		–		–
	Per Class 5 Preferred Share(2)	$0.6457		–		–
Cash Flows
Funds generated from operations(1)		3,331		3,080		3,021
(Increase)/decrease in operating working capital		(249	)	(90	)	135
Net Cash Provided by Operations		3,082		2,990		3,156
Capital Expenditures		5,036		5,417		3,134
Acquisitions, Net of Cash Acquired		–		902		3,229
Balance Sheet
Total Assets		46,589		43,841		39,414
Total Long-Term Liabilities		23,044		21,959		20,158

⁽¹⁾

Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA, Comparable Earnings, Comparable Earnings per Share and Funds Generated from Operations.

⁽²⁾

The Company issued Class 1, 3 and 5 preferred shares in September 2009, March 2010 and June 2010, respectively.

10        MANAGEMENT'S DISCUSSION AND ANALYSIS

HIGHLIGHTS

Earnings

•

Net Income was $1,272 million and Net Income Applicable to Common Shares was $1,227 million or $1.78 per share in 2010 compared to $1,380 million and $1,374 million or $2.11 per share, respectively, in 2009.

•

TransCanada's Comparable Earnings of $1,361 million or $1.97 per share in 2010 excluded a $127 million after-tax valuation provision for the Mackenzie Gas Project (MGP).

Cash Flow

•

Funds Generated from Operations were $3.3 billion in 2010, an increase of $0.2 billion from 2009.

•

TransCanada invested $5.0 billion in its Natural Gas Pipelines, Oil Pipelines and Energy capital projects in 2010, including the following:

•

capital expenditures of $1.2 billion for Natural Gas Pipelines projects, including expansion of the Alberta System and construction of Bison and Guadalajara;

•

capital expenditures of $2.7 billion for Keystone; and

•

capital expenditures of $1.1 billion for Energy projects, including the refurbishment and restart of Bruce A Units 1 and 2, and construction of Coolidge, Halton Hills and Cartier Wind.

•

In 2010, TransCanada issued approximately $2.4 billion of long-term debt, $0.7 billion of preferred shares and $0.4 billion of common shares, primarily comprising the following:

•

in September 2010, the issuance of US$1.0 billion of senior notes;

•

in June 2010, the issuance of 14 million Series 5 preferred shares at $25 per share, resulting in gross proceeds of $350 million;

•

in June 2010, the issuance of US$1.25 billion of senior notes;

•

in March 2010, the issuance of 14 million Series 3 preferred shares at $25 per share, resulting in gross proceeds of $350 million; and

•

in accordance with its Dividend Reinvestment and Share Purchase Plan (DRP), the issuance of approximately 11 million common shares from treasury in lieu of making cash dividend payments totalling $378 million.

Balance Sheet

•

Total assets increased by $2.8 billion to $46.6 billion in 2010 from 2009, primarily due to investments in capital projects, described above.

•

TransCanada's Shareholders' Equity increased by $1.0 billion to $16.7 billion in 2010 from 2009.

Dividends

•

On February 14, 2011, the Board of Directors of TransCanada increased the quarterly dividend on the Company's outstanding common shares by five per cent to $0.42 per share from $0.40 per share for the quarter ending March 31, 2011. This was the eleventh consecutive year in which the common share dividend was increased. In addition, the Board of Directors declared quarterly dividends of $0.2875 and $0.25 per Series 1 and 3 preferred share, respectively, for the quarter ending March 31, 2011, and $0.275 per Series 5 preferred share for the three-month period ending April 30, 2011.

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

MANAGEMENT'S DISCUSSION AND ANALYSIS        11

Reconciliation of Comparable EBITDA, Comparable EBIT, EBIT and Comparable Earnings to Net Income Applicable to Common Shares

Year ended December 31, 2010 (millions of dollars except per share amounts)		Natural Gas Pipelines		Energy		Corporate		Total
Comparable EBITDA(1)		2,915		1,125		(99	)	3,941
Depreciation and amortization		(977	)	(377	)	–		(1,354	)
Comparable EBIT(1)		1,938		748		(99	)	2,587
Specific items:
	Valuation provision for MGP	(146	)	–		–		(146	)
	Risk management activities	–		(8	)	–		(8	)
EBIT(1)		1,792		740		(99	)	2,433
Interest expense								(701	)
Interest expense of joint ventures								(59	)
Interest income and other								94
Income taxes								(380	)
Non-controlling interests								(115	)
Net Income								1,272
Preferred share dividends								(45	)
Net Income Applicable to Common Shares								1,227
Specific items (net of tax):
	Valuation provision for MGP							127
	Risk management activities							7
Comparable Earnings(1)								1,361
Net Income per Share – Basic								$1.78
Comparable Earnings per Share(1)(2)								$1.97

Year ended December 31, 2009 (millions of dollars except per share amounts)
Comparable EBITDA(1)		3,093		1,131		(117	)	4,107
Depreciation and amortization		(1,030	)	(347	)	–		(1,377	)
Comparable EBIT(1)		2,063		784		(117	)	2,730
Specific items:
	Dilution gain from reduced interest in PipeLines LP	29		–		–		29
	Risk management activities	–		1		–		1
EBIT(1)		2,092		785		(117	)	2,760
Interest expense								(954	)
Interest expense of joint ventures								(64	)
Interest income and other								121
Income taxes								(387	)
Non-controlling interests								(96	)
Net Income								1,380
Preferred share dividends								(6	)
Net Income Applicable to Common Shares								1,374
Specific items (net of tax where applicable):
	Dilution gain from reduced interest in PipeLines LP							(18	)
	Risk management activities							(1	)
	Income tax adjustments							(30	)
Comparable Earnings(1)								1,325
Net Income per Share – Basic								$2.11
Comparable Earnings per Share(1)(2)								$2.03

12        MANAGEMENT'S DISCUSSION AND ANALYSIS

Reconciliation of Comparable EBITDA, Comparable EBIT, EBIT and Comparable Earnings to Net Income Applicable to Common Shares

Year ended December 31, 2008 (millions of dollars except per share amounts)		Natural Gas Pipelines		Energy		Corporate		Total
Comparable EBITDA(1)		3,019		1,210		(104	)	4,125
Depreciation and amortization		(989	)	(258	)	–		(1,247	)
Comparable EBIT(1)		2,030		952		(104	)	2,878
Specific items:
	Calpine bankruptcy distributions	279		–		–		279
	GTN lawsuit settlement	17		–		–		17
	Write-down of Broadwater LNG project costs	–		(41	)	–		(41	)
EBIT(1)		2,326		911		(104	)	3,133
Interest expense								(943	)
Interest expense of joint ventures								(72	)
Interest income and other								54
Income taxes								(602	)
Non-controlling interests								(130	)
Net Income								1,440
Specific items (net of tax where applicable):
	Calpine bankruptcy distributions							(152	)
	GTN lawsuit settlement							(10	)
	Write-down of Broadwater LNG project costs							27
	Income tax adjustments							(26	)
Comparable Earnings(1)								1,279
Net Income per Share – Basic								$2.53
Comparable Earnings per Share(1)(2)								$2.25

	(1)Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA, Comparable EBIT, EBIT, Comparable Earnings and Comparable Earnings per Share.
		2010		2009	2008
	(2)Comparable Earnings per Share(1)	$1.97		$2.03	$2.25
Specific items – per share (net of tax where applicable):
Valuation provision for MGP		(0.18	)	–	–
Risk management activities		(0.01	)	–	–
Dilution gain from reduced interest in PipeLines LP		–		0.03	–
Calpine bankruptcy distributions		–		–	0.27
GTN lawsuit settlement		–		–	0.02
Write-down of Broadwater LNG project costs		–		–	(0.05	)
Income tax adjustments		–		0.05	0.04
	Net Income per Share	$1.78		$2.11	$2.53

MANAGEMENT'S DISCUSSION AND ANALYSIS        13

RESULTS OF OPERATIONS

TransCanada had Net Income of $1,272 million and Net Income Applicable to Common Shares of $1,227 million or $1.78 per share in 2010 compared to $1,380 million and $1,374 million or $2.11 per share, respectively, in 2009. Net Income in 2008 was $1,440 million or $2.53 per share.

Comparable Earnings in 2010, 2009 and 2008 were $1,361 million or $1.97 per share, $1,325 million or $2.03 per share and $1,279 million or $2.25 per share, respectively. Comparable Earnings in 2010 excluded a $127 million after-tax ($146 million pre-tax) valuation provision for advances to the Aboriginal Pipeline Group (APG) for the MGP. Comparable Earnings in 2010 also excluded $7 million of net unrealized after-tax losses ($8 million pre-tax) (2009 – after-tax and pre-tax gains of $1 million; 2008 – nil) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

Comparable Earnings in 2009 also excluded $30 million of favourable income tax adjustments arising from a reduction in the Province of Ontario's corporate income tax rates and an $18 million after-tax ($29 million pre-tax) dilution gain resulting from TransCanada's reduced interest in PipeLines LP after a public offering of PipeLines LP common units in fourth quarter 2009. Comparable Earnings in 2008 excluded $152 million of after-tax gains ($279 million pre-tax) on the disposition of shares received by GTN and Portland from Calpine Corporation (Calpine) bankruptcy distributions, $10 million after tax ($17 million pre-tax) of GTN lawsuit settlement proceeds and a $27 million after-tax ($41 million pre-tax) write-down of costs previously capitalized for the Broadwater liquefied natural gas (LNG) project. Comparable Earnings in 2008 also excluded $26 million of favourable income tax adjustments from an internal restructuring and realization of losses.

Comparable Earnings increased $36 million and decreased $0.06 per share in 2010 from 2009. The increase in Comparable Earnings reflected:

•

decreased Comparable Earnings Before Interest and Taxes (EBIT) from Natural Gas Pipelines primarily due to the negative impact in 2010 of a weaker U.S. dollar on Natural Gas Pipelines' U.S. operations, a decrease in Canadian Mainline revenues due to decreased amounts recovered on a flow-through basis, and reduced revenues for Great Lakes. These decreases were partially offset by decreased operating, maintenance and administration (OM&A) costs, reduced depreciation expense primarily for Great Lakes, increased revenue for Northern Border and higher earnings as a result of an Alberta System revenue requirement settlement;



•

decreased Comparable EBIT from Energy primarily due to lower realized power prices for Western Power and Bruce B, and lower Natural Gas Storage price spreads, partially offset by higher capacity revenues at Ravenswood and incremental earnings from the start up of Halton Hills, Portlands Energy and Kibby Wind;



•

decreased Comparable EBIT loss from Corporate primarily due to lower support services and other corporate costs;



•

decreased Interest Expense primarily due to an increase in capitalized interest relating to Keystone and other capital projects, the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest expense, and Canadian debt maturities, partially offset by interest expense for long-term debt issuances in 2010 and increased losses from changes in the fair value of derivatives used to manage the Company's exposure to fluctuating interest rates;



•

decreased Interest Income and Other due to a higher positive impact in 2009 compared to 2010 of a weakening U.S. dollar on U.S. dollar working capital balances throughout the year;



•

decreased Income Taxes due to reduced pre-tax earnings in 2010, partially offset by positive tax adjustments in 2009;



•

an increase in Non-Controlling Interests due to higher PipeLines LP earnings; and



•

increased preferred share dividends recorded on preferred shares issued in 2010 and third quarter 2009.

Comparable Earnings increased $46 million and decreased $0.22 per share in 2009 compared to 2008. Comparable Earnings reflected an increase in Comparable EBIT primarily as a result of higher realized power prices for Bruce Power,

14        MANAGEMENT'S DISCUSSION AND ANALYSIS

the positive impact in 2009 of a stronger U.S. dollar on Natural Gas Pipelines' U.S. operations, incremental earnings from the start-up of Portlands Energy and the Carleton phase of Cartier Wind, and higher earnings from the Alberta System revenue requirement settlement, partially offset by lower realized power prices in Western Power and U.S. Power, and increased costs for developing the Alaska Pipeline Project.

Net Income per Share and Comparable Earnings per Share in 2010 and 2009 were reduced by the increase in the average number of common shares outstanding following the Company's issuance of 58.4 million common shares in second quarter 2009 as well as common shares issued under the DRP. Net Income per Share and Comparable Earnings per Share in 2009 were also reduced by the issuance of 35.1 million and 34.7 million common shares in fourth quarter 2008 and second quarter 2008, respectively. The shares were issued to partially finance TransCanada's extensive capital growth program and acquisitions.

On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. Natural Gas Pipelines and U.S. Energy EBIT is partially offset by U.S. dollar-denominated interest expense. The resultant net exposure is managed using derivatives, further reducing the Company's exposure to changes in U.S. foreign exchange rates.

Further discussion of these items is included in the Natural Gas Pipelines, Energy, Corporate and Other Income Statement Items sections in 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 TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada'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 TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results, and expected impact of future commitments and contingent liabilities. All forward-looking statements reflect TransCanada'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 TransCanada 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, capacity payments, 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 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 Natural Gas Pipelines, Oil Pipelines, Energy and Risk Management and Financial Instruments sections in this MD&A, which could cause TransCanada'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 TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS        15

NON-GAAP MEASURES

TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, EBIT, Comparable EBIT and Funds Generated from Operations in this MD&A. These measures do not have any standardized meaning prescribed by GAAP. They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada 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 TransCanada's operating performance, liquidity and ability to generate funds to finance operations.

EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, non-controlling interests and preferred share dividends.

Comparable Earnings, Comparable EBITDA and Comparable EBIT comprise Net Income Applicable to Common Shares, EBITDA and EBIT, respectively, 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, Comparable EBITDA and Comparable EBIT, 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, write-downs of assets and investments, and certain fair value adjustments on risk management activities. The Reconciliation of Comparable EBITDA, Comparable EBIT, EBIT and Comparable Earnings to Net Income Applicable to Common Shares table in this MD&A presents a reconciliation of Comparable Earnings, Comparable EBITDA, Comparable EBIT and EBIT to Net Income and Net Income Applicable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the year.

Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. 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 in this MD&A.

OUTLOOK

TransCanada's corporate strategy is to maximize the full-life value of its existing assets and commercial positions, and to pursue long-term growth opportunities that add long-term shareholder value while focusing on core strengths in its pipelines and energy businesses in North America. In 2011 and beyond, TransCanada expects its net income and operating cash flow combined with a strong balance sheet and its proven ability to access capital markets will provide the financial resources needed to complete its $20 billion capital expenditure program, to continue pursuing additional long-term growth opportunities and to create additional value for its shareholders. This strategy will be executed with the same discipline and deliberate manner that characterized TransCanada's capital expenditure program in previous years. In 2011, the Company will continue to advance its capital program and implement its strategy to grow the Natural Gas Pipelines, Oil Pipelines and Energy businesses as discussed in the TransCanada's Strategy section in this MD&A.

In February 2011, TransCanada began recording EBITDA for Keystone's Wood River/Patoka and Cushing Extension phases. Keystone's EBITDA could be impacted by levels of spot volumes transported. Spot volumes transported are

16        MANAGEMENT'S DISCUSSION AND ANALYSIS

affected by customer demand, market pricing, refinery, terminal and pipeline facility outages, and the associated rates charged.

In addition, TransCanada expects a positive impact on its 2011 earnings from assets that were placed in service in 2010 and early 2011 such as NCC, Groundbirch, Bison, Halton Hills and Kibby Wind, and from assets that are expected to be placed in service later in 2011, such as Guadalajara and Coolidge. TransCanada expects that, as these new assets are placed in service in 2011, its consolidated earnings for the year will be affected by a reduction in capitalized interest and an increase in depreciation.

Natural Gas Pipelines' EBIT in 2011 may be affected by the expiry of long-term contracts, variances in throughput volume particularly on the U.S. pipelines, customer settlements and decisions made by applicable regulatory authorities.

Energy's EBIT in 2011 will be affected by the current economic climate which continues to dampen demand growth, market liquidity, as well as commodity and capacity prices. Although a significant portion of Energy's output is sold under long-term contracts, output that is sold under shorter-term forward arrangements or at spot prices will continue to be impacted by the current lower price environment. Energy's EBIT in 2011 will be positively affected by assets that were placed in service during 2010 and assets that are expected to be placed in service in 2011.

TransCanada's earnings from its U.S. Natural Gas Pipelines, Oil Pipelines and Energy businesses are generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TransCanada's Net Income. As new assets are placed in service in the U.S., this exposure is expected to increase as EBIT from U.S. operations increases. This impact is expected to be partially offset by changes in the value of U.S. dollar-denominated interest expense. In addition, the Company expects to continue to use derivatives to manage its resultant net exposure to changes in U.S. dollar exchange rates.

The Company's results in 2011 may be affected 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 and Business Risks sections for Natural Gas Pipelines, Oil Pipelines and Energy. Refer to the Outlook sections in this MD&A for further discussion on the outlook for Natural Gas Pipelines, Oil Pipelines and Energy.

MANAGEMENT'S DISCUSSION AND ANALYSIS        17

The following pipelines are owned 100 per cent by TransCanada unless otherwise stated.

NATURAL GAS PIPELINES

CANADIAN MAINLINE   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   The Alberta System is a 24,187 km (15,029 miles) natural gas transmission system in Alberta and Northeast B.C. that connects with the Canadian Mainline and Foothills natural gas pipelines and with third-party natural gas pipelines.

ANR   ANR is a 17,000 km (10,563 miles) natural gas transmission system that extends from producing fields located in the Texas and Oklahoma panhandle regions, from the offshore and onshore regions of the Gulf of Mexico, and from the U.S. midcontinent region to markets located mainly in Wisconsin, Michigan, Illinois, Indiana and Ohio. ANR also owns and operates regulated underground natural gas storage facilities in Michigan with a total working capacity of 250 Bcf.

18        MANAGEMENT'S DISCUSSION AND ANALYSIS

GTN   GTN is a 2,178 km (1,353 miles) natural gas transmission system that transports WCSB and Rocky Mountain-sourced natural gas to third-party natural gas pipelines and markets in Washington, Oregon and California, and connects with Tuscarora.

FOOTHILLS   Foothills is a 1,241 km (771 miles) transmission system in Western Canada carrying 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.

VENTURES LP   Ventures LP comprises a 161 km (100 miles) pipeline supplying natural gas to the oil sands region near Fort McMurray, Alberta and a 27 km (17 miles) pipeline supplying natural gas to a petrochemical complex at Joffre, Alberta.

BISON   Bison is a 487 km (303 miles) natural gas pipeline that was placed in service in January 2011 and connects supply from the Powder River Basin in Wyoming to Northern Border in North Dakota.

TAMAZUNCHALE   Tamazunchale is a 130 km (81 miles) natural gas pipeline in east central Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi.

NORTH BAJA   Owned 100 per cent by PipeLines LP, North Baja is a natural gas transmission system extending 138 km (86 miles) from Ehrenberg, Arizona to Ogilby, California and connecting with a third-party natural gas pipeline system in Mexico. TransCanada operates North Baja and effectively owns 38.2 per cent of the system through its 38.2 per cent interest in PipeLines LP.

TUSCARORA   Owned 100 per cent by PipeLines LP, Tuscarora is a 491 km (305 miles) pipeline system transporting natural gas from GTN at Malin, Oregon to Wadsworth, Nevada, with delivery points in northeastern California and northwestern Nevada. TransCanada operates Tuscarora and effectively owns 38.2 per cent of the system through its 38.2 per cent interest in PipeLines LP.

NORTHERN BORDER   Owned 50 per cent by PipeLines LP, Northern Border is a 2,250 km (1,398 miles) natural gas transmission system serving the U.S. Midwest. TransCanada operates Northern Border and effectively owns 19.1 per cent of the system through its 38.2 per cent interest in PipeLines LP.

GREAT LAKES   Owned 53.6 per cent by TransCanada and 46.4 per cent by PipeLines LP, Great Lakes is a 3,404 km (2,115 miles) natural gas transmission system serving markets in Eastern Canada and the U.S. Northeast and Midwest regions. TransCanada operates Great Lakes and effectively owns 71.3 per cent of the system through the combination of its direct ownership interest and its 38.2 per cent interest in PipeLines LP.

IROQUOIS   Owned 44.5 per cent by TransCanada, Iroquois is a 666 km (414 miles) pipeline system that 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 TransCanada, TQM is a 572 km (355 miles) pipeline system that connects with the Canadian Mainline near the Québec/Ontario border, transports natural gas to markets in Québec, and connects with Portland. TQM is operated by TransCanada.

PORTLAND   Owned 61.7 per cent by TransCanada, 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 TransCanada.

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

GAS PACIFICO/INNERGY   Owned 30 per cent by TransCanada, Gas Pacifico is a 540 km (336 miles) natural gas pipeline extending from Loma de la Lata, Argentina to Concepción, Chile. TransCanada 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.

GUADALAJARA   The Guadalajara natural gas pipeline is under construction and when completed in 2011 will extend approximately 305 km (190 miles) from Manzanillo to Guadalajara in Mexico.

ALASKA PIPELINE PROJECT   The Alaska Pipeline Project is a proposed natural gas pipeline and treatment plant. The pipeline would extend 2,737 km (1,700 miles) from the treatment plant at Prudhoe Bay, Alaska to Alberta. TransCanada has also proposed an alternate pipeline from Prudhoe Bay to Valdez, Alaska. TransCanada has entered into an agreement with ExxonMobil to jointly advance the project.

MACKENZIE GAS PROJECT   The Mackenzie Gas Project is a proposed natural gas pipeline extending 1,196 km (743 miles) that would connect northern onshore natural gas fields with North American markets. TransCanada has the right to acquire an equity interest in the project.

MANAGEMENT'S DISCUSSION AND ANALYSIS        19

OIL PIPELINE

KEYSTONE   Keystone is a 3,467 km (2,154 miles) crude oil pipeline extending from Hardisty, Alberta, to U.S. markets at Wood River and Patoka in Illinois, and from Steele City, Nebraska to Cushing, Oklahoma. The Wood River/Patoka and Cushing Extension phases commenced commercial operations in June 2010 and February 2011, respectively. In addition, TransCanada plans to construct the U.S. Gulf Coast Expansion, a 2,673 km (1,661 miles) extension and expansion of the pipeline to the U.S. Gulf Coast.

NATURAL GAS PIPELINES

NATURAL GAS PIPELINES – HIGHLIGHTS

•

Comparable EBIT from Natural Gas Pipelines was $1.9 billion in 2010, a decrease of $0.2 billion from $2.1 billion in 2009.

•

The Company invested $1.2 billion in Natural Gas Pipelines capital projects in 2010.

•

Construction was completed on the Bison natural gas pipeline in late 2010 and became operational in January 2011.

•

During 2010, the NEB approved the Company's Alberta System 2010 - 2012 Revenue Requirement Settlement application. The NEB also approved the Company's application for the Alberta System's Rate Design Settlement and the commercial integration of the ATCO Pipelines system with the Alberta System.

•

In March 2010, the Company completed the final phase of the Alberta System's NCC expansion at a total capital cost of approximately $800 million. The Alberta System's Groundbirch pipeline was completed in December 2010 at a total capital cost of approximately $155 million.

•

In December 2010, the NEB issued its decision approving the MGP subject to the project proponents meeting certain conditions and deadlines. Nevertheless, uncertainty persists with respect to the project. Accordingly, at December 31, 2010, the Company recorded a valuation provision of $146 million. TransCanada remains committed to advancing the project.

•

In January 2011, the NEB approved the construction of the approximately $310 million Horn River pipeline, which is expected to commence operations in second quarter 2012.

20        MANAGEMENT'S DISCUSSION AND ANALYSIS

NATURAL GAS PIPELINES – RESULTS

Year ended December 31 (millions of dollars)		2010		2009		2008
Canadian Natural Gas Pipelines
Canadian Mainline		1,054		1,133		1,141
Alberta System		742		728		692
Foothills		135		132		133
Other (TQM, Ventures LP)		50		59		50
Canadian Natural Gas Pipelines Comparable EBITDA(1)		1,981		2,052		2,016
Depreciation and amortization		(715	)	(714	)	(702	)
Canadian Natural Gas Pipelines Comparable EBIT(1)		1,266		1,338		1,314
U.S. Natural Gas Pipelines (in U.S. dollars)
ANR		314		300		327
GTN(2)		171		170		185
Great Lakes(3)		109		120		118
PipeLines LP(2)(4)		99		90		84
Iroquois		67		68		55
Portland(5)		22		22		25
International (Tamazunchale, TransGas, Gas Pacifico/INNERGY)		42		52		38
General, administrative and support costs(6)		(31	)	(17	)	(17	)
Non-controlling interests(7)		173		153		161
U.S. Natural Gas Pipelines Comparable EBITDA(1)		966		958		976
Depreciation and amortization		(256	)	(276	)	(272	)
U.S. Natural Gas Pipelines Comparable EBIT(1)		710		682		704
Foreign exchange		24		105		49
U.S. Natural Gas Pipelines Comparable EBIT(1) (in Canadian dollars)		734		787		753
Natural Gas Pipelines Business Development Comparable EBITDA and EBIT(1)		(62	)	(62	)	(37	)
Natural Gas Pipelines Comparable EBIT(1)		1,938		2,063		2,030
Summary:
Natural Gas Pipelines Comparable EBITDA(1)		2,915		3,093		3,019
Depreciation and amortization		(977	)	(1,030	)	(989	)
Natural Gas Pipelines Comparable EBIT(1)		1,938		2,063		2,030
Specific items:
	Valuation provision for MGP(8)	(146	)	–		–
	Dilution gain from reduced interest in PipeLines LP(3)(9)	–		29		–
	Calpine bankruptcy distributions(10)	–		–		279
	GTN lawsuit settlement	–		–		17
Natural Gas Pipelines EBIT(1)		1,792		2,092		2,326

⁽¹⁾

Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA, Comparable EBIT and EBIT.

MANAGEMENT'S DISCUSSION AND ANALYSIS        21

⁽²⁾

GTN's results include North Baja until July 1, 2009, when North Baja was sold to PipeLines LP.

⁽³⁾

Represents the Company's 53.6 per cent direct ownership interest.

⁽⁴⁾

Effective November 18, 2009, PipeLines LP's results reflected TransCanada's effective ownership in PipeLines LP of 38.2 per cent. From July 1, 2009 to November 17, 2009, TransCanada's ownership interest in PipeLines LP was 42.6 per cent. From January 1, 2008 to June 30, 2009, TransCanada's ownership interest in PipeLines LP was 32.1 per cent.

⁽⁵⁾

Portland's results reflect TransCanada's 61.7 per cent ownership interest.

⁽⁶⁾

Represents General, Administrative and Support Costs associated with certain of the Company's pipelines, including $17 million for Keystone.

⁽⁷⁾

Non-Controlling Interests reflects Comparable EBITDA for the portions of PipeLines LP and Portland not owned by TransCanada.

⁽⁸⁾

The Company recorded a valuation provision of $146 million for its advances to the APG for the MGP, which is discussed further under the heading Opportunities and Developments in the Natural Gas Pipelines section in this MD&A.

⁽⁹⁾

As a result of PipeLines LP issuing common units to the public in 2009, the Company's ownership interest in PipeLines LP was reduced to 38.2 per cent from 42.6 per cent and a dilution gain of $29 million was realized.

⁽¹⁰⁾

GTN and Portland received shares of Calpine with an initial value of $154 million and $103 million, respectively, as a result of the bankruptcy distributions with Calpine. These shares were subsequently sold for an additional gain of $22 million.

Natural Gas Pipelines generated Comparable EBIT of $1,938 million in 2010 compared to $2,063 million in 2009. Comparable EBIT in 2010 excluded a $146 million valuation provision for the Company's advances to the APG for the MGP. Comparable EBIT in 2009 excluded the $29 million dilution gain resulting from TransCanada's reduced interest in PipeLines LP, which occurred as a result of the public issuance of common units by PipeLines LP in November 2009. Comparable EBIT in 2008 was $2,030 million excluding the $279 million of gains received by Portland and GTN from the bankruptcy distributions with Calpine and the $17 million of proceeds received by GTN from a lawsuit settlement with a software supplier.

Wholly Owned Canadian Natural Gas Pipelines Net Income

Year ended December 31 (millions of dollars)	2010	2009	2008
Canadian Mainline	267	273	278
Alberta System	198	168	145
Foothills	27	23	24

NATURAL GAS PIPELINES – FINANCIAL ANALYSIS

Canadian Mainline    The Canadian Mainline is regulated by the NEB under the National Energy Board Act (Canada). The NEB sets tolls that provide TransCanada with the opportunity to recover the costs of transporting natural gas, including a return on average investment base. The Canadian Mainline's EBITDA and net income are affected by changes in investment base, the rate of return on common equity (ROE), the level of deemed common equity, potential incentive earnings and changes in the level of depreciation, financial charges and income taxes recovered in revenue on a flow-through basis.

The Canadian Mainline currently operates under a five-year tolls settlement effective from 2007 through 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 tolls settlement established certain elements of the Canadian Mainline's fixed OM&A costs for each of the five years. The variance between actual and agreed-upon OM&A costs accrued entirely to TransCanada from 2007 to 2009, and was shared equally between TransCanada and its customers in 2010, and will be shared equally in 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 TransCanada and its customers. In 2009, an adjustment charge account was established under a settlement with stakeholders and approved by the NEB to

22        MANAGEMENT'S DISCUSSION AND ANALYSIS

reduce tolls in 2010. In accordance with the terms of the settlement, balances in an adjustment charge account in any given year will be amortized at the composite depreciation rate and included in tolls commencing the following year.

Net income of $267 million in 2010 was $6 million lower than $273 million in 2009. The decrease was primarily the result of lower OM&A savings as a result of cost-sharing with customers and an ROE of 8.52 per cent in 2010 compared to 8.57 per cent in 2009. Net income in 2009 was $5 million lower than $278 million in 2008 as a result of a lower average investment base and lower ROE of 8.57 per cent in 2009 compared to 8.71 per cent in 2008.

Canadian Mainline's Comparable EBITDA of $1,054 million in 2010 was $79 million lower than $1,133 million in 2009, primarily due to reduced revenues as a result of lower income taxes and financial charges in the 2010 tolls, which are recovered on a flow-through basis and do not affect net income. The decrease in financial charges was primarily due to higher-cost debt that matured in 2009 and early 2010. The lower income taxes in 2010 were primarily due to the adjustment charge that decreased taxable income. Comparable EBITDA in 2009 declined $8 million from $1,141 million in 2008. The decrease was primarily due to lower revenues as a result of recovery of a lower overall return on a reduced average investment base and a lower ROE in 2009. The decrease in 2009 revenues was partially offset by higher OM&A cost savings and recovery of higher depreciation.

Alberta System    The Alberta System is also regulated by the NEB, which approves the Alberta System's tolls and revenue requirement. The Alberta System's EBITDA and net income are affected by changes in investment base, the ROE, the level of deemed common equity, potential incentive earnings and changes in the level of depreciation, financial charges and income taxes recovered in revenue on a flow-through basis.

The Alberta System currently operates under the 2010 - 2012 Revenue Requirement Settlement approved by the NEB in September 2010. In October 2010, the NEB approved TransCanada's application to establish final tolls for 2010. In 2008 and 2009, the Alberta System operated under the 2008 - 2009 Revenue Requirement Settlement approved by the Alberta Utilities Commission (AUC) in December 2008. The Alberta System was regulated by the AUC until April 2009.

The 2010 - 2012 Revenue Requirement Settlement established an ROE of 9.70 per cent on deemed common equity of 40 per cent and included an annual fixed amount of $174 million for certain OM&A costs. Variances between actual and agreed-to OM&A costs accrue to TransCanada over the three-year term. All other cost elements of the revenue requirement are treated on a flow-through basis.

The 2008 - 2009 Revenue Requirement Settlement established fixed amounts for ROE, income taxes and certain OM&A costs. Variances between actual costs and those agreed to in the settlement accrued to TransCanada, subject to an ROE and income tax adjustment mechanism that accounted for variances between actual and settlement rate base, and income tax assumptions. The other cost elements of the settlement were treated on a flow-though basis.

The Alberta System's net income of $198 million in 2010 was $30 million higher than $168 million in 2009. The increase reflects an ROE of 9.70 per cent on 40 per cent deemed common equity in 2010 and a higher average investment base, partially offset by lower incentive earnings. Net income in 2009 was $23 million higher than $145 million in 2008 primarily due to higher settlement earnings and a higher average investment base in 2009. The increased average investment base reflected capital expenditures from 2008 to 2010 to expand capacity in response to growing customer demand for service.

MANAGEMENT'S DISCUSSION AND ANALYSIS        23

The Alberta System's Comparable EBITDA of $742 million in 2010 was $14 million higher than $728 million in 2009. The increase reflects an ROE of 9.70 per cent on 40 per cent deemed common equity in 2010 and a higher average investment base, partially offset by lower incentive earnings, and lower financial charges and depreciation recovered on a flow-through basis. Comparable EBITDA in 2009 was $36 million higher than $692 million in 2008 primarily due to increased settlement earnings and a higher average investment base as well as higher revenues as a result of the recovery of higher financial charges, partially offset by lower income taxes.

Foothills    Net income and Comparable EBITDA from Foothills increased $4 million and $3 million, respectively, in 2010 from 2009 primarily due to a Foothills 2010 settlement agreement, which established an ROE of 9.70 per cent on deemed common equity of 40 per cent for 2010 through 2012. Results in 2009 and 2008 were based on the NEB ROE formula of 8.57 per cent and 8.71 per cent, respectively, on deemed common equity of 36 per cent.

Other Canadian Natural Gas Pipelines    Comparable EBITDA from Other Canadian Natural Gas Pipelines was $50 million in 2010 compared to $59 million in 2009. The decrease was primarily due to an adjustment in 2009 related to the NEB decision reached in March 2009 on Trans Québec and Maritimes' (TQM) cost of capital for 2007 and 2008. Comparable EBITDA in 2009 increased $9 million from $50 million in 2008, primarily due to the adjustment in 2009.

ANR    American Natural Resources' (ANR) natural gas storage and transportation services are regulated by the U.S. Federal Energy Regulatory Commission (FERC) and services are provided under tariffs. These tariffs include maximum and minimum rates for services and permit ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline Company rates were established pursuant to a settlement approved by the FERC and became effective beginning in 1997. ANR Storage Company's rates were established pursuant to a settlement approved by the FERC and became effective beginning in 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.

ANR's EBITDA is affected by the contracting and pricing of its existing transportation and storage capacity, expansion projects, delivered volumes and incidental natural gas sales, as well as by costs for providing various services, which include OM&A costs and property taxes. Due to the seasonal nature of its business, ANR's volumes and revenues are generally higher in the winter months.

ANR's Comparable EBITDA in 2010 was US$314 million, an increase of US$14 million compared to US$300 million in 2009, primarily due to lower OM&A costs, partially offset by lower contracted firm long-haul transportation sales and storage revenues as higher regional storage inventories and marginal supply from the U.S. Gulf Coast negatively affected transportation rates and demand for natural gas. Comparable EBITDA in 2009 decreased US$27 million compared to US$327 million in 2008. The decrease was due to lower incidental natural gas sales and higher OM&A costs, partially offset by higher transportation and storage revenues resulting from expansion projects, increased utilization and favourable pricing on existing capacity.

GTN    GTN is regulated by the FERC and is operated in accordance with 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. These rates were effective January 1, 2007. GTN is permitted to discount or negotiate these rates on a non-discriminatory basis. Under the settlement, a five-year moratorium commencing January 1, 2007 was established

24        MANAGEMENT'S DISCUSSION AND ANALYSIS

during which GTN and the settling parties are prohibited from taking certain actions, including any filings to adjust rates. The settlement also requires GTN to file for new rates that are to be in effect no later than January 1, 2014.

GTN's EBITDA is affected by variations in contracted volume levels, volumes delivered and prices charged under the various service types as well as by variations in the costs of providing services, which include OM&A costs and property taxes.

GTN's Comparable EBITDA was US$171 million in 2010, an increase of US$1 million compared to US$170 million in 2009. The increase was primarily due to lower OM&A costs and incremental proceeds accrued in 2010 relating to bankruptcy distributions with Calpine, partially offset by the impact of selling North Baja to PipeLines LP in July 2009 and the write-off of costs in 2010 related to an unsuccessful information systems project. Comparable EBITDA in 2009 decreased US$15 million, compared to US$185 million in 2008, primarily due to the sale of North Baja to PipeLines LP.

Other U.S. Natural Gas Pipelines    Comparable EBITDA for the remainder of the U.S. Natural Gas Pipelines was US$481 million in 2010 and US$488 million in 2009. The decrease was primarily due to lower Great Lakes revenues, and higher general, administrative and support costs primarily related to the start-up of Keystone. Partially offsetting these decreases were increased revenues from Northern Border and higher PipeLines LP earnings in 2010 primarily due to its acquisition of North Baja in July 2009. Comparable EBITDA in 2009 increased US$24 million from US$464 million in 2008, primarily due to PipeLines LP's acquisition of North Baja.

Business Development    Natural Gas Pipelines' Business Development Comparable EBITDA loss in 2010 was consistent with 2009. Comparable EBITDA losses increased to $62 million in 2009 from $37 million in 2008 primarily due to higher business development costs associated with the Alaska Pipeline Project.

Depreciation and Amortization    Depreciation and Amortization for Natural Gas Pipelines was $977 million in 2010, a decrease of $53 million from $1,030 million in 2009. The decrease was primarily due to a weaker U.S. dollar in 2010 and lower depreciation for Great Lakes as a result of the lower depreciation rate in its rate settlement. Depreciation and Amortization increased $41 million to $1,030 million in 2009 from $989 million in 2008 primarily due to the stronger U.S. dollar in 2009.

NATURAL GAS PIPELINES – OPPORTUNITIES AND DEVELOPMENTS

Canadian Mainline and Alberta System 2011 Tolls    In December 2010, the NEB denied TransCanada's initial interim application for 2011 tolls on the Canadian Mainline and Alberta System, which was based on a new three-year agreement with the Canadian Association of Petroleum Producers (CAPP) and was supported by CAPP and certain other stakeholders. In its decision, the NEB concluded that it was not prepared to implement significant changes to the established Canadian Mainline toll design and method of allocating costs on an interim basis, and established Canadian Mainline 2010 tolls as interim tolls for 2011. As a result, TransCanada filed for revised interim tolls on January 25, 2011 based on the existing 2007 - 2011 settlement with customers. If approved, the revised interim tolls will allow for collection of revenues that will more closely reflect TransCanada's costs and forecast throughput in 2011. TransCanada is continuing its discussions with stakeholders with the intent of increasing the level of support for a potential settlement and expects to file a subsequent application for final 2011 tolls for the Canadian Mainline.

Interim tolls for 2011 on the Alberta System were established based on the provisions of the Alberta System 2010 - 2012 Revenue Requirement Settlement approved by the NEB in 2010. TransCanada expects to file for final 2011 tolls on the Alberta System that would reflect the outcome of further discussions with stakeholders with respect to the 2011 tolls and commercial integration of the ATCO Pipelines system.

Canadian Mainline    In 2010, the Canadian Mainline continued to base its return on the NEB's ROE formula in accordance with the terms of the 2007 - 2011 tolls settlement. The 2010 calculated ROE for the Canadian Mainline was 8.52 per cent, a decrease from 8.57 per cent in 2009. The NEB formula ROE in 2011 is 8.08 per cent and, pending the outcome of further discussions with stakeholders, this ROE is applicable for 2011 tolls.

MANAGEMENT'S DISCUSSION AND ANALYSIS        25

Annual tolls on the Canadian Mainline are partially based on projected throughput volumes for the year. Throughput volumes for 2010 were lower than those projected when setting tolls for the year and, as a result, amounts collected through tolls were approximately 15 per cent less than anticipated in 2010. This shortfall is deferred as a Regulatory Asset for accounting purposes as it is expected to be collected in future tolls under the framework regulated by the NEB.

With the objective of maintaining markets and competitive position, TransCanada conducted two open seasons in 2010 to transport Marcellus shale gas volumes on the Canadian Mainline. These open seasons resulted in the execution of precedent agreements in January 2011 to transport a total of approximately 230,000 gigajoules of natural gas per day to eastern Canadian markets. TransCanada is assessing the facilities required to provide the requested service and will begin the work necessary to support a regulatory application in the near future.

Alberta System    In September 2010, the NEB approved the Alberta System's 2010 - 2012 Revenue Requirement Settlement Application. The settlement incorporates a return of 9.70 per cent on 40 per cent deemed common equity and included an annual fixed amount of $174 million for certain OM&A costs. Variances between actual and recoverable OM&A costs accrue to TransCanada over the three-year term. All other cost elements of the revenue requirement are treated on a flow-through basis.

In August 2010, the NEB approved the Company's application for the Alberta System's Rate Design Settlement and the commercial integration of the ATCO Pipelines system with the Alberta System. This approval permits the provision of streamlined natural gas transmission service to Alberta System customers under a new rate structure that reflects the business environment. TransCanada expects commercial and operational integration of the ATCO Pipelines system and the Alberta System to be completed in third quarter 2011.

In October 2010, the NEB approved final rates for the Alberta System that reflect the 2010 - 2012 Revenue Requirement Settlement and the Rate Design Settlement. These settlements are the result of many months of collaborative work with stakeholders.

In March 2010, the final phase of the NCC natural gas pipeline was completed. The NCC consists of a 300 km (186 miles) pipeline and associated compression facilities on the northern section of the Alberta System. The NCC provides capacity to accommodate increasing natural gas supply in northwestern Alberta and northeastern B.C., increasing natural gas demand within Alberta and deliveries of natural gas to Canadian and U.S. markets. The NCC is also expected to materially reduce the quantity of fuel gas consumed by the Alberta System. This project was completed on schedule and under budget at a total capital cost of approximately $800 million.

In December 2010, the Groundbirch pipeline was completed and put in service. Groundbirch extends the Alberta System into northeastern B.C. and connects it to natural gas supplies in the Montney shale gas formation. The project was completed on schedule and under budget at a total capital cost of approximately $155 million. Groundbirch has firm transportation contracts for 1.24 Bcf/d by 2014.

In January 2011, the NEB approved construction of the Horn River pipeline, which will connect new shale gas supply in the Horn River basin north of Fort Nelson, B.C. to the Alberta System. The pipeline, costing approximately $310 million, is scheduled to be operational in second quarter 2012 and has commitments for contracted natural gas of approximately 634 million cubic feet per day (mmcf/d) by 2014.

TransCanada continues to advance further pipeline development in B.C. and Alberta to transport new gas supply. The Company has received requests for additional natural gas transmission service throughout the northwest portion of the Western Canada Sedimentary Basin (WCSB), including the Horn River and Montney areas of B.C. These new requests are expected to result in the need for further extensions and expansions of the Alberta System.

Bison    Bison is a 487 km (303 miles) natural gas pipeline extending from the Powder River Basin in Wyoming and connecting to Northern Border in North Dakota. The pipeline has shipping commitments for approximately 407 mmcf/d and was placed in service in January 2011. The capital cost of Bison was US$630 million.

26        MANAGEMENT'S DISCUSSION AND ANALYSIS

Mexico    In 2010, TransCanada began construction on the US$360 million Guadalajara pipeline in Mexico, which is supported by a 25-year contract for its entire capacity with the Comisión Federal de Electricidad, Mexico's state-owned electric power company. Guadalajara is a natural gas pipeline of approximately 305 km (190 miles) extending from Manzanillo to Guadalajara. The pipeline has an expected in-service date of mid-2011 and was 70 per cent complete at December 31, 2010. TransCanada continues to pursue additional opportunities in Mexico, including the extension or expansion of existing assets.

Great Lakes    In November 2009, the FERC issued an order instituting an investigation pursuant to Section 5 of the Natural Gas Act (Rate Proceeding). The FERC alleged, based on a review of certain historical information, that Great Lakes' revenues might substantially exceed its actual cost of service and, therefore, may be unreasonable. In July 2010, the FERC approved, without modification, a settlement reached among Great Lakes, active participants and the FERC trial staff establishing the terms pursuant to which all matters in the Rate Proceeding would be resolved. As approved, this settlement applies to all current and future shippers on the Great Lakes system.

Under the terms of the settlement, Great Lakes' reservation rates were reduced by eight per cent and annual depreciation expense for Great Lakes' transmission plant were decreased to a rate of 1.48 per cent from a rate of 2.75 per cent. Depreciation rates for other assets decreased or remained unchanged. Rates for interruptible transportation services increased approximately 28 per cent. All terms of the settlement were effective May 1, 2010.

Under the terms of the settlement, Great Lakes' obligation to share interruptible transportation revenues with its shippers was eliminated effective May 1, 2010. Great Lakes also agreed to a new revenue-sharing provision whereby it will share with qualifying shippers 50 per cent of any qualifying revenues collected in excess of US$500 million between November 1, 2010 and October 31, 2012.

ANR    In 2010, ANR connected new sources of natural gas supply from emerging production plays located in the Texas and Oklahoma panhandle regions and connected with new pipelines from shale gas supply in the U.S midcontinent. ANR is focused on attracting and connecting to additional natural gas supply directly or through new pipeline interconnects and on connecting to new or growing markets, particularly in the U.S. Midwest where natural gas-fired electric generation demand is expected to increase over the next several years.

In September 2008, certain portions of ANR's Gulf of Mexico offshore facilities were damaged by Hurricane Ike. The Company estimates its total exposure to damage costs to be approximately US$40 million to US$50 million, mainly to replace, repair and abandon capital assets, including the estimated cost to abandon an offshore platform. Since September 2008, related capital expenditures of US$13 million (2009 – US$11 million) and OM&A costs of US$9 million (2009 – US$7 million) have been incurred. The remaining costs are expected to be incurred primarily in 2011 and 2012. Service on the offshore facilities and related throughput volumes are at pre-hurricane levels.

TQM    In December 2010, the NEB approved TQM's final tolls for 2010 and interim tolls for 2011. These final and interim tolls reflect the terms of an NEB-approved multi-year settlement with TQM's interested parties regarding its annual revenue requirement for 2010 to 2012. The settlement includes an annual revenue requirement comprising fixed and flow-through components. The fixed component includes certain OM&A costs, return on rate base, depreciation and municipal taxes, with variances from actual costs accruing to TQM. In June 2010, the NEB approved TQM's final 2009 tolls based on a 6.4 per cent after-tax weighted average cost of capital on rate base and all the cost components in an NEB-approved three-year partial settlement for 2007 to 2009.

Alaska Pipeline Project    The proposed Alaska Pipeline Project is a 4.5 Bcf/d natural gas pipeline extending 2,737 km (1,700 miles) from a proposed new natural gas treatment plant at Prudhoe Bay, Alaska to Alberta. The pipeline would provide access to diverse markets across North America and is expected to have an estimated capital cost of US$32 billion to US$41 billion. The pipeline construction application filed by TransCanada included provisions to expand capacity to 5.9 Bcf/d through the addition of compressor stations in Alaska and Canada. The estimated capital cost for the project is an increase over previous estimates. The latest estimate is based on increased costs for oil and gas projects from 2007 to 2009 and a significant increase in the estimated cost of building the gas treatment plant at Prudhoe Bay. TransCanada has also proposed an alternate pipeline from Prudhoe Bay to Valdez, Alaska to supply LNG markets. The

MANAGEMENT'S DISCUSSION AND ANALYSIS        27

estimated capital cost of the alternate pipeline is US$20 billion to US$26 billion. TransCanada has entered into an agreement with ExxonMobil to jointly advance the project. A joint project team is developing the engineering, environmental, aboriginal relations and commercial components of the project.

The State of Alaska has issued TransCanada a license to construct the Alaska Pipeline Project under the Alaska Gasline Inducement Act (AGIA). The state determined that TransCanada's application to construct a pipeline under the AGIA was the only proposal that met all of the state's requirements. Under the AGIA, the State of Alaska has agreed to reimburse a share of TransCanada's eligible pre-construction costs, as they are incurred, subject to approval by the state, to a maximum of US$500 million. The State of Alaska reimbursed up to 50 per cent of the eligible costs incurred prior to the close of the first binding open season on July 30, 2010. Commencing July 31, 2010, the state began reimbursing up to 90 per cent of the eligible costs. The reimbursements and project-applicable expenses are shared proportionately with ExxonMobil. In 2010, the Company expensed $34 million related to the project.

On July 30, 2010, the Alaska Pipeline Project concluded its initial open season. The project team continues to work with shippers to resolve the conditions under its control.

Palomar    In December 2008, Palomar Gas Transmission LLC applied to the FERC for a certificate to build a 349 km (217 miles) natural gas pipeline extending from GTN in central Oregon to the Columbia River northwest of Portland. The proposed pipeline would have a capacity of up to 1.3 Bcf/d of natural gas and would be a 50/50 joint venture between GTN and Northwest Natural Gas Co. In May 2010, an underpinning shipper filed a bankruptcy proceeding and subsequently terminated its transportation agreement with Palomar. The partners of Palomar continue to support the project and are engaged in discussions with potential shippers to secure additional shipping commitments for the proposed pipeline.

Mackenzie Gas Project    The MGP is a proposed 1,196 km (743 miles) natural gas pipeline extending from a point near Inuvik, Northwest Territories to the northern border of Alberta, where it would connect to the Alberta System.

TransCanada's involvement with the MGP arises from a 2003 agreement between the Mackenzie Valley APG and the MGP, under which TransCanada agreed to finance the APG's one-third share of the pre-development costs associated with the project. Under the terms of certain MGP agreements, TransCanada holds an option to acquire up to five per cent equity ownership in the MGP at the time of the decision to construct it. In addition, TransCanada gained 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.

At December 31, 2010, the Company had advanced $146 million (2009 – $143 million) on behalf of the APG. These advances constituted a loan to the APG, which would become repayable only after the natural gas pipeline commenced commercial operations. If the project does not proceed, TransCanada has no recourse against the APG for recovery of advances made.

The MGP proponents continue to pursue the required regulatory approvals for the project and the Canadian government's support of an acceptable fiscal framework. In December 2010, the NEB released a decision granting approval of the project's application for a Certificate of Public Convenience and Necessity. The approval contained 264 conditions including the requirement to file an updated cost estimate and report on the decision to construct by the end of 2013 and, further, that construction must commence by December 31, 2015.

Nevertheless, uncertainty persists with respect to the project's ultimate commercial structure and fiscal framework, the timeframes under which the project would proceed and if and when the Company's advances to the APG will be repaid. Accordingly, at December 31, 2010, TransCanada recorded a valuation provision for its $146 million loan to the APG. Future amounts advanced to the APG in furtherance of the MGP will be expensed. TransCanada remains committed to advancing the project.

28        MANAGEMENT'S DISCUSSION AND ANALYSIS

NATURAL GAS PIPELINES – BUSINESS RISKS

Natural Gas Supply, Markets and Competition TransCanada faces competition at both the supply and market ends of its natural gas pipeline systems. This competition comes from other natural gas pipelines accessing supply basins, including the WCSB, and markets served by TransCanada's pipelines as well as from natural gas supplies produced in basins not directly served by the Company. Growth in supply and pipeline infrastructure has increased competition throughout North America. Production has increased in the U.S., driven primarily by shale gas, while WCSB and other natural gas basin production has declined. Lower-cost shale gas in the U.S. has resulted in an increase in competition between supply basins, changes to traditional flow patterns and an increase in choices for customers. This change has contributed to a continued reduction in long-haul, long-term firm contracted capacity and a shift to shorter-distance, short-term firm and interruptible contracts on natural gas pipelines.

Although TransCanada has diversified its natural gas supply sources, many of its North American natural gas pipelines and its transmission infrastructure remain dependent on supply from the WCSB. The WCSB has established natural gas reserves of approximately 60 trillion cubic feet and a reserves-to-production ratio, based on these established reserves, of approximately 11 years at current levels of production. The reserves-to-production ratio is a measure of drilling and production activity that can increase or deplete reserves. Historically, this factor has been unchanged at approximately nine years. More recently, it has increased to 11 years as production from the WCSB has declined due to reduced drilling activity in the basin. The reduced drilling activity is a result of lower prices, higher supply costs and competition for capital from other North American gas production basins that have lower exploration costs. Drilling levels in the WCSB are expected to recover in the future, assuming natural gas prices increase and finding and development costs continue to improve. As part of the Alberta government's competitiveness review, the existing oil and gas royalty framework was substantially revamped. These changes are expected to increase investment in the WCSB, which should also support increased activity levels. TransCanada expects there will be excess natural gas pipeline capacity from the WCSB to markets outside Alberta for the foreseeable future as a result of capacity expansions on natural gas pipelines over the past decade, competition from other pipelines and supply basins, and significant growth in natural gas consumption within Alberta driven primarily by oil sands and electricity generation requirements.

TransCanada's Alberta System is the major natural gas gathering and transportation system for the WCSB, connecting most of the natural gas processing plants in Western Canada to domestic and export markets. Despite reduced overall drilling levels, increased drilling rates in certain areas of the WCSB have resulted in the need for new natural gas transmission infrastructure. Drilling activity has increased in northwestern Alberta and northeastern B.C. as producers develop projects to access deeper multi-zone reserves, unconventional gas shale and tight sands utilizing horizontally-drilled wells in combination with multi-stage hydraulic fracturing stimulation techniques. Recently, shale gas production in northeastern B.C. has emerged as a significant natural gas supply source. TransCanada forecasts approximately 5 Bcf/d of total production from the Montney and Horn River shale gas sources by 2020, however, achieving this level will depend on natural gas prices as well as producer economics in the basin. The production from these two natural gas zones is approximately 1 Bcf/d. TransCanada recently commissioned the Groundbirch pipeline, its first B.C. pipeline extension to serve the Montney shale gas formation. In addition, the Company received approval in January 2011 to construct a major extension of its Alberta System that will allow emergent unconventional B.C. gas production from the Horn River shale gas formation to be transported to markets served by TransCanada's pipeline systems.

Demand for WCSB-sourced natural gas in Eastern Canada and the U.S. Northeast decreased in 2010, largely as a result of a diversification of supply sources. However, demand for natural gas in TransCanada's key eastern markets served by the Canadian Mainline is expected to increase over time, particularly to meet the expected growth in natural gas-fired power generation. There are opportunities to increase market share in Canadian domestic and U.S. export markets, however, TransCanada expects to continue to face significant competition in these markets. 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 TransCanada's systems are now able to receive supplies from new natural gas pipelines that source U.S. and Atlantic Canada supplies. In recent years, the Canadian Mainline has experienced reductions in volumes originating at the Alberta border and in Saskatchewan, which have been partially

MANAGEMENT'S DISCUSSION AND ANALYSIS        29

offset by increases in volumes originating at points east of Saskatchewan. These reductions in both volumes and distance transported have resulted in an increase in Canadian Mainline tolls that adversely affects its competitive position.

ANR's directly connected natural gas supply is primarily sourced from the U.S. Gulf Coast and midcontinent regions which are also served by competing interstate and intrastate natural gas pipelines. The U.S. Gulf Coast is highly competitive given its extensive natural gas pipeline network. ANR is one of many pipelines competing for new and existing production in this region. ANR must also compete for interconnects with and supply from pipelines originating within the growing U.S. midcontinent shale gas formations and the Rocky Mountain production regions.

ANR competes for market share with other natural gas pipelines and storage operators in its primary markets in the U.S. Midwest. Lower natural gas prices could reduce drilling activity and reduce the supply growth that has been fuelling the expansion of pipeline infrastructure in the U.S. midcontinent. As transportation capacity becomes more abundant, lower natural gas prices and supply could negatively affect the value of pipeline capacity. ANR's natural gas storage is primarily contracted on a relatively short-term basis and the value of storage services is based on market conditions, which could become unfavourable resulting in reduced rates and terms.

GTN is primarily supplied with natural gas from the WCSB and competes with other interstate pipelines providing natural gas transportation services to markets in the U.S. Pacific Northwest, California and Nevada. These markets also have access to supplies from natural gas basins in the Rocky Mountains and the U.S. Southwest. Historically, natural gas supplies from the WCSB have been competitively priced against supplies from the other regions serving these markets. Increased competing supply sources could negatively affect the transportation value on GTN. Pacific Gas and Electric Company, GTN's largest customer, received California Public Utilities Commission approval to commit to capacity on a competing pipeline project out of the Rocky Mountain basin to the California border. The owner of this competing pipeline has announced it is expected to be in service in 2011.

Regulatory Risk    Regulatory decisions continue to have an impact on the financial returns from existing investments in TransCanada's Canadian natural gas pipelines and are expected to have a similar impact on financial returns from future investments. Through rate applications and negotiated settlements, TransCanada has been able to improve the financial returns of its Canadian natural gas pipeline and their capital structures.

Regulations and decisions issued by U.S. regulatory bodies, particularly the FERC, Environmental Protection Agency (EPA) and Department of Transportation, may have an impact on the financial performance of TransCanada's U.S. pipelines. TransCanada continually monitors existing and proposed regulations to determine their possible impact on its U.S. pipelines.

Throughput Risk    As transportation contracts expire, TransCanada expects its U.S. natural gas pipelines to become more exposed to the risk of reduced throughput and their revenues to become more likely to experience increased variability. Throughput risk is created by supply and market competition, variations in economic activity, weather variability, natural gas pipeline competition and pricing of alternative fuels.

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

NATURAL GAS PIPELINES – OUTLOOK

The Company expects demand for natural gas in North America to increase in the long term, although demand growth is expected to continue to be relatively weak in 2011. TransCanada's Natural Gas Pipelines business will continue to focus on delivering natural gas to growing markets, connecting new supply and progressing development of new infrastructure to connect with natural gas from unconventional supplies such as shale gas, coalbed methane and LNG, and from the north.

30        MANAGEMENT'S DISCUSSION AND ANALYSIS

Reduced throughput and greater use of shorter-distance transportation contracts are the primary factors that continue to put pressure on the Canadian Mainline to increase its tolls. This situation, coupled with the ongoing development and growth of competitive alternative natural gas supply from infrastructure in U.S. shale gas regions, is increasing competitive pressures on the Canadian Mainline. In response, TransCanada continues to work closely with its stakeholders, examining the Canadian Mainline's rate design, business model and available services to develop solutions that would result in higher throughput and revenue as well as lower costs and tolls. TransCanada is also pursuing the connection of new sources of U.S. natural gas supply from the Marcellus shale gas formation to the Canadian Mainline infrastructure to enhance its current markets and competitive position.

TransCanada will continue to focus on operational excellence and collaboration with all stakeholders to achieve negotiated settlements and provision of services that will increase the value of the Company's business.

Most of TransCanada's expansion plans in Canadian natural gas transmission are focused on the Alberta System. TransCanada is actively involved in expanding the Alberta System to serve the growing shale gas regions in northeastern B.C. Additional growth opportunities for the Alberta System include the west and central foothills regions of Alberta.

In the U.S., TransCanada expects unconventional production will continue to be developed from shale gas formations in eastern Texas, northwestern Louisiana, Arkansas, southwestern Oklahoma and the Appalachian Mountain region. Production focus has shifted in the near term toward more oil and hydrocarbon-rich production, which is expected to increase natural gas supply in Texas and North Dakota. Supply from coalbed methane and tight gas sands in the Rocky Mountain region is also expected to grow. The resulting anticipated growth in U.S. supply should provide additional opportunities for TransCanada's U.S. pipelines.

Earnings    Canadian Natural Gas Pipelines' earnings are affected by changes in investment base, ROE, capital structure and terms of toll settlements as approved by the NEB, with the most significant variables being ROE, capital structure and investment base. The Company expects continued growth of the Alberta System investment base as new supply in northeastern B.C. continues to be developed and connected to the Alberta System. TransCanada also anticipates a modest level of investment in its other Canadian natural gas pipelines but expects a continued net decline in the average investment bases of these pipelines as annual depreciation outpaces capital investment. A net decline in the average investment base would have the effect of reducing year-over-year earnings from these assets. Under the current regulatory model, earnings from Canadian natural gas pipelines are not affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contract levels.

The in service of Bison in January 2011 and the expected in service of Guadalajara in mid-2011 will positively impact earnings of U.S. Natural Gas Pipelines. The ability to recontract available capacity at attractive rates 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 TransCanada's U.S. pipelines. EBIT from U.S. Natural Gas Pipelines' operations is also affected by the level of OM&A costs, regulatory decisions and changes in foreign currency exchange rates.

In addition, Natural Gas Pipelines' EBIT is expected to be affected by costs to develop new pipeline projects, including the Alaska Pipeline Project.

Capital Expenditures    Total capital spending for natural gas pipelines was $1.2 billion in 2010. Capital spending for the Company's wholly owned pipelines is expected to be approximately $1.1 billion in 2011.

MANAGEMENT'S DISCUSSION AND ANALYSIS        31

NATURAL GAS THROUGHPUT VOLUMES

(Bcf)	2010	2009	2008
Canadian Mainline(1)	1,666	2,030	2,173
Alberta System(2)	3,447	3,538	3,800
ANR	1,589	1,575	1,619
Foothills	1,446	1,205	1,292
Northern Border(3)	902	706	839
Great Lakes	804	727	784
GTN	802	797	783
Iroquois	343	355	376
TQM	151	164	170
Ventures LP	144	145	165
North Baja	60	96	104
Tamazunchale	52	54	53
Gas Pacifico	51	62	73
Portland	36	37	50
Tuscarora(3)	35	34	30
TransGas	30	28	26

⁽¹⁾

Canadian Mainline's throughput volumes reflect physical deliveries to domestic and export markets. Customer contracting patterns have changed in recent years therefore the Company uses physical deliveries to measure system utilization. Canadian Mainline physical receipts originating at the Alberta border and in Saskatchewan in 2010 were 1,228 Bcf (2009 – 1,579 Bcf; 2008 – 1,898 Bcf).

⁽²⁾

Field receipt volumes for the Alberta System in 2010 were 3,471 Bcf (2009 – 3,578 Bcf; 2008 – 3,843 Bcf).

⁽³⁾

Throughput volumes for Northern Border and Tuscarora reflect scheduled deliveries. Throughput volumes in previous years reflected physical deliveries.

OIL PIPELINES

OIL PIPELINES – HIGHLIGHTS

•

The Company invested $2.7 billion in 2010 to advance Keystone.



•

The first phase of Keystone extending from Hardisty, Alberta to Wood River and Patoka in Illinois began operating at a low operating pressure in June 2010.



•

The second phase extending Keystone from Steele City, Nebraska to Cushing, Oklahoma was placed in service at the beginning of February 2011.

OIL PIPELINES – FINANCIAL ANALYSIS

Although the first phase of Keystone extending from Hardisty, Alberta to Wood River and Patoka in Illinois commenced commercial operations in June 2010, cash flows related to Keystone, other than general, administrative and support costs, were capitalized during 2010. As a condition of the NEB's approval to begin operations, Wood River/Patoka was operating at a reduced maximum operating pressure (MOP) on the Canadian conversion segment of the pipeline, which did not allow the pipeline to run at design pressure and reduced throughput capacity below the initial nominal capacity of 435,000 Bbl/d. After additional in-line inspections were completed, the NEB removed the MOP restriction in December 2010 and the required operational modifications were completed in late January 2011. As a result, the system began operating at design pressure and the Company commenced recording EBITDA for Keystone at the beginning of February 2011.

32        MANAGEMENT'S DISCUSSION AND ANALYSIS

OIL PIPELINES – OPPORTUNITIES AND DEVELOPMENTS

Keystone    The Cushing Extension extends the pipeline to Cushing, Oklahoma and increases nominal capacity to 591,000 Bbl/d if design capacity is achieved. The extension began commissioning in late 2010 and commenced commercial in service at the beginning of February 2011.

After an open season conducted in 2008, Keystone secured additional firm, long-term shipper contracts to expand and extend the system. With these commitments, Keystone filed the necessary regulatory applications in Canada and the U.S. for approval to construct and operate the U.S. Gulf Coast Expansion from Western Canada to the U.S. Gulf Coast, which would provide additional pipeline capacity. In March 2010, the NEB approved the application for the new Canadian facilities required for the U.S. Gulf Coast Expansion. In April 2010, the Department of State, the lead agency for U.S. federal regulatory approvals, issued a Draft Environmental Impact Statement which concluded that the U.S. Gulf Coast Expansion would have limited environmental impact. The regulatory process conducted by the Department of State is continuing within a heightened political environment and opposition to the project has been expressed. However, the Company expects a decision regarding final regulatory approvals in mid to late 2011. Construction on the U.S. Gulf Coast Expansion is expected to begin shortly thereafter.

The capital cost of Keystone, including the U.S. Gulf Coast Expansion, is estimated to be approximately US$13 billion. The US$1 billion increase from the previously estimated capital cost of approximately US$12 billion reflects currency translation, an increase in the actual cost incurred bringing the Wood River/Patoka and Cushing Extension phases to commercial in service and an increase in estimated capital cost associated with the U.S. Gulf Coast Expansion resulting from scope changes, evolving regulatory requirements and permitting delays. At December 31, 2010, US$7.4 billion had been invested, including US$1.4 billion related to the U.S. Gulf Coast Expansion. The remaining US$5.6 billion, US$1.2 billion of which has already been committed, is expected to be invested between now and the in-service date of the expansion, which is expected in 2013. Capital costs related to the construction of Keystone are subject to capital cost risk- and reward-sharing mechanisms with Keystone's long-term committed shippers.

In August 2009, TransCanada purchased ConocoPhillips' remaining interest in Keystone. The purchase gave TransCanada 100 per cent ownership of Keystone.

Three entities, each of which had entered into Transportation Service Agreements for the Cushing Extension, have filed separate Statements of Claim against certain of TransCanada's Keystone subsidiaries in the Alberta Court of Queen's Bench, seeking declaratory relief, or alternatively, damages in varying amounts. One of the claims has been discontinued on a without-cost and without-liability basis. The Company believes the remaining claims to be without merit and will vigorously defend against them.

Marketlink Projects    The Company is pursuing opportunities to transport growing Bakken shale crude oil production from the Williston Basin in Montana and North Dakota to major U.S. refining markets. Following an open season conducted in the second half of 2010, the Company secured firm, five-year shipper contracts totalling 65,000 Bbl/d for its proposed Bakken Marketlink project, which would transport U.S. crude oil from Baker, Montana to Cushing on facilities that form part of the Keystone U.S. Gulf Coast Expansion. With these commitments, TransCanada will file for the necessary regulatory approvals in the U.S. to construct and operate the Bakken Marketlink project. The capital cost of the incremental facilities is expected to be approximately US$140 million and commercial in service is anticipated in 2013.

Following an open season conducted in the second half of 2010, the Company secured contractual support to proceed with the Cushing Marketlink project, which would transport up to 150,000 Bbl/d of crude oil from Cushing to the U.S. Gulf Coast on facilities that form part of the U.S. Gulf Coast Expansion. With these commitments, TransCanada will file for the necessary regulatory approvals in the U.S. to construct and operate the Cushing Marketlink project. Commercial in service is anticipated in 2013.

MANAGEMENT'S DISCUSSION AND ANALYSIS        33

OIL PIPELINES – BUSINESS RISKS

Crude Oil Supply, Markets and Competition    Alberta produces approximately 80 per cent of the crude oil in the WCSB and is the primary source of crude oil supply for Keystone. In 2010, the WCSB produced an estimated 2.6 million Bbl/d, consisting of 1.1 million Bbl/d of conventional crude oil and condensate, and 1.5 million Bbl/d of Alberta oil sands crude oil. The production of conventional crude oil has been declining but has been offset by increases in production from the oil sands. The Alberta Energy Resources Conservation Board estimated in its June 2010 report that there are approximately 170 billion barrels of remaining established reserves in the Alberta oil sands.

In June 2010, CAPP forecast WCSB crude oil supply would increase to 3.1 million Bbl/d by 2015 and to 3.7 million Bbl/d by 2020, indicating future growth in Alberta crude oil production. CAPP estimated spending in the oil sands totalled $13 billion in 2010 and forecasts $15 billion of spending in 2011.

Keystone has contracted a significant portion of its capacity. Keystone will compete for spot market throughput with other crude oil pipelines from Alberta and for new long-term contracts as supply from the WCSB increases.

The Williston Basin, located primarily in North Dakota and Montana, is the primary source of crude oil supply for the Bakken Marketlink project. In 2010, the Williston Basin achieved production rates of nearly 400,000 Bbl/d. TransCanada forecasts production levels will reach approximately 550,000 Bbl/d by 2015 due to growth in Bakken shale oil production.

The Permian Basin, located primarily in western Texas, is the primary source of crude oil for the Cushing Marketlink project. Production in the Permian Basin connected to crude oil storage facilities at Cushing is 900,000 Bbl/d and has been growing by approximately three per cent per year since 2006.

The Bakken Marketlink and Cushing Marketlink projects have contracted a significant amount of capacity. Both projects would compete for spot market throughput with other crude oil pipelines in the Williston Basin, Rocky Mountain and U.S. midcontinent regions and for new long-term contracts as supply from connected basins increases.

The markets for crude oil served by TransCanada's Keystone oil pipeline are primarily refiners in the U.S. Midwest, midcontinent and Gulf Coast regions. TransCanada will compete with pipelines that deliver WCSB, Williston Basin and Permian Basin crude oil to these refiners through interconnections with other pipelines. Keystone will also compete with U.S. domestically-produced crude oil and imported crude oil for markets in the U.S. Midwest, Midcontinent and Gulf Coast regions.

Regulatory Risk    Regulations and decisions issued by Canadian and U.S. regulatory bodies, particularly the NEB, FERC, EPA and U.S. Department of Transportation, may have a significant impact on the approval, construction, timing and financial performance of TransCanada's crude oil pipelines. TransCanada continuously monitors existing and proposed regulations to determine their possible impact on its Oil Pipelines business.

TransCanada anticipates final U.S. regulatory approvals for the U.S. Gulf Coast Expansion in mid to late 2011. However, if the expansion project as currently proposed is denied regulatory approval, the Company would look to reconfigure all or part of the project and redeploy invested capital to other pipeline opportunities and expense any unmitigated amounts.

Throughput Risk    Throughput risk for TransCanada's crude oil pipelines is dependent primarily on crude oil production levels, market competition for crude oil, refinery activity and variations in economic activity. As transportation contracts expire, TransCanada expects its crude oil pipelines to become more exposed to the risk of reduced throughput and revenues to become more likely to experience increased variability. To assist in managing this risk, TransCanada has contracted a significant portion of capacity. Uncontracted capacity is offered to the market on a spot basis, creating the potential for increased earnings.

Plant Availability    Optimizing and maintaining plant availability is essential to the success of the oil pipelines business. TransCanada has a proven history of achieving high levels of performance through the use of risk-based comprehensive preventative maintenance programs, prudent operating and capital investment, and a skilled workforce. Further mitigation is provided through firm contracts with Keystone's shippers. In the event of a force majeure, Keystone will

34        MANAGEMENT'S DISCUSSION AND ANALYSIS

continue to receive payments for capacity from its firm contract shippers for a limited time. In the event of a loss of capacity that is not due to force majeure, the firm payments for capacity may be reduced by the extent of the reduced capacity. Unexpected plant outages, including unexpected delays in completing planned outages, could result in lower pipeline throughput, resulting in lower sales revenue, reduced capacity payments and margins, and increased maintenance costs.

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 Keystone's long-term committed shippers. 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 Keystone's Wood River/Patoka and Cushing Extension phases will be adjusted by a factor equal to 50 per cent of the percentage change in capital cost. Tolls on the U.S. Gulf Coast Expansion would be adjusted by a factor equal to 75 per cent of the percentage change in capital cost. Capital costs related to the construction of the Bakken Marketlink and Cushing Marketlink projects would not be subject to a capital cost risk- and reward-sharing mechanism with the shippers.

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

OIL PIPELINES – OUTLOOK

North American crude oil demand is expected to remain relatively unchanged in the long term while the availability of foreign sources of supply to North America declines. TransCanada's Oil Pipelines business will continue to focus on contracting and delivering growing crude oil supply to key U.S. markets.

Producers continue to develop new crude oil supply in Western Canada. Several Alberta oil sands projects recently completed or under construction will begin to produce crude oil or will increase crude oil production in 2011 and 2012. Alberta oil sands production is forecast to increase to 2.2 million Bbl/d by 2015 from 1.5 million Bbl/d in 2010 and total Western Canada crude oil supply is projected to grow over the same period to 3.1 million Bbl/d from 2.6 million Bbl/d. The primary market for new crude oil production extends from the U.S. Midwest to the U.S. Gulf Coast and contains a large number of refineries that are capable of handling 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.

The increase in WCSB crude oil exports from Alberta requires access to new markets, including markets in the U.S. Gulf Coast. TransCanada will continue to pursue additional opportunities to transport crude oil from Alberta to U.S. markets.

Production in the Williston Basin is also growing and pipeline capacity in the region is constrained. Major markets for Williston Basin crude oil include the U.S. midcontinent and Midwest, with the U.S. Gulf Coast being a potential growth market. There are several competitive proposals to build take-away pipeline capacity for this region and TransCanada will continue to compete for additional opportunities to transport Williston Basin crude oil to U.S. markets.

Take-away capacity is constrained on the pipelines serving the crude oil storage facilities at Cushing. This situation periodically causes the price of West Texas Intermediate crude oil to be depressed relative to world prices. There are several competitive proposals to build take-away pipeline capacity from this region to the U.S. Gulf Coast. TransCanada will continue to compete for additional opportunities to transport Cushing crude oil to U.S. markets.

TransCanada will continue to focus on operational excellence and collaboration with all stakeholders to provide services that will increase the value of the Company's business.

Earnings    TransCanada began recording EBITDA from the Wood River/Patoka and the Cushing Extension phases beginning in February 2011 when they commenced full operations. TransCanada expects earnings from its crude oil pipelines to increase through 2011, 2012 and 2013 as Keystone's expansion phases and the proposed Marketlink projects begin delivering crude oil. Based on current long-term commitments for Keystone, TransCanada expects to record annual EBITDA of approximately US$1.3 billion, commencing in 2013, assuming a full year of commercial operations servicing both the U.S. Midwest and Gulf Coast markets. If volumes were to increase to the full commercial design of the system, TransCanada would record annual EBITDA of approximately US$1.5 billion. In the future, Keystone capacity could be economically expanded in response to additional market demand.

Capital Expenditures    Total capital spending for Keystone in 2010 was $2.7 billion. Capital spending for Keystone in 2011 is expected to be approximately $1.4 billion.

MANAGEMENT'S DISCUSSION AND ANALYSIS        35

The following Energy assets are owned 100 per cent by TransCanada unless otherwise stated.

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

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

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

SUNDANCE A&B   TransCanada 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 that expires in 2017. TransCanada 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.

36        MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

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

BRUCE POWER   Bruce Power is a nuclear generating facility located northwest of Toronto, Ontario. TransCanada owns 48.8 per cent of Bruce A, which has four 750 MW reactors. Two of these reactors are currently operating and the remaining two are being refurbished. TransCanada 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, combined-cycle power plant in Halton Hills, Ontario which began commercial operations in third quarter 2010.

PORTLANDS ENERGY   A 550 MW natural gas-fired, combined-cycle power plant located in Toronto, Ontario. The plant is 50 per cent owned by TransCanada.

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

CARTIER WIND   The 590 MW Cartier Wind farm consists of five wind power projects located in Québec and is 62 per cent owned by TransCanada. Three of the wind farms, Baie-des-Sables, Anse-à-Valleau and Carleton, are operating and have a total generating capacity of 320 MW. The two remaining wind farms, Gros-Morne and Montagne-Sèche, are under construction and will have total generating capacity of 270 MW.

GRANDVIEW   A 90 MW natural gas-fired cogeneration power plant located in Saint John, New Brunswick.

KIBBY WIND   A 132 MW wind farm located in Kibby and Skinner Townships in Maine. The 66 MW second phase of Kibby Wind was placed in service in October 2010.

TC HYDRO   TC Hydro has a total generating capacity of 583 MW and 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 located in Burrillville, Rhode Island.

RAVENSWOOD   A 2,480 MW multiple-unit generating facility located 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 facility under construction in Coolidge, Arizona.

EDSON   An underground natural gas storage facility connected to the Alberta System near Edson, Alberta. Edson's central processing system is capable of maximum injection and withdrawal rates of 725 mmcf/d of natural gas, and has a working storage capacity of approximately 50 Bcf.

CROSSALTA   A 68 Bcf underground natural gas storage facility connected to the Alberta System near Crossfield, Alberta. CrossAlta's central processing system is capable of maximum injection and withdrawal rates of 550 mmcf/d of natural gas. TransCanada owns 60 per cent of CrossAlta.

MANAGEMENT'S DISCUSSION AND ANALYSIS        37

ENERGY – HIGHLIGHTS

•

Energy's comparable EBIT was $748 million in 2010, a decrease of $36 million from $784 million in 2009.

•

In 2010, the Company invested $1.1 billion in Energy capital projects, including:

•

the 683 MW Halton Hills generating facility, which was fully commissioned in September 2010, on time and on budget;

•

the second phase of the Kibby Wind farm, which was placed in service in October 2010 and included the installation of an additional 22 turbines, ahead of schedule and on budget; and

•

the restart of Bruce A Units 1 and 2 as well as construction of Coolidge and the two remaining wind farms at Cartier Wind.

•

Successful installation of the last of the fuel channel assemblies (FCA) and significant staff demobilization at Bruce A Unit 2 was achieved.

•

Approximately 1,500 MW of generation capacity was under construction and in development at December 31, 2010, at an anticipated total capital cost of approximately $3.2 billion.

38        MANAGEMENT'S DISCUSSION AND ANALYSIS

POWER PLANTS – NOMINAL GENERATING CAPACITY AND FUEL TYPE

			MW	Fuel Type
Canadian Power
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
		Halton Hills	683	Natural gas
		Bécancour	550	Natural gas
		Cartier Wind(3)	365	Wind
		Portlands Energy(4)	275	Natural gas
		Grandview	90	Natural gas
			1,963
	Bruce(5)		2,480	Nuclear
			7,079
U.S. Power
	Ravenswood		2,480	Natural gas/oil
	TC Hydro		583	Hydro
	OSP		560	Natural gas
	Kibby Wind		132	Wind
			3,755
Total Nominal Generating Capacity			10,834

⁽¹⁾

Currently under construction.

⁽²⁾

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

⁽³⁾

Represents TransCanada's 62 per cent share of the total 590 MW project, including 168 MW under construction.

⁽⁴⁾

Represents TransCanada's 50 per cent share of the total 550 MW facility.

⁽⁵⁾

Represents TransCanada's 48.8 per cent proportionate interest in Bruce A and 31.6 per cent proportionate interest in Bruce B.

MANAGEMENT'S DISCUSSION AND ANALYSIS        39

ENERGY – RESULTS

Year ended December 31 (millions of dollars)		2010		2009		2008
Canadian Power
Western Power		220		279		510
Eastern Power(1)		231		220		147
Bruce Power		298		352		275
General, administrative and support costs		(38	)	(39	)	(39	)
Canadian Power Comparable EBITDA(2)		711		812		893
Depreciation and amortization		(242	)	(227	)	(198	)
Canadian Power Comparable EBIT(2)		469		585		695
U.S. Power (in U.S. dollars)
Northeast Power(3)		335		210		256
General, administrative and support costs		(32	)	(40	)	(38	)
U.S. Power Comparable EBITDA(2)		303		170		218
Depreciation and amortization		(116	)	(92	)	(38	)
U.S. Power Comparable EBIT(2)		187		78		180
Foreign exchange		7		8		8
U.S. Power Comparable EBIT(2) (in Canadian dollars)		194		86		188
Natural Gas Storage
Alberta Storage		140		173		152
General, administrative and support costs		(8	)	(9	)	(14	)
Natural Gas Storage Comparable EBITDA(2)		132		164		138
Depreciation and amortization		(15	)	(14	)	(17	)
Natural Gas Storage Comparable EBIT(2)		117		150		121
Business Development Comparable EBITDA and EBIT(2)		(32	)	(37	)	(52	)
Energy Comparable EBIT(2)		748		784		952
Summary:
Energy Comparable EBITDA(2)		1,125		1,131		1,210
Depreciation and amortization		(377	)	(347	)	(258	)
Energy Comparable EBIT(2)		748		784		952
Specific items:
	Risk management activities	(8	)	1		–
	Write-down of Broadwater LNG project costs	–		–		(41	)
Energy EBIT(2)		740		785		911

⁽¹⁾

Includes Halton Hills, Portlands Energy and Carleton effective September 2010, April 2009 and November 2008, respectively.

⁽²⁾

Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA, Comparable EBIT and EBIT.

⁽³⁾

Includes phase one and two of Kibby Wind, and Ravenswood effective October 2009, October 2010 and August 2008, respectively.

40        MANAGEMENT'S DISCUSSION AND ANALYSIS

Energy's Comparable EBIT was $748 million in 2010 compared to $784 million in 2009 and $952 million in 2008. Comparable EBIT in 2010 and 2009 excluded net unrealized losses of $8 million and net unrealized gains of $1 million, respectively, from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities. TransCanada manages its proprietary Natural Gas Storage business by simultaneously entering 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. Fair value adjustments are recorded each period on proprietary natural gas inventory in storage and on the forward contracts, however, these adjustments are not representative of the amounts that will be realized on settlement. U.S. Power focuses on selling power under short- and long-term contracts to wholesale, commercial and industrial customers and manages exposure to fluctuations in spot prices on these power sales either with the purchase of power or the purchase of fuel to generate power from its assets, effectively locking in positive margins. These Natural Gas Storage and U.S. Power contracts provide effective economic hedges which effectively lock in a margin but do not meet the specific criteria required for hedge accounting treatment and, therefore, are recorded at their fair value based on forward market prices for the contracted month of delivery. These forwards are excluded in determining Comparable Earnings as their fair value is not representative of amounts that will be realized on settlement. Comparable EBIT in 2008 excluded the $41 million write-down of costs previously capitalized for the Broadwater LNG project.

ENERGY – FINANCIAL ANALYSIS

Western Power    As at December 31, 2010, Western Power owned or had 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), five natural gas-fired cogeneration facilities and a simple-cycle, natural gas peaking facility under construction in Arizona. The current operating power supply portfolio of Western Power in Alberta comprises approximately 1,700 MW of low-cost, baseload, coal-fired generation 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 and most competitive power generation in the Alberta market area. The Sheerness and Sundance B PPAs expire in 2020, while the Sundance A PPA expires in 2017. Plant operations in Alberta consist of five natural gas-fired cogeneration power plants whose capacity ranges from 27 MW to 165 MW. A portion of the expected output from the Western Power facilities is sold under long-term contracts and the remaining output is subject to fluctuations in the price of power and natural gas.

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 through 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 critical for optimizing Energy's return from its portfolio of power supply and managing risks associated with uncontracted volumes. A portion of Energy's power is sold into the spot market to ensure supply in case of unexpected plant outages. The overall amount of spot market volumes 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 TransCanada 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, 2010, fixed-price power sales contracts to sell approximately 7,400 gigawatt hours (GWh) in 2011 and 6,300 GWh in 2012.

Eastern Power    Eastern Power owns approximately 2,000 MW of power generation capacity, including facilities under construction. Eastern Power's current operating power generation assets are Halton Hills, Bécancour, three Cartier Wind farms, Portlands Energy and Grandview.

MANAGEMENT'S DISCUSSION AND ANALYSIS        41

Halton Hills was placed in service in September 2010 and provides power under a 20-year Clean Energy Supply contract with the Ontario Power Authority (OPA).

Bécancour's entire power output is supplied to Hydro-Québec under a 20-year power purchase contract expiring in 2026. Steam from this facility is sold to an industrial customer for use in commercial processes. Electricity generation at the Bécancour power plant has been suspended since January 2008 as a result of an agreement entered into with Hydro-Québec. Under the agreement, TransCanada continues to receive payments similar to those that would have been received under the normal course of operation. Suspension of electricity generation at the Bécancour power facility is discussed further in the Energy – Opportunities and Developments section in this MD&A.

Three of Cartier Wind's operating wind farms, Carleton, Anse-à-Valleau, and Baie-des-Sables, were placed in service in November 2008, 2007 and 2006, respectively. Output from these wind farms is supplied to Hydro-Québec under 20-year power purchase contracts.

Portlands Energy was placed in service in April 2009. This facility provides power under a 20-year Accelerated Clean Energy Supply contract with the OPA.

Grandview is located on the site of the Irving Oil refinery in Saint John, New Brunswick. TransCanada and Irving Oil are under a 20-year tolling arrangement, which expires in 2025, through which Irving Oil supplies fuel for the 90 MW plant and is contracted to purchase 100 per cent of the plant's heat and electricity output.

Eastern Power is focused on selling power under long-term contracts. In 2008, 2009 and 2010, all of Eastern Power sales volumes were sold under contract and are expected to continue to be 100 per cent sold under contract in 2011 and 2012.

Western and Eastern Canadian Power Comparable EBIT⁽¹⁾⁽²⁾

Year ended December 31 (millions of dollars)		2010		2009		2008
Revenues
	Western power	714		788		1,140
	Eastern power(2)	330		281		175
	Other(3)	84		86		138
		1,128		1,155		1,453
Commodity purchases resold
	Western power	(431	)	(451	)	(517	)
	Other(3)(4)	(26	)	(26	)	(64	)
		(457	)	(477	)	(581	)
Plant operating costs and other		(220	)	(179	)	(215	)
General, administrative and support costs		(38	)	(39	)	(39	)
Comparable EBITDA(1)		413		460		618
Depreciation and amortization		(140	)	(138	)	(124	)
Comparable EBIT(1)		273		322		494

⁽¹⁾

Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

⁽²⁾

Includes Halton Hills, Portlands Energy and Carleton effective September 2010, April 2009 and November 2008, respectively.

⁽³⁾

Includes sales of excess natural gas purchased for generation, sales of thermal carbon black and sales of sulphur in 2008. Effective January 1, 2010, the net impact of derivatives used to purchase and sell natural gas to manage Western and Eastern Power's assets is presented on a net basis in Other Revenues. Comparative results for 2009 and 2008 reflect amounts reclassified to Other Revenues from Other Commodity Purchases Resold.

⁽⁴⁾

Includes the cost of excess natural gas not used in operations.

42        MANAGEMENT'S DISCUSSION AND ANALYSIS

Western and Eastern Canadian Power Operating Statistics⁽¹⁾

Year ended December 31			2010	2009	2008
Sales Volumes (GWh)
Supply
	Generation
		Western Power	2,373	2,334	2,322
		Eastern Power	2,359	1,550	1,069
	Purchased
		Sundance A & B and Sheerness PPAs	10,785	10,603	12,368
		Other purchases	429	529	970
			15,946	15,016	16,729
Sales
	Contracted
		Western Power	10,211	9,944	11,284
		Eastern Power	2,375	1,588	1,232
	Spot
		Western Power	3,360	3,484	4,213
			15,946	15,016	16,729
Plant Availability(2)
	Western Power(3)		95%	93%	87%
	Eastern Power(4)		94%	97%	97%

⁽¹⁾

Includes Halton Hills, Portlands Energy and Carleton effective September 2010, April 2009 and November 2008, respectively.

⁽²⁾

Plant availability represents the percentage of time in a year that the plant is available to generate power regardless of whether it is running.

⁽³⁾

Excludes facilities that provide power to TransCanada under PPAs.

⁽⁴⁾

Bécancour has been excluded from the availability calculation, as power generation at the facility has been suspended since 2008.

Western Power's Comparable EBITDA of $220 million and Power Revenues of $714 million in 2010 decreased $59 million and $74 million, respectively, compared to 2009 primarily due to lower overall realized power prices. Realized prices were negatively affected by lower contracted prices in 2010 compared to 2009 due to the continued impact of the North American economic downturn and the timing of certain unplanned outages that occurred in 2010 during periods of high spot prices. Approximately 25 per cent of Western Power's sales volumes were sold in the spot market in 2010 compared to 26 per cent in 2009.

Eastern Power's Comparable EBITDA of $231 million and Power Revenues of $330 million in 2010 increased $11 million and $49 million, respectively, compared to 2009. These increases were primarily due to incremental earnings from Halton Hills and Portlands Energy, which went into service September 2010 and April 2009, respectively, partially offset by lower contracted revenue from the Bécancour facility. Results from Bécancour are consistent with the expected contracted earnings based on the original electricity supply contract with Hydro-Québec.

Plant Operating Costs and Other, which includes natural gas fuel consumed in power generation, of $220 million in 2010 increased $41 million from 2009 primarily due to incremental fuel consumed at Portlands Energy and Halton Hills.

Western Power's Comparable EBITDA of $279 million and Power Revenues of $788 million in 2009 decreased $231 million and $352 million, respectively, compared to 2008. The decrease was primarily due to lower overall realized

MANAGEMENT'S DISCUSSION AND ANALYSIS        43

prices on reduced volumes of power sold as a result of the economic downturn. Western Power's Comparable EBITDA in 2008 included $23 million related to sulphur sales. Commodity Purchases Resold decreased $66 million in 2009 compared to 2008 primarily due to a reduction in volumes purchased and the expiry of certain retail contracts. Approximately 26 per cent of power sales volumes were sold in the spot market in 2009 compared to 27 per cent in 2008.

Eastern Power's Comparable EBITDA of $220 million and Power Revenues of $281 million in 2009 increased $73 million and $106 million, respectively, compared to 2008. The increase was primarily due to incremental earnings from Portlands Energy, which was placed in service in April 2009, and the Carleton wind farm at Cartier Wind, which went into service in November 2008, as well as higher contracted revenue from the Bécancour facility.

Other Revenues and Other Commodity Purchases Resold were $86 million and $26 million, respectively, in 2009 compared to $138 million and $64 million, respectively, in 2008. The decreases in 2009 reflect the lower price of natural gas purchased for operations but not used. Other Revenues in 2008 included $23 million related to sulphur sales.

Plant Operating Costs and Other, which includes natural gas fuel consumed in power generation, of $179 million in 2009 decreased $36 million from 2008 primarily due to lower prices for natural gas in Western Power, partially offset by incremental fuel consumed at Portlands Energy.

Western Power's plants operated with an average availability of approximately 95 per cent in 2010, 93 per cent in 2009 and 87 per cent in 2008. The increases in 2010 and 2009 were primarily due to the return to service of the Cancarb facility in April 2009.

Bruce Power    Bruce Power is a nuclear power generation facility located northwest of Toronto, Ontario and comprises Bruce A and Bruce B. Bruce A has four 750 MW reactors, two of which are operating and two are being refurbished. The two units being refurbished are expected to resume commercial operations in first quarter and third quarter 2012. Bruce B has four operating reactors with a combined capacity of 3,200 MW. As at December 31, 2010, TransCanada and BPC Generation Infrastructure Trust (BPC), a trust established by the Ontario Municipal Employees Retirement System (OMERS), each owned a 48.8 per cent interest in Bruce A (2009 – 48.8 per cent; 2008 – 48.9 per cent). The remaining 2.4 per cent interest in Bruce A is owned by the Power Workers' Union Trust (PWU), the Society of Energy Professionals Trust (SEP) and the Bruce Power Employee Investment Trust. Bruce A subleases Bruce A Units 1 to 4 from Bruce B. TransCanada, OMERS and Cameco Corporation each own 31.6 per cent of Bruce B, which consists of Units 5 to 8 and the supporting site infrastructure. The remaining interest in Bruce B is owned by PWU and SEP.

44        MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Bruce Power financial results reflect TransCanada's proportionate share of the eight Bruce Power units, six of which were operating:

Bruce Power Results⁽¹⁾
(TransCanada's proportionate share)

Year ended December 31 (millions of dollars unless otherwise indicated)		2010		2009		2008
Revenues(2)		862		883		785
Operating expenses		(564	)	(531	)	(510	)
Comparable EBITDA(1)		298		352		275
Bruce A Comparable EBITDA(1)		91		48		78
Bruce B Comparable EBITDA(1)		207		304		197
Comparable EBITDA(1)		298		352		275
Depreciation and amortization		(102	)	(89	)	(74	)
Comparable EBIT(1)		196		263		201
Bruce Power – Other Information
Plant availability(3)
	Bruce A	81%		78%		82%
	Bruce B	91%		91%		87%
	Combined Bruce Power	88%		87%		86%
Planned outage days
	Bruce A	60		56		91
	Bruce B	70		45		100
Unplanned outage days
	Bruce A	64		82		27
	Bruce B	34		47		65
Sales volumes (GWh)
	Bruce A	5,026		4,894		5,159
	Bruce B	8,184		7,767		7,799
		13,210		12,661		12,958
Results per MWh
	Bruce A power revenues	$65		$64		$62
	Bruce B power revenues(4)	$58		$64		$57
	Combined Bruce Power revenues	$60		$64		$59
Percentage of Bruce B output sold to spot market(5)		82%		43%		33%

⁽¹⁾

Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

⁽²⁾

Revenues include Bruce A fuel cost recoveries of $29 million in 2010 (2009 – $34 million; 2008 – $30 million). Revenues also include Bruce B unrealized losses of $6 million as a result of changes in the fair value of held-for-trading derivatives in 2010 (2009 – $5 million gains; 2008 – $2 million losses).

⁽³⁾

Plant availability represents the percentage of time in a year that the plant is available to generate power regardless of whether it is running.

⁽⁴⁾

Includes revenues received under the floor price mechanism, from contract settlements and deemed generation, and the associated volumes.

⁽⁵⁾

All of Bruce B's output is covered by the floor price mechanism, including volumes sold to the spot market.

MANAGEMENT'S DISCUSSION AND ANALYSIS        45

TransCanada's proportionate share of Bruce Power's Comparable EBITDA decreased $54 million to $298 million in 2010 compared to 2009. Comparable EBITDA in 2010 included the positive net impact of a payment made in 2010 by Bruce B to Bruce A related to amendments made in 2009 to the agreements with the OPA. The net positive impact to TransCanada from the payment reflected TransCanada's higher percentage ownership in Bruce A.

TransCanada's proportionate share of Bruce A's Comparable EBITDA increased $43 million to $91 million in 2010 compared to 2009 primarily as a result of the payment received from Bruce B, lower operating expenses due to a decrease in outage days and higher volumes.

TransCanada's proportionate share of Bruce B's Comparable EBITDA decreased $97 million to $207 million in 2010 compared to 2009. The decrease was primarily due to lower realized prices resulting from expiration of fixed-price contracts at higher prices, the payment made to Bruce A and a higher annual lease expense in 2010, partially offset by higher volumes. Provisions in the lease agreement with Ontario Power Generation allow for a reduction in the annual lease expense if the annual average Ontario spot price for electricity is less than $30 per megawatt hour (MWh). No lease expense reduction was available in 2010 while lease expense was reduced in 2009. The annual average Ontario spot price was $36.25 per MWh in 2010 compared to $29.52 per MWh in 2009 and $48.83 per MWh in 2008.

Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. In both 2010 and 2009, no amounts recorded in revenue were repaid. Bruce B did not recognize into revenue any of the support payments received under the floor price mechanism in 2008 as the average spot price exceeded the floor price.

Bruce Power's Depreciation and Amortization increased $13 million in 2010 compared to 2009 and $15 million in 2009 compared to 2008 primarily due to capital additions.

TransCanada's proportionate share of Bruce Power's Comparable EBITDA of $352 million in 2009 increased $77 million compared to 2008 as a result of higher realized prices and reduced annual lease expense, partially offset by lower volumes and higher operating expenses for Bruce A.

TransCanada's proportionate share of Bruce Power's generation in 2010 increased to 13,210 GWh compared to 12,661 GWh in 2009, partially due to periods in 2009 when the Independent Electricity System Operator (IESO) curtailed certain units at Bruce Power to address surplus baseload generation in Ontario. During these unit curtailments by the IESO, Bruce Power received deemed generation payments at OPA contract prices. Including deemed generation, the combined average availability of Bruce A and Bruce B was 88 per cent in 2010 compared to 87 per cent in 2009 and 86 per cent in 2008.

The overall plant availability percentage in 2011 is expected to be in the mid-80s for the two operating Bruce A units and in the high 80s for the four Bruce B units. Bruce A expects an outage of approximately one week on Unit 3 in July 2011 and, following approval from the Canadian Nuclear Safety Commission, the West Shift Plus outage of approximately six months is scheduled to commence in early November 2011 on Unit 3. The West Shift Plus outage is a key part of the life extension strategy for Unit 3 and is an extension of the West Shift program which was successfully executed in 2009. A maintenance outage of approximately three weeks commenced on February 1, 2011 on Bruce B Unit 8 and outages of approximately seven weeks are scheduled to begin in mid-April 2011 for Bruce B Unit 7 and in mid-October 2011 for Bruce B Unit 5.

Bruce A

Under a contract with the OPA, all of the output from Bruce A is sold at a fixed price per MWh, adjusted annually for inflation on April 1. In addition, fuel costs are recovered from the OPA.

Bruce A Fixed Price

	per MWh
April 1, 2010 – March 31, 2011	$64.71
April 1, 2009 – March 31, 2010	$64.45
April 1, 2008 – March 31, 2009	$63.00

46        MANAGEMENT'S DISCUSSION AND ANALYSIS

Bruce B

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

Bruce B Floor Price

	per MWh
April 1, 2010 – March 31, 2011	$48.96
April 1, 2009 – March 31, 2010	$48.76
April 1, 2008 – March 31, 2009	$47.66

Payments received pursuant to the Bruce B floor price mechanism were previously subject to a recapture payment dependent on annual spot prices over the entire term of the contract. In July 2009, the contract with the OPA was amended making payments received pursuant to the floor price mechanism subject to recapture payments dependent on monthly average spot prices only within each calendar year.

Bruce B enters into fixed-price contracts under which it receives the difference between the contract price and spot price. As a result, Bruce B's 2010 realized price of $58 per MWh reflected revenues recognized from both the floor price mechanism and contract sales. Realized prices were $64 per MWh and $57 per MWh in 2009 and 2008, respectively. Most of the higher-priced contracts entered into in prior years expired at December 31, 2010, which is expected to result in a further reduction in realized prices at Bruce B for future periods. As at December 31, 2010, Bruce B had entered into fixed-price contracts to sell forward approximately 500 GWh for 2011 and 700 GWh for 2012, representing TransCanada's proportionate share.

U.S. Power    U.S. Power owns approximately 3,800 MW of power generation capacity, consisting of Ravenswood, TC Hydro, Ocean State Power (OSP), and Kibby Wind. Ravenswood, located in Queens, New York and acquired in August 2008, is a 2,480 MW natural gas and oil-fired generating facility consisting of multiple units employing steam turbine, combined-cycle and combustion turbine technology with the capacity to serve approximately 20 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 with total generating capacity of 583 MW. OSP, a 560 MW natural gas-fired combined-cycle facility, is the largest power plant in Rhode Island and Kibby Wind is a 132 MW wind farm located in Maine. The first 66 MW phase of Kibby Wind was placed in service in October 2009 and the second 66 MW phase went into service in October 2010.

U.S. Power conducts its business primarily in the deregulated New England, New York and PJM Interconnection power markets, and continues to expand its marketing presence and customer base. PJM Interconnection is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia. U.S. Power focuses on selling power under short- and long-term contracts to wholesale, commercial and industrial customers in these markets. To manage exposure to fluctuations in spot prices, power sales are hedged with the purchase of power or the purchase of fuel to generate power from its assets, effectively locking in positive margins.

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. At present, a series of voluntary forward auctions and a mandatory spot demand curve price setting process are used to determine the price paid to capacity suppliers. There are two annual six-month strip forward auctions and 12 monthly forward auctions in which buyer and seller participation is optional. All remaining available capacity is required to participate in a monthly spot auction in the final week prior to each capacity month. The spot auction clears at a price based on a downward-sloping demand curve, the parameters of which are determined by the NYISO and approved by the FERC. There are separate demand curves for each of three defined capacity zones: Long Island, New York City and Rest of State. The Ravenswood capacity is located in the New York City capacity zone.

MANAGEMENT'S DISCUSSION AND ANALYSIS        47

The New England Power Pool relies on a Forward Capacity Market (FCM) to promote investment in new and existing power resources needed to meet growing consumer demand and maintain a reliable power system. This capacity market operated on a transition basis from 2007 to 2009. During this period, OSP and TC Hydro received capacity transition payments under this mechanism as specified in the FERC-approved FCM settlement. Beginning in June 2010, the price paid for capacity was determined by annual competitive FCM auctions, which are held three years in advance of the applicable capacity year. Future auction results will be affected by actual versus projected demand, the pace of progress in developing new qualifying resources that bid into the auctions and other factors.

U.S. Power Comparable EBIT⁽¹⁾⁽²⁾

Year ended December 31 (millions of U.S. dollars)		2010		2009		2008
Revenues
	Power(3)	1,090		742		1,143
	Capacity	231		169		80
	Other(3)(4)	78		79		42
		1,399		990		1,265
Commodity purchases resold(3)
	Power	(543	)	(309	)	(510	)
	Other(5)	–		–		(257	)
		(543	)	(309	)	(767	)
Plant operating costs and other(4)		(521	)	(471	)	(242	)
General, administrative and support costs		(32	)	(40	)	(38	)
Comparable EBITDA(1)		303		170		218
Depreciation and amortization		(116	)	(92	)	(38	)
Comparable EBIT(1)		187		78		180

⁽¹⁾

Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

⁽²⁾

Includes phases one and two of Kibby Wind, and Ravenswood as of October 2009, October 2010 and August 2008, respectively.

⁽³⁾

Effective January 1, 2010, the net impact of derivatives used to purchase and sell power, natural gas and fuel oil to manage U.S. Power's assets is presented on a net basis in Power Revenues. Comparative results for 2009 and 2008 reflect amounts reclassified to Power Revenues from Commodity Purchases Resold and Other Revenues.

⁽⁴⁾

Includes revenues and costs related to a third-party service agreement at Ravenswood.

⁽⁵⁾

Includes the cost of excess physical natural gas not used in operations, which was purchased under the terms of contracts that expired in 2008.

48        MANAGEMENT'S DISCUSSION AND ANALYSIS

U.S. Power Operating Statistics⁽¹⁾

Year ended December 31		2010	2009	2008
Sales Volumes (GWh)
Supply
	Generation	6,755	5,993	3,974
	Purchased	8,899	5,310	6,020
		15,654	11,303	9,994
Sales
	Contracted	14,485	10,205	9,758
	Spot	1,169	1,098	236
		15,654	11,303	9,994
Plant Availability(2)		86%	79%	75%

⁽¹⁾

Includes phases one and two of Kibby Wind, and Ravenswood as of October 2009, October 2010 and August 2008, respectively.

⁽²⁾

Plant availability represents the percentage of time in a year that the plant is available to generate power regardless of whether it is running.

U.S. Power's Comparable EBITDA was US$303 million in 2010, US$133 million higher than the US$170 million earned in 2009. The increase was primarily due to growth in capacity revenue, higher volumes of power sold in the New England and New York markets, reduced lease costs, higher realized prices and incremental earnings from Kibby Wind.

U.S. Power's Power Revenues of US$1,090 million in 2010 increased US$348 million from US$742 million in 2009 primarily due to higher volumes of power sold, higher realized power prices, and incremental revenues from Kibby Wind. Capacity Revenue of US$231 million in 2010 increased US$62 million from US$169 million in 2009 primarily due to higher capacity prices as a result of the long-planned retirement of a power generating facility owned by the New York Power Authority, which occurred at the end of January 2010. The increases in capacity prices were partially offset by the impact of the Ravenswood Unit 30 outage, which occurred from September 2008 to May 2009.

Power Commodity Purchases Resold increased US$234 million in 2010 compared to 2009 primarily due to an increase in the quantity of power purchased for resale under U.S. Power's power sales commitments to wholesale, commercial and industrial customers in New England.

Plant Operating Costs and Other increased US$50 million in 2010 compared to 2009 primarily due to higher generation volumes and fuel costs, partially offset by reduced lease costs.

Depreciation and Amortization increased US$24 million in 2010 compared to 2009 and includes a full year of depreciation expense for phase one of Kibby Wind.

U.S. Power's Comparable EBITDA was US$170 million in 2009, US$48 million lower than the US$218 million earned in 2008. The decrease was primarily due to reduced power prices and lower margins realized on generation volumes in New England, partially offset by the benefit of forward hedging activities. Lower realized prices were a result of the economic downturn coupled with unseasonably mild weather. These decreases were partially offset by incremental revenue realized on contract sales at higher than average spot market prices in New England and by incremental EBITDA from a full year of operations at the Ravenswood facility, which was acquired in August 2008. On December 31, 2008, Ravenswood fulfilled its obligations under a tolling agreement with a third party that was in place at the time of its acquisition.

MANAGEMENT'S DISCUSSION AND ANALYSIS        49

U.S. Power achieved plant availability of 86 per cent in 2010 compared to 79 per cent in 2009 and 75 per cent in 2008. The fluctuations in availability were primarily due to the unplanned outage of the Ravenswood Unit 30 from September 2008 to May 2009.

In 2010, seven per cent of power sales volumes were sold into the spot market compared to 10 per cent in 2009. As at December 31, 2010, U.S. Power had entered into fixed-price power sales contracts to sell approximately 11,400 GWh in 2011 and 6,600 GWh in 2012, including financial contracts. Certain contracted volumes are dependent on customer usage levels and actual amounts contracted in future periods will depend on market liquidity and other factors.

Natural Gas Storage    TransCanada owns or has rights to 129 Bcf of non-regulated natural gas storage capacity in Alberta, including a 60 per cent ownership interest in CrossAlta, an independently operated storage facility, and 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)	41	550
Third-party storage	38	630
	129	1,905

⁽¹⁾

Represents TransCanada's 60 per cent ownership interest in CrossAlta. Working gas storage capacity can vary due to the amount of base gas in the facility.

The Company's natural gas storage capability helps balance seasonal and short-term supply and demand, and adds flexibility to the delivery of natural gas to markets in Alberta and the rest of North America. Alberta-based storage will continue to serve market needs and could play an important role as additional natural gas supplies are connected to North American markets. Energy's natural gas storage business operates independently from TransCanada's regulated natural gas transmission business and from ANR's regulated storage business, which is included in the Natural Gas Pipelines segment.

TransCanada 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.

Market volatility creates arbitrage opportunities and TransCanada's storage facilities provide customers with the ability to capture value from short-term price movements. At December 31, 2010, TransCanada had contracted approximately 56 per cent of the total 129 Bcf of working gas storage capacity in 2011 and 27 per cent of storage capacity in 2012. Earnings from third-party storage capacity contracts are recognized over the terms of the contracts.

Proprietary natural gas storage transactions consist 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, TransCanada locks in future positive margins, effectively eliminating its exposure to natural gas seasonal price spreads. The seasonal nature of natural gas storage generally results in higher revenue in the winter months.

Natural Gas Storage's Comparable EBITDA in 2010 was $132 million compared to $164 million in 2009. The $32 million decrease in EBITDA was primarily due to decreased proprietary natural gas and third-party storage revenues as a result of lower realized natural gas price spreads. Natural Gas Storage's Comparable EBITDA was $164 million in

50        MANAGEMENT'S DISCUSSION AND ANALYSIS

2009 compared to $138 million in 2008. The increase in 2009 was due to increased storage revenues as a result of higher realized natural gas price spreads.

Business Development    Business Development Comparable EBITDA losses decreased $5 million in 2010 compared to 2009 and $15 million in 2009 compared to 2008 primarily due to the timing of expenses on certain key projects.

ENERGY – OPPORTUNITIES AND DEVELOPMENTS

Bruce Power    In accordance with terms of the 2005 Bruce Power Refurbishment Implementation Agreement (BPRIA) between Bruce Power and the OPA, Bruce A committed to refurbish and restart the idle Units 1 and 2 and refurbish the operating Units 3 and 4 under certain conditions.

In August 2007, Bruce Power and the OPA agreed to amend the BPRIA to expand the scope of the refurbishment contemplated for Unit 4.

In July 2009, Bruce Power and the OPA agreed to amend the BPRIA to include the following:

•

elimination of the requirement that annual net payments received under the Bruce B floor price mechanism be subject to repayment in future years. Instead, amounts received under the floor price mechanism within a calendar year will be subject to repayment only if the monthly average spot price for that year exceeds the floor price;

•

Bruce Power will receive deemed generation payments from the OPA at contract prices in the event Bruce Power's generation is reduced due to system curtailments on the IESO-controlled grid in Ontario;

•

the original terms of the BPRIA provided that the cumulative contingent support payments received by Bruce A, which are equal to the difference between the fixed prices under the BPRIA and spot market prices, were capped at $575 million until both of Units 1 and 2 go into commercial service. The amendment removed the $575 million cap on these contingent support payments and stipulated that the payments would be suspended if both Units 1 and 2 were not in commercial service by December 31, 2011; and

•

the capital cost-sharing mechanism for the refurbishment and restart of Bruce A Units 1 and 2 was amended to eliminate the requirement that the OPA share in any costs for Units 1 and 2 in excess of $3.4 billion. Previously, the OPA was responsible for 25 per cent of cost refurbishment above $3.4 billion through a future adjustment to the fixed price paid to Bruce Power for power generated by the Bruce A units.

In February 2011, the BPRIA was further amended to reflect the following:

•

the suspension date for contingent support payments on Bruce A output was extended to June 1, 2012 from December 31, 2011 and, as a result, all output from Bruce A will receive spot prices from June 1, 2012 until the restart of Units 1 and 2 is complete; and

•

a recovery of costs incurred by Bruce A in connection with development of fuel programs.

Refurbishment work on Units 1 and 2 reached a significant milestone in December 2010 with Atomic Energy of Canada Ltd.'s (AECL) substantial completion of work in connection with Unit 2. Substantial completion of the Unit 2 work resulted in a significant reduction of the AECL workforce and enabled AECL to focus on the installation of FCAs at Unit 1. The installation of these FCAs is the final stage of AECL's work on the reactors. AECL is expected to complete FCA installation on Unit 1 in second quarter 2011.

Subject to regulatory approval, Bruce Power expects to load fuel into Unit 2 in second quarter 2011 and achieve a first synchronization of the generator to the electrical grid by the end of 2011, with commercial operation expected to occur in first quarter 2012. Bruce Power expects to load fuel into Unit 1 in third quarter 2011, with a first synchronization of the generator during first quarter 2012 and commercial operation expected to occur during third quarter 2012. Plant commissioning and testing are underway and will accelerate in second quarter 2011 when construction activities are essentially complete. TransCanada's share of the total capital cost is expected to be approximately $2.4 billion.

As at December 31, 2010, Bruce A had incurred approximately $4.0 billion in costs for the refurbishment and restart of Units 1 and 2, and approximately $0.3 billion for the refurbishment of Units 3 and 4.

MANAGEMENT'S DISCUSSION AND ANALYSIS        51

Halton Hills    The $700 million Halton Hills generating station went into service on September 1, 2010, on time and on budget. Power from the 683 MW natural gas-fired power plant in Halton Hills, Ontario is sold to the OPA under a 20-year Clean Energy Supply contract.

Oakville    In September 2009, the OPA awarded TransCanada a 20-year Clean Energy Supply contract to build, own and operate a 900 MW power generating station in Oakville, Ontario. TransCanada expected to invest approximately $1.2 billion in the natural gas-fired, combined-cycle plant. In October 2010, the Government of Ontario announced that it would not proceed with the Oakville generating station. TransCanada is negotiating a settlement with the OPA that would terminate the Clean Energy Supply contract and compensate TransCanada for the economic consequences associated with the contract's termination.

Kibby Wind    The 66 MW second phase of the Kibby Wind power project went into service in October 2010 and included the installation of an additional 22 turbines, which were all erected ahead of schedule and on budget. The two phases of the project have a combined capacity of 132 MW and total capital cost of US$350 million. A total of 30 MW of energy and associated renewable energy credits produced by Kibby Wind have been sold at fixed prices for a term of 10 years. Phase one of the project received government incentive payments totalling US$44 million under the federal U.S. stimulus package. Phase two is also expected to qualify for payments under the program.

Sundance A    On February 8, 2011, TransCanada received from TransAlta Corporation (TransAlta) notice under the Sundance A PPA that TransAlta has determined that the Sundance 1 and 2 generating units cannot be economically repaired, replaced, rebuilt or restored and that TransAlta therefore seeks to terminate the PPA in respect of those units. TransCanada has not received any information that would validate TransAlta's determination that the units cannot be economically restored to service.

TransCanada has 10 business days from the date of TransAlta's notice to either agree with or dispute TransAlta's determination that the Sundance 1 and 2 generating units cannot be economically repaired, replaced, rebuilt or restored. TransCanada will assess any information provided by TransAlta during this 10-day period. If TransCanada disputes TransAlta's determination, the issue will be resolved using the dispute resolution procedure under the terms of the PPA.

In December 2010, the Sundance 1 and 2 generating units were withdrawn from service for testing. In January 2011, these same units were subject to a force majeure claim by TransAlta under the PPA. TransCanada has received insufficient information to make an assessment of TransAlta's force majeure claim and therefore has recorded revenues under the PPA as though this event was a normal plant outage.

Sundance B    In second quarter 2010, Sundance B Unit 3 experienced an unplanned outage related to mechanical failure of certain generator components that the facility operator, TransAlta, has asserted is a force majeure event. TransCanada has received no information that validates a claim of force majeure and therefore has recorded revenues under the PPA as though this event was a normal plant outage. TransCanada is pursuing the remedies available to it under the terms of the PPA.

Coolidge    At December 31, 2010, construction of the US$500 million Coolidge generating station located near Phoenix, Arizona was approximately 95 per cent complete and commissioning was approximately 80 per cent finished. The 575 MW, simple-cycle, natural gas-fired peaking power facility is expected to be in service in second quarter 2011. All of the power produced by the facility will be sold under a 20-year PPA to the Salt River Project Agricultural Improvement and Power District based in Phoenix.

Cartier Wind    Construction activity on the 212 MW Gros-Morne and 58 MW Montagne-Sèche wind farms continued throughout 2010. The Montagne-Sèche project and the 101 MW first phase of the Gros-Morne project are expected to be operational by the end of 2011. The 111 MW second phase of the Gros-Morne project is expected to be operational by the end of 2012. Gros-Morne and Montagne-Sèche are the fourth and fifth wind farms of the Cartier Wind project in Québec. Once they are complete, Cartier Wind, which is 62 per cent owned by TransCanada, will be capable of producing 590 MW of electricity. All of the power produced by Cartier Wind is sold to Hydro-Québec under a 20-year PPA.

52        MANAGEMENT'S DISCUSSION AND ANALYSIS

Bécancour    In June 2010, Hydro-Québec notified TransCanada it would exercise its option to extend the agreement suspending all electricity generation from the Bécancour power plant through 2011. Under the original agreement signed in June 2009, Hydro-Québec has the option, subject to certain conditions, to extend the suspension on an annual basis until such time as regional electricity demand levels recover. TransCanada will continue to receive payments under the agreement similar to those that would have been received under the normal course of operation.

Ravenswood    Subsequent to closing the acquisition of Ravenswood, TransCanada experienced a forced outage event related to Ravenswood's 972 MW Unit 30. The unit returned to service in May 2009. Insurers of the business interruption and physical damage claim have denied coverage. TransCanada has filed a claim against the insurers to enforce its rights under the insurance policies. Settlement discussions have not resolved the dispute over coverage and litigation proceedings are ongoing.

Power Transmission Line Projects    In May 2010, TransCanada concluded a successful open season for the proposed Zephyr power transmission (Zephyr) project, during which it received signed agreements for the full 3,000 MW of wind-generated capacity with renewable energy developers in Wyoming. Support from key markets and a positive regulatory environment are necessary before the significant siting and permitting activities required to construct the project will commence. TransCanada anticipates making a decision in 2011 on whether to proceed with the project. The Zephyr project is a 1,609 km (1,000 miles), 500 kilovolt, high voltage direct current line (HVDC) expected to cost approximately US$3 billion. TransCanada expects commercial operations would commence in late 2016 or early 2017 if the project proceeds.

TransCanada closed the open season for the Chinook power transmission project in December 2010 without allocating capacity to Montana shippers. TransCanada is still developing the project and will continue discussions with Montana wind developers and other market participants to identify their future transmission requirements. The Chinook transmission project is a 1,609 km (1,000 miles), 500 kilovolt, HVDC transmission line expected to cost approximately US$3 billion.

ENERGY – BUSINESS RISKS

Fluctuating Power and Natural Gas Market Prices    TransCanada operates in competitive power and natural gas markets in North America. Power and natural gas price volatility is caused by fluctuating supply and demand, and by general economic conditions. Sales of uncontracted power volumes into the spot market can be subject to price volatility, directly affecting earnings. To mitigate this risk, Energy commits a significant portion of its supply to sales contracts that are medium-term to long-term while retaining an amount of unsold supply in case of unexpected plant outages and in order to provide operational flexibility in managing the Company's portfolio of wholly owned assets. This unsold supply is subsequently sold under shorter-term forward arrangements or into the spot market and is exposed to fluctuating power and natural gas market prices. Additionally, as power sales contracts expire, new forward contracts are entered into at the prevailing market prices.

Bruce B volumes are subject to a floor price mechanism. When the spot market price is above the floor price, Bruce B's non-contracted volumes are subject to spot price volatility. When spot prices are below the floor price, Bruce B receives the floor price for all of its output. However, Bruce B's results during this period remain subject to the impact of fluctuating spot prices upon the settlement of fixed-price contract sales. The majority of contracted sales at Bruce B expired at December 31, 2010. All Bruce A output is sold into the Ontario wholesale power spot market under a fixed-price contract with the OPA and 100 per cent of Eastern Power sales volumes are sold under long-term contracts. As discussed, all Bruce A output after July 1, 2012 will be subject to spot market pricing if both Units 1 and 2 are not operating, which will continue until such time as both units are operational.

Energy's 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 capacity sales contracts and proprietary natural gas purchases and sales.

MANAGEMENT'S DISCUSSION AND ANALYSIS        53

Capacity Payments    The parameters that drive U.S. Power capacity prices are reset periodically and are affected by a number of factors including the cost of entering the market, reflected in administratively-set demand curves, available supply and fluctuations in forecast demand. With the downturn in the economy, there has been a decrease in demand that, combined with increased supply, has put downward pressure on capacity prices. On January 28, 2011, the FERC issued a decision in a rate filing made by the NYISO relating to the periodic reset of the demand curves. The FERC made several determinations related to such demand curves and ordered the NYISO to make revisions in a compliance filing no later than March 29, 2011. The FERC decision will likely result in higher demand curves that may positively affect capacity prices, but until the compliance filing and additional orders are issued and finalized, it is unclear what the impact on capacity prices will be.

Plant Availability    Optimizing and maintaining plant availability is essential to the continued success of the Energy business. High levels of performance are achieved through the use of risk-based comprehensive preventative maintenance programs, prudent operating and capital investment, and a skilled workforce. Further mitigation is provided through the contractual obligations to TransCanada of its power suppliers under the Sundance and Sheerness PPAs, including the payment of market-based penalties related to availability requirements and by certain sales contracts that share operating risks with the purchaser. In the event a PPA power supplier experiences a verified force majeure event, TransCanada is not entitled to receive market-based penalties for the duration of the verified force majeure event and the monthly capacity payments paid to the supplier are eliminated during the same period. Unexpected plant outages, including unexpected delays in ending planned outages, could result in lower plant output and sales revenue, reduced capacity payments and margins, and increased maintenance costs. At certain times, unplanned outages may require power or natural gas purchases at market prices to ensure TransCanada meets its contractual obligations.

Weather    Extreme temperature and weather events in North America and the Gulf of Mexico often create price volatility and variable demand for power and natural gas. These 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 Energy's wind assets.

Hydrology    TransCanada'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, Capital Cost and Permitting    Energy's construction programs in Québec, Arizona and Ontario, including its investment in Bruce Power, are subject to execution, capital cost and permitting risks.

Regulation of Power Markets    TransCanada operates in both regulated and deregulated power markets. As power markets evolve across North America, there is the potential for regulatory bodies to implement new rules that could negatively affect TransCanada 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, all of which negatively affect the price of capacity or energy, or both. In addition, TransCanada's development projects rely on an orderly permitting process and any disruption to that process can have negative effects on project schedules and costs. TransCanada continues to monitor regulatory issues and regulatory reform and participate in and lead related discussions.

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

ENERGY – OUTLOOK

TransCanada expects that results from its Energy operations in 2011 will be materially consistent with those in 2010. There will be a positive earnings impact from a full year of earnings from Halton Hills and Kibby Wind, and a partial year of earnings from Coolidge, which is expected to be commissioned in second quarter 2011. Output from these plants, as well as a significant portion of output from Energy's other assets, has been sold under long-term contracts and provides a stable earnings base for the Energy business.

54        MANAGEMENT'S DISCUSSION AND ANALYSIS

The Company expects the positive impact on earnings from the new assets coming into service will be tempered by results from Energy facilities whose output is sold under shorter-term forward arrangements or at spot prices. These facilities are expected to be affected to a greater degree by the current economic climate, which continues to have a negative impact on demand, liquidity and commodity and capacity prices.

Other factors such as plant availability, regulatory changes, weather, currency movements and overall stability of the energy industry can also affect 2011 EBIT. Refer to the Energy – Business Risks section in this MD&A for a complete discussion of these and other factors affecting the Energy Outlook.

Capital Expenditures    Energy's total capital expenditures in 2010 were $1.1 billion. Energy's overall capital spending in 2011 is expected to be approximately $1 billion, including cash calls for the Bruce A refurbishment and restart project, and continued construction at Coolidge and Cartier Wind.

CORPORATE

Corporate had a Comparable EBIT loss of $99 million in 2010 compared to losses of $117 million and $104 million in 2009 and 2008, respectively. The decrease in the loss in 2010 was primarily due to lower support services and other corporate costs. The increase in the loss in 2009 compared to 2008 was primarily due to higher support services costs, reflecting a growing asset base.

OTHER INCOME STATEMENT ITEMS

INTEREST EXPENSE

Year ended December 31 (millions of dollars)		2010		2009		2008
Interest on long-term debt(1)
	Canadian dollar-denominated	514		548		523
	U.S. dollar-denominated	680		645		479
	Foreign exchange	20		92		36
		1,214		1,285		1,038
Other interest and amortizations		74		27		46
Capitalized interest		(587	)	(358	)	(141	)
		701		954		943

⁽¹⁾

Includes interest on Junior Subordinated Notes.

Interest Expense in 2010 decreased $253 million to $701 million from $954 million in 2009. Interest on Canadian dollar-denominated debt decreased in 2010 compared to 2009 primarily due to debt maturities. Interest on U.S. dollar-denominated debt increased in 2010 compared to 2009 due to new debt issues of US$1.0 billion in September 2010, US$1.25 billion in June 2010 and US$2.0 billion in January 2009, partially offset by the impact of a weaker U.S. dollar. Other Interest and Amortization expense in 2010 was negatively affected by additional financing charges on committed credit facilities and increased losses from changes in the fair value of derivatives used to manage TransCanada's exposure to fluctuating interest rates, although the majority of these derivatives were settled prior to December 31, 2010. Interest Expense was positively impacted by higher capitalization of interest in 2010 relating to the Company's larger capital spending program primarily for the construction of Keystone and refurbishment and restart of Bruce A.

Interest Expense in 2009 increased $11 million to $954 million from $943 million in 2008. The increase in 2009 compared to 2008 reflected new Canadian debt issues of $700 million in February 2009 and $500 million in August 2008. Interest on U.S. dollar-denominated debt increased in 2009 compared to 2008 due to new debt issues of

MANAGEMENT'S DISCUSSION AND ANALYSIS        55

US$2.0 billion in January 2009 and US$1.5 billion in August 2008. In addition, Interest Expense increased in 2009 compared to 2008 due to the impact of a stronger U.S. dollar on U.S. dollar-denominated interest. Increases in Interest Expense were significantly offset by higher capitalization of interest in 2009 relating to the Company's larger capital spending program primarily for the construction of Keystone, the acquisition of the remaining ownership interest in Keystone from ConocoPhillips, and refurbishment and restart of Bruce A.

Interest Income and Other was $94 million in 2010 compared to $121 million and $54 million in 2009 and 2008, respectively. The year-over-year changes primarily reflected the positive impact of a weakening U.S. dollar on the translation of U.S. dollar working capital balances throughout each year. The increase in 2009 compared to 2008 was also due to higher gains from derivatives used to manage the Company's exposure to foreign exchange rate fluctuation.

Income Taxes were $380 million, $387 million and $602 million in 2010, 2009, and 2008, respectively. The decrease of $7 million in 2010 compared to 2009 was primarily due to reduced pre-tax earnings, partially offset by positive income tax adjustments that reduced income taxes in 2009, including $30 million of favourable adjustments arising from a reduction in the Province of Ontario's corporate income tax rates. In 2010, the Company recorded a benefit in Current Income Taxes with an offsetting provision in Future Income Taxes as a result of bonus depreciation for U.S. income tax purposes on Keystone assets placed in service June 30, 2010. The decrease of $215 million in 2009 compared to 2008 was primarily due to reduced pre-tax earnings, higher income tax savings from income tax differentials and the positive income tax adjustments in 2009.

Non-Controlling Interests were $115 million in 2010 compared to $96 million and $130 million in 2009 and 2008, respectively. The $19 million increase in 2010 compared to 2009 was primarily due to increased PipeLines LP earnings as a result of higher revenues for Northern Border and the acquisition in 2009 of North Baja, partially offset by the impact of a weaker U.S. dollar in 2010. The decrease in 2009 compared to 2008 was primarily due to the non-controlling interests' portion of Portland's Calpine bankruptcy distributions in 2008, partially offset by higher PipeLines LP earnings and the impact of a stronger U.S. dollar in 2009.

LIQUIDITY AND CAPITAL RESOURCES

TransCanada's financial position remains sound and consistent with recent years as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, and provide for planned growth. TransCanada's liquidity position remains solid, underpinned by predictable cash flow from operations, cash balances on hand from preferred share and debt issues, and unutilized committed revolving bank lines of US$1.0 billion, $2.0 billion and US$800 million, maturing in November 2011, December 2012 and December 2012, respectively. These facilities also support the Company's commercial paper programs. In addition, at December 31, 2010, TransCanada's proportionate share of unutilized capacity on committed bank facilities at TransCanada-operated affiliates was $111 million with maturity dates in 2011 and 2012. As at December 31, 2010, TransCanada had remaining capacity of $1.75 billion, $2.0 billion and US$1.75 billion under its equity, Canadian debt and U.S. debt shelf prospectuses, respectively. In lieu of making cash dividend payments, a portion of declared dividends for common and preferred shares are expected to be paid in common shares issued under the Company's DRP. TransCanada's liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section in this MD&A.

SUMMARIZED CASH FLOW

Year ended December 31 (millions of dollars)	2010		2009		2008
Funds generated from operations(1)	3,331		3,080		3,021
(Increase)/decrease in operating working capital	(249	)	(90	)	135
Net Cash Provided by Operations	3,082		2,990		3,156

⁽¹⁾

Refer to the Non-GAAP Measures section in this MD&A for further discussion of Funds Generated from Operations.

56        MANAGEMENT'S DISCUSSION AND ANALYSIS

HIGHLIGHTS

Investing Activities

•

Capital expenditures and acquisitions, including assumed debt, totalled approximately $18 billion over the three-year period ending December 31, 2010.

Dividends

•

TransCanada's Board of Directors declared a $0.42 per common share dividend for the quarter ending March 31, 2011, an increase of five per cent over the previous dividend amount. The Board of Directors also declared regular quarterly dividends of $0.2875 and $0.25 per Series 1 and 3 preferred share, respectively, for the quarter ending March 31, 2011 and $0.275 per Series 5 preferred share for the three-month period ending April 30, 2011.

CASH FLOW AND CAPITAL RESOURCES

Cash Generated from Operations

Net Cash Provided by Operations was $3.1 billion in 2010 compared to $3.0 billion and $3.2 billion in 2009 and 2008, respectively. Net Cash Provided by Operations reflects Funds Generated from Operations, net of changes in operating working capital.

Funds Generated from Operations

Funds Generated from Operations were $3.3 billion in 2010 compared to $3.1 billion and $3.0 billion in 2009 and 2008, respectively. The increase in 2010 compared to 2009 was primarily due to an income tax benefit generated from bonus depreciation for U.S. tax purposes on Keystone assets placed in service on June 30, 2010 and increased cash from earnings. The increase in 2009 compared to 2008 was primarily due to increased cash from earnings, partially offset by higher pension contributions in 2009 and the $152 million after-tax Calpine bankruptcy distributions in 2008.


As at December 31, 2010, TransCanada's current liabilities were $5.7 billion and current assets were $3.2 billion resulting in a working capital deficiency of $2.5 billion. Excluding $2.1 billion of Notes Payable under the Company's commercial paper programs and draws on its line-of-credit facilities, TransCanada's working capital deficiency was $0.4 billion. The Company believes this shortfall can be managed through its ability to generate cash flow from operations as well as its ongoing access to capital markets.

Investing Activities

Capital expenditures totalled $5.0 billion in 2010 compared to $5.4 billion in 2009 and $3.1 billion in 2008. Expenditures in 2010, 2009 and 2008 related primarily to the construction of Keystone, the refurbishment and restart at Bruce A, construction of other new pipeline and power facilities, and the expansion and maintenance of existing pipelines.


In August 2009, the Company purchased ConocoPhillips' remaining interest of approximately 20 per cent in Keystone for US$553 million plus the assumption of US$197 million of short-term debt. In the first seven months of 2009, TransCanada solely funded $1.3 billion of cash calls for Keystone, resulting in the Company acquiring an incremental increase in ownership of approximately 18 per cent for $313 million. In 2008, the Company solely funded $362 million of cash calls, resulting in an incremental increase in ownership of approximately 12 per cent for $176 million. TransCanada's ownership interest in Keystone was approximately 62 per cent at December 31,  2008.


TransCanada acquired Ravenswood from National Grid plc in August 2008 for US$2.9 billion.

MANAGEMENT'S DISCUSSION AND ANALYSIS        57

Financing Activities

In 2010, TransCanada issued $2.4 billion of long-term debt and its proportionate share of long-term debt issued by joint ventures was $177 million. Also in 2010, the Company reduced its long-term debt by $494 million and its proportionate share of the long-term debt of joint ventures by $254 million, and increased notes payable by $474 million. This financing activity included the items noted below.

At December 31, 2010, total committed revolving and demand credit facilities of $5.1 billion were available to support the Company's commercial paper programs and for general corporate purposes. These unsecured credit facilities included the following:

•

a $2.0 billion committed, syndicated, revolving TransCanada PipeLines Limited (TCPL) credit facility, maturing December 2012. The facility was fully available at December 31, 2010;



•

a US$300 million committed, syndicated, revolving credit facility, maturing February 2013. This facility is part of a US$1.0 billion TransCanada PipeLine USA Ltd. (TCPL USA) credit facility established in 2007 to partially finance the ANR acquisition and increased ownership in Great Lakes. At December 31, 2010, this facility was fully drawn;



•

a US$1.0 billion committed, syndicated, revolving, extendible TransCanada Keystone Pipeline, L.P. credit facility, maturing November 2011 with a one-year extension at the option of the borrower. The facility was fully available at December 31, 2010 and supports a commercial paper program dedicated to funding a portion of capital expenditures for Keystone;



•

a US$1.0 billion committed, syndicated, revolving TCPL USA credit facility, maturing December 2012, with a one-year extension at the option of the borrower. At December 31, 2010, US$200 million was drawn on this facility; and



•

demand lines totalling $800 million, which support the issuance of letters of credit and provide additional liquidity. At December 31, 2010, the Company had used approximately $382 million of these demand lines for letters of credit.

In July 2009, TransCanada sold North Baja to PipeLines LP and received aggregate consideration totalling approximately US$395 million, including US$200 million in cash and 6,371,680 common units of PipeLines LP. The transaction resulted in TransCanada's ownership in PipeLines LP increasing to 42.6 per cent. Subsequent to the transaction, TransCanada's ownership in PipeLines LP decreased to 38.2 per cent due to PipeLines LP's public issuance of common units as discussed under the heading 2009 Equity Financing Activities in this section.

The Company is well positioned to fund its existing capital program through its internally-generated cash flow, its DRP and its continued access to capital markets. TransCanada will also continue to examine opportunities for portfolio management, including a role for PipeLines LP, in financing its capital program.

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, which was extendible at the option of the Company for an additional six-month term. 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. In February 2009, the US$255 million was repaid and the facility was cancelled.

2011 and 2010 Long-Term Debt Financing Activities

In September 2010, TCPL issued US$1.0 billion of Senior Notes maturing October 1, 2020 and bearing interest at 3.80 per cent. The notes were issued under a US$4.0 billion debt shelf prospectus filed in December 2009. The net proceeds of this offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

58        MANAGEMENT'S DISCUSSION AND ANALYSIS

In June 2010, TCPL issued US$500 million and US$750 million of Senior Notes maturing on June 1, 2015 and June 1, 2040, respectively, and bearing interest at 3.40 per cent and 6.10 per cent, respectively. These notes were issued under the US$4.0 billion debt shelf prospectus filed in December 2009. The net proceeds of this offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

In January 2011, TCPL retired $300 million of 4.30 per cent Medium-Term Notes.

In February 2010, the Company retired US$120 million of 6.125 per cent Medium-Term Notes and in August 2010, the Company retired $130 million of 10.50 per cent debentures.

In September 2010, TQM retired $100 million of 7.53 per cent Series I bonds and $75 million of 3.906 per cent Series J bonds. In July 2010, TQM issued $100 million of bonds maturing in September 2017 and bearing interest at 4.25 per cent.

In April 2010, Iroquois retired US$200 million of Series I bonds bearing interest at 9.16 per cent and issued US$150 million of bonds maturing in April 2020 and bearing interest at 4.96 per cent.

2009 Long-Term Debt Financing Activities

In December 2009, TCPL filed a debt shelf prospectus qualifying the future issuance of up to US$4.0 billion of debt securities in the U.S. The prospectus replaced a US$3.0 billion debt base shelf prospectus filed in January 2009, which had remaining capacity of US$1.0 billion. At December 31, 2010, the December 2009 shelf prospectus had remaining capacity of US$1.75 billion.

In April 2009, TCPL filed a $2.0 billion Canadian Medium-Term Notes base shelf prospectus to replace a March 2007 $1.5 billion Canadian Medium-Term Notes base shelf prospectus, which expired in April 2009. No amounts have been issued under the April 2009 base shelf prospectus.

In February 2009, TCPL issued $300 million and $400 million of Medium-Term Notes maturing in February 2014 and February 2039, respectively, and bearing interest at 5.05 per cent and 8.05 per cent, respectively. The proceeds were used to fund the Alberta System and Canadian Mainline rate bases. These notes were issued by way of pricing supplements under a $1.5 billion Canadian debt base shelf prospectus filed in March 2007.

In January 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. The proceeds were used to partially fund capital projects, retire maturing debt obligations and for general corporate purposes. These notes were issued by way of a prospectus supplement under a US$3.0 billion debt base shelf prospectus filed by TCPL in January 2009.

In October 2009, the Company retired $250 million of 10.625 per cent debentures.

In February 2009, the Company retired $200 million of 4.10 per cent Medium-Term Notes, and in January 2009, the Company retired US$227 million of 6.49 per cent Medium-Term Notes.

In September 2009, TQM issued $75 million of bonds maturing in September 2014 and bearing interest at 4.05 per cent. In August 2009, TQM retired $100 million of 6.50 per cent Series H bonds.

In August 2009, Northern Border issued US$100 million of Senior Unsecured Notes maturing in August 2016 and bearing interest at 6.24 per cent. In September 2009, Northern Border retired US$200 million of 7.75 per cent Senior Notes.

In May 2009, Iroquois issued US$140 million of Senior Unsecured Notes maturing in May 2019 and bearing interest at 6.63 per cent.

2008 Long-Term Debt Financing Activities

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

MANAGEMENT'S DISCUSSION AND ANALYSIS        59

general corporate purposes. These notes were issued by way of pricing supplement under a $1.5 billion Canadian debt base shelf prospectus filed 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 the notes were used to partially fund the Ravenswood acquisition and for general corporate purposes. The notes were issued by way of a prospectus supplement under a US$2.5 billion debt base shelf prospectus filed in September 2007, which was fully utilized following these issuances.

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.

2010 Equity Financing Activities

In June 2010, TransCanada completed a public offering of 14 million Series 5 cumulative redeemable first preferred shares, including the full exercise of an underwriters' option of two million shares, under its September 2009 base shelf prospectus, discussed below. The preferred shares were issued at a price of $25.00 per share, resulting in gross proceeds of $350 million including the underwriters' option. The holders of the Series 5 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.10 per share, payable quarterly, yielding 4.4 per cent per annum for the initial five and a half year period ending January 30, 2016. The dividend rate will reset on January 30, 2016 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.54 per cent. The Series 5 preferred shares are redeemable by TransCanada on January 30, 2016 and on January 30 of every fifth year thereafter at a price of $25.00 per share plus all accrued and unpaid dividends. The preferred shareholders are eligible to participate in the Company's DRP. The net proceeds of this offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

The Series 5 preferred shareholders have the right to convert their shares into Series 6 cumulative redeemable first preferred shares on January 30, 2016 and on January 30 of every fifth year thereafter. The holders of Series 6 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.54 per cent.

In March 2010, TransCanada completed a public offering of 14 million Series 3 cumulative redeemable first preferred shares, including the full exercise of an underwriters' option of two million shares, under its September 2009 base shelf prospectus, discussed below. The preferred shares were issued at a price of $25.00 per share, resulting in gross proceeds of $350 million including the underwriters' option. The holders of the Series 3 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly, yielding 4.0 per cent per annum for the initial five-year period ending June 30, 2015. The dividend rate will reset on June 30, 2015 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.28 per cent. The Series 3 preferred shares are redeemable by TransCanada on June 30, 2015 and on June 30 of every fifth year thereafter at a price of $25.00 per share plus all accrued and unpaid dividends. The preferred shareholders are eligible to participate in the Company's DRP. The net proceeds of this offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

The Series 3 preferred shareholders have the right to convert their shares into Series 4 cumulative redeemable first preferred shares on June 30, 2015 and on June 30 of every fifth year thereafter. The holders of Series 4 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.28 per cent.

2009 Equity Financing Activities

In September 2009, TransCanada completed a public offering of 22 million Series 1 cumulative redeemable first preferred shares under a prospectus supplement to its September 2009 base shelf prospectus, discussed below, for gross proceeds of $550 million. The holders of the Series 1 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.15 per share, payable quarterly, yielding 4.6 per cent per annum for the initial

60        MANAGEMENT'S DISCUSSION AND ANALYSIS

five-year period ending December 31, 2014. The dividend rate will reset on December 31, 2014 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield plus 1.92 per cent. The preferred shares are redeemable by TransCanada on or after December 31, 2014 at a price of $25.00 per share plus all accrued and unpaid dividends. The preferred shareholders are eligible to participate in the Company's DRP. The net proceeds of the offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

The Series 1 preferred shareholders have the right to convert their shares into Series 2 cumulative redeemable first preferred shares on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 2 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.92 per cent.

In September 2009, TransCanada filed a base shelf prospectus qualifying the future issuance of up to $3.0 billion of common shares, first or second preferred shares, or subscription receipts in Canada and the U.S. until October 2011. This base shelf prospectus replaced the base shelf prospectus filed in July 2008, which was depleted by the common share issuance in June 2009. The Company had $1.75 billion available under the September 2009 prospectus at December 31, 2010.

In June 2009, TransCanada completed a public offering of 58.4 million common shares at a purchase price of $31.50 per share. The issue, including the full exercise of a 15 per cent over-allotment option by the underwriters, resulted in gross proceeds of $1.8 billion. The proceeds were used by TransCanada to partially fund capital projects, including the acquisition of the remaining interest in Keystone, for general corporate purposes and to repay short-term debt.

In November 2009, PipeLines LP completed a public offering of five million common units at a price of US$38.00 per unit, resulting in net proceeds to PipeLines LP of US$182 million. TransCanada contributed an additional US$4 million to maintain its general partnership interest but did not purchase any units. Upon completion of this offering, TransCanada's ownership interest in PipeLines LP was 38.2 per cent.

2008 Equity Financing Activities

In fourth quarter 2008, TransCanada completed a public offering of 35.1 million common shares at a purchase price of $33.00 per share. The issue, including the full exercise of a 15 per cent over-allotment option by the underwriters, resulted in gross proceeds of $1.2 billion. The proceeds of the offering were used by TransCanada to partially fund its capital projects, including Keystone, for general corporate purposes and to repay short-term debt. The common shares were issued under a prospectus supplement to the base shelf prospectus filed in July 2008.

In July 2008, TransCanada filed a base shelf prospectus in Canada and the U.S. qualifying the future issuance of up to $3.0 billion of common shares, preferred shares or subscription receipts in Canada and the U.S. until August 2010. The base shelf prospectus replaced a base shelf prospectus filed in January 2007.

In May 2008, TransCanada completed a public offering of 34.7 million common shares at a purchase price of $36.50 per share. The issue, including the full exercise of a 15 per cent over-allotment option by the underwriters, resulted in gross proceeds of $1.3 billion. These proceeds were used to partially fund the Ravenswood acquisition and the Company's capital projects, and for general corporate purposes. The common shares were issued under a prospectus supplement to the base shelf prospectus filed in January 2007.

Dividend Reinvestment and Share Purchase Plan

TransCanada's Board of Directors has authorized the issuance of common shares from treasury at a discount to participants in the Company's DRP. Under this plan, eligible holders of common or preferred shares of TransCanada and preferred shares of TCPL may reinvest their dividends and make optional cash payments to obtain 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 three per cent in 2009 and 2010, and was reduced to two per cent commencing with the dividends declared in February 2011. The discount was set at two per cent for 2008 and was increased to three per cent commencing with the dividend declared in February 2009. The Company reserves the

MANAGEMENT'S DISCUSSION AND ANALYSIS        61

right to alter the discount or to satisfy its DRP obligations by instead purchasing shares on the open market at any time. In 2010, dividends of $378 million were paid (2009 – $254 million; 2008 – $218 million) through the issuance of 11 million (2009 – 8 million; 2008 – 6 million) common shares from treasury in accordance with the DRP.

Dividends

Cash dividends on common shares amounting to $710 million were paid in 2010 (2009 – $722 million; 2008 – $577 million). In addition, cash dividends of $44 million were paid on preferred shares in 2010 (2009 – $6 million). The decrease in common share dividends paid in 2010 was primarily due to increased participation in the DRP in lieu of cash dividends, which grew to $378 million in 2010 from $254 million in 2009, partially offset by a greater number of shares outstanding and an increase in the dividend per share amount in 2010. The increase in common share dividends paid in 2009 from 2008 was primarily due to a greater number of shares outstanding and an increase in the dividend per share amount in 2009, partially offset by the Company's issuance in 2009 of $254 million (2008 – $218 million) of common shares from treasury under the DRP in lieu of cash dividends. The increase in preferred share dividends paid in 2010 from 2009 was primarily due to a full year of preferred share dividend payments in 2010 on preferred shares issued in September 2009 and the preferred share issuances in 2010.

In February 2011, TransCanada's Board of Directors approved an increase in the quarterly common share dividend payment to $0.42 per share from $0.40 per share for the quarter ending March 31, 2011. This was the eleventh consecutive year in which the dividend was increased, resulting in a per share dividend that has more than doubled since 2000. In addition, the Board of Directors declared quarterly dividends of $0.2875 and $0.25 per Series 1 and 3 preferred share, respectively, for the quarter ending March 31, 2011 and $0.275 per Series 5 preferred share for the three-month period ended April 30, 2011.

CONTRACTUAL OBLIGATIONS

Obligations and Commitments

At December 31, 2010, the Company had $17.9 billion of total long-term debt and $1.0 billion of Junior Subordinated Notes, compared to $16.7 billion of total long-term debt and $1.0 billion of Junior Subordinated Notes at December 31, 2009. TransCanada's share of the total long-term debt of joint ventures, including capital lease obligations, was $0.9 billion at December 31, 2010, compared to $1.0 billion at December 31, 2009. Total Notes Payable, including TransCanada's proportionate share of the notes payable of joint ventures, were $2.1 billion at December 31, 2010 and $1.7 billion at December 31, 2009. TransCanada has provided certain pro-rata guarantees related to the capital lease and performance obligations of Bruce Power and certain other partially owned entities.

CONTRACTUAL OBLIGATIONS

		Payments Due by Period
Year ended December 31 (millions of dollars)	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years
Long-term debt(1)	19,566	943	2,122	2,085	14,416
Capital lease obligations	207	16	38	48	105
Operating leases(2)	784	74	150	142	418
Purchase obligations	9,599	2,393	2,102	1,527	3,577
Other long-term liabilities reflected on the balance sheet	976	16	32	37	891
	31,132	3,442	4,444	3,839	19,407

⁽¹⁾

Includes Junior Subordinated Notes and Long-Term Debt of Joint Ventures, excluding capital lease obligations.

⁽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 2052 with an option to renew certain lease agreements for one to 10 years.

62        MANAGEMENT'S DISCUSSION AND ANALYSIS

TransCanada'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 operating leases in the above table, as these payments are dependent upon plant availability among other factors. TransCanada's share of power purchased under the PPAs in 2010 was $363 million (2009 – $384 million; 2008 – $398 million).

At December 31, 2010, scheduled principal repayments and interest payments related to long-term debt and the Company's proportionate share of the long-term debt of joint ventures were as follows:

PRINCIPAL REPAYMENTS

		Payments Due by Period
Year ended December 31 (millions of dollars)	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years
Long-term debt	17,922	894	2,012	2,034	12,982
Junior subordinated notes	985	–	–	–	985
Long-term debt of joint ventures	659	49	110	51	449
	19,566	943	2,122	2,085	14,416

INTEREST PAYMENTS

		Payments Due by Period
Year ended December 31 (millions of dollars)	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years
Long-term debt	16,721	1,140	2,190	1,973	11,418
Junior subordinated notes(1)	410	63	126	126	95
Long-term debt of joint ventures	381	48	90	80	163
	17,512	1,251	2,406	2,179	11,676

⁽¹⁾

Payments were calculated assuming the notes would be redeemed after 10 years.

MANAGEMENT'S DISCUSSION AND ANALYSIS        63

At December 31, 2010, the Company's approximate future purchase obligations were as follows:

PURCHASE OBLIGATIONS⁽¹⁾

		Payments Due by Period
Year ended December 31 (millions of dollars)	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years
Natural Gas Pipelines
Transportation by others(2)	651	189	197	111	154
Capital expenditures(3)(4)	239	174	65	–	–
Other	2	1	1	–	–
Oil Pipelines
Capital expenditures(3)(5)	1,172	783	389	–	–
Other	49	4	8	8	29
Energy
Commodity purchases(6)	5,467	547	1,158	1,201	2,561
Capital expenditures(3)(7)	567	541	26	–	–
Other(8)	1,420	133	251	204	832
Corporate
Information technology and other	32	21	7	3	1
	9,599	2,393	2,102	1,527	3,577

⁽¹⁾

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

⁽²⁾

Rates are based primarily on known 2010 levels. Beyond 2010, demand rates are subject to change. The purchase 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, the issuance of senior debt and subordinated capital, and through portfolio management.

⁽⁴⁾

Capital expenditures primarily relate to the construction costs of the Alberta System expansion, Guadalajara and other natural gas pipeline projects.

⁽⁵⁾

Capital expenditures relate to the Keystone U.S. Gulf Coast Expansion.

⁽⁶⁾

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.

⁽⁷⁾

Capital expenditures primarily relate to TransCanada's share of the construction and development costs of Bruce Power and Cartier Wind.

⁽⁸⁾

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.

TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business. Potential future commitments are discussed in the Opportunities and Developments sections for Natural Gas Pipelines, Oil Pipelines and Energy in this MD&A.

In 2011, TransCanada expects to make funding contributions of approximately $98 million to its defined benefit pension plans and approximately $28 million to the Company's other post-retirement benefit plans, savings plan and defined contribution pension plans. This is consistent with total funding contributions of $127 million in 2010. TransCanada's proportionate share of funding contributions expected to be made by joint ventures to their respective

64        MANAGEMENT'S DISCUSSION AND ANALYSIS

pension and other post-retirement benefit plans in 2011 is approximately $87 million and $7 million, respectively, compared to total contributions of $58 million in 2010.

The next actuarial valuation for the Company's pension and other post-retirement benefit plans will be carried out as at January 1, 2012. Based on current market conditions, TransCanada expects funding requirements for these plans to continue at the anticipated 2011 level for the next several years to amortize solvency deficiencies in addition to normal costs. The Company's 2011 net benefit cost is expected to increase from 2010 primarily due to a lower projected discount rate. However, future net benefit costs and the amount of funding contributions will be dependent on various factors, including 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. TransCanada's share of these signed commitments is $205 million. The Company expects $193 million and $12 million to be paid in 2011 and 2012, respectively.

Contingencies

TransCanada is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2010, the Company accrued approximately $59 million (2009 – $67 million) related to operating facilities, which represents the estimated amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue.

TransCanada 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

TransCanada and its joint venture partners on Bruce Power, Cameco Corporation and BPC, have severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, a lease agreement and contractor services. The guarantees have terms ranging from 2018 to perpetuity. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the OPA to refurbish and restart Bruce A power generation units. The guarantees were provided as part of the reorganization of Bruce Power in 2005 and have terms ending in 2018 and 2019. TransCanada's share of the potential exposure under these Bruce A and Bruce B guarantees was estimated to be $739 million at December 31, 2010. The fair value of these Bruce Power guarantees is estimated to be $42 million. The Company's exposure under certain of these guarantees is unlimited.

In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, PPA payments and the payment of liabilities. TransCanada's share of the potential exposure under these guarantees was estimated at December 31, 2010 to range from $227 million to a maximum of $539 million. The fair value of these guarantees is estimated to be $9 million, which has been included in Deferred Amounts. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

MANAGEMENT'S DISCUSSION AND ANALYSIS        65

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

FINANCIAL RISKS AND FINANCIAL INSTRUMENTS

Risk Management Overview

TransCanada has exposure to market risk, counterparty credit risk and liquidity risk. TransCanada engages in risk management activities with the objective of protecting earnings, cash flow and, ultimately, shareholder value.

Risk management strategies, policies and limits are designed to ensure TransCanada'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 financial risk management framework. Internal audit personnel assist the Audit Committee in its oversight role by performing regular and ad-hoc reviews of financial risk management controls and procedures, the results of which are reported to the Audit Committee.

Market Risk

The Company constructs and invests in large infrastructure projects, purchases and sells energy 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 strategy to manage the 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. TransCanada 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.

Where possible, derivative financial instruments are designated as hedges, but in some cases derivatives do not meet the specific criteria for hedge accounting treatment and are accounted for at fair value with changes in fair value recorded in Net Income in the period of change. This may expose the Company to increased variability in reported operating results because the fair value of the derivative instruments can fluctuate significantly from period to period. However, the Company enters into the arrangements as they are considered to be effective economic hedges.

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 its overall risk management strategy, the Company commits a 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.

66        MANAGEMENT'S DISCUSSION AND ANALYSIS

•

The Company purchases a portion of the natural gas and oil products required for its power plants or enters into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin. A significant portion of the electricity needed to fulfil the Company's power sales commitments is fulfilled through power generation or purchased through contracts, thereby reducing the Company's exposure to fluctuating commodity prices.

•

The Company enters into offsetting or back-to-back positions using 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 fair value accounting is not required, 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 and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain exemptions.

Natural Gas Storage Commodity Price Risk

TransCanada manages its exposure to seasonal natural gas price spreads in its non-regulated 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. TransCanada 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 natural gas price movements. Fair value adjustments recorded each period on proprietary natural gas inventory in storage and on these forward contracts are not representative of the amounts that will be realized on settlement.

At December 31, 2010, the fair value of proprietary natural gas inventory in storage, measured using a weighted average of forward prices for the following four months less selling costs, was $49 million (2009 – $73 million). The change in fair value of proprietary natural gas inventory in storage in 2010 resulted in pre-tax unrealized losses of $16 million (2009 – gains of $3 million; 2008 – losses of $7 million), which were recorded as a decrease to Revenues and to Inventories. The change in fair value of natural gas forward purchase and sales contracts in 2010 resulted in pre-tax unrealized gains of $6 million (2009 – losses of $2 million; 2008 – gains of $7 million), which were recorded as an increase to Revenues and to Inventories.

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 market interest rates.

TransCanada's earnings from its Natural Gas Pipelines and Energy segments are generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TransCanada's earnings. This foreign exchange impact is partially offset by U.S. dollar-denominated financing costs and by the Company's hedging activities. TransCanada has a greater exposure to U.S. currency fluctuations than in prior years due to growth in its U.S. operations, partially offset by increased levels of U.S. dollar-denominated financing costs.

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 exposures of the Alberta System and Foothills operations. Certain of the realized gains and losses on these derivatives 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS        67

TransCanada has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of 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, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At December 31, 2010, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $9.8 billion (US$9.8 billion) (2009 – $7.9 billion (US$7.6 billion)) and a fair value of $11.3 billion (US$11.4 billion) (2009 – $9.8 billion (US$9.3 billion)). At December 31, 2010, $181 million was included in Intangibles and Other Assets (2009 – $96 million) 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 amounts for the derivatives designated as a net investment hedge were as follows:

Asset/(Liability)

		2010		2009
December 31 (millions of dollars)		Fair Value(1)	Notional or Principal Amount	Fair Value(1)	Notional or Principal Amount
U.S. dollar cross-currency swaps
	(maturing 2011 to 2016)	179	US 2,800	86	US 1,850
U.S. dollar forward foreign exchange contracts
	(maturing 2011)	2	US 100	9	US 765
U.S. dollar options
	(matured in 2010)	–	–	1	US 100
		181	US 2,900	96	US 2,715

⁽¹⁾

Fair values equal carrying values.

VaR Analysis

TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its liquid open positions. VaR represents the potential change in pre-tax earnings over a given holding period for a specified confidence level. The VaR number used by TransCanada is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its liquid open 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.

TransCanada'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 regulated natural gas pipelines, as the nature of the rate-regulated pipeline business reduces the impact of market risks. TransCanada's Board of Directors has established a

68        MANAGEMENT'S DISCUSSION AND ANALYSIS

VaR limit, which is monitored on an ongoing basis as part of the Company's risk management policy. TransCanada's consolidated VaR was $12 million at December 31, 2010 (2009 – $12 million).

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 they will protect it against all material losses.

TransCanada's maximum counterparty credit exposure with respect to financial instruments at the Balance Sheet date, without taking into account security held, consisted of accounts receivable, the fair value of derivative assets and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table located in the Fair Values section below. Letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties that are investment grade. At December 31, 2010, there were no significant amounts past due or impaired.

At December 31, 2010, the Company had a credit risk concentration of $317 million (2009 – $334 million) due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.

TransCanada 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 TransCanada's exposure to non-creditworthy counterparties.

As a level of uncertainty continues to exist in the global financial markets, TransCanada continues to closely monitor and reassess the creditworthiness of its counterparties. This has resulted in TransCanada reducing or mitigating its exposure to certain counterparties where it was deemed warranted and permitted under contractual terms. As part of its ongoing operations, TransCanada must balance its market and counterparty credit risks when making business decisions.

Calpine and certain of its subsidiaries filed for bankruptcy protection in Canada or the U.S. in 2005. Gas Transmission Northwest Corporation (GTNC) and Portland reached agreements with Calpine for allowed unsecured claims in the Calpine bankruptcy. In February 2008, GTNC and Portland received initial distributions of 9.4 million common shares and 6.1 million common shares, respectively, of Calpine, which represented approximately 85 per cent of their agreed-upon claims. In 2008, these shares were 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 were passed onto shippers on these systems in 2008 and 2009. In 2010, the Company accrued an additional pre-tax gain of $15 million related to expected future proceeds with respect to the GTNC and Portland claims.

Liquidity Risk

Liquidity risk is the risk that TransCanada will not be able to meet its financial obligations as they become due. The Company's approach to managing liquidity risk is to ensure that sufficient cash and credit facilities are available to meet its operating, financing and capital expenditure obligations when due, under both normal and stressed economic conditions.

MANAGEMENT'S DISCUSSION AND ANALYSIS        69

Management continuously 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 in the Capital Management section below.

At December 31, 2010, the Company had unutilized committed revolving bank lines of US$1.0 billion, $2.0 billion and US$0.8 billion maturing in November 2011, December 2012 and December 2012, respectively. The Company has also maintained continuous access to the Canadian commercial paper market on competitive terms.

Capital Management

The primary objective of capital management is to ensure TransCanada has strong credit ratings to support its businesses and maximize shareholder value. In 2010, the overall objective and policy for managing capital remained unchanged from the prior year.

TransCanada 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 comprises Notes Payable, 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 TransCanada's joint ventures.

The total capital managed by the Company was as follows:

December 31 (millions of dollars)	2010		2009
Notes payable	2,081		1,678
Long-term debt	17,922		16,664
Junior subordinated notes	985		1,036
Cash and cash equivalents	(660	)	(896	)
Net debt	20,328		18,482
Non-controlling interests	1,157		1,174
Shareholders' equity	16,727		15,759
Total equity	17,884		16,933
	38,212		35,415

Fair Values

Certain financial instruments included in Cash and Cash Equivalents, Accounts Receivable, Intangibles and Other Assets, Notes Payable, Accounts Payable, Accrued Interest and Deferred Amounts have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity. The fair value of foreign exchange and interest rate derivatives has been calculated using year-end market rates and applying a discounted cash flow valuation model. The fair value of power, natural gas and oil products derivatives, and of available-for-sale investments, has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used.

The fair value of the Company's Notes Receivable is calculated by discounting future payments of interest and principal using forward interest rates. Long-Term Debt was estimated based on quoted market prices for the same or similar debt instruments. Credit risk has been taken into consideration when calculating the fair value of derivatives, Notes Receivable and Long-Term Debt.

70        MANAGEMENT'S DISCUSSION AND ANALYSIS

Non-Derivative Financial Instruments Summary

The carrying and fair values of non-derivative financial instruments were as follows:

	2010		2009
December 31 (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Financial Assets(1)
Cash and cash equivalents	764	764	997	997
Accounts receivable and other(2)(3)	1,555	1,595	1,432	1,483
Available-for-sale assets(2)	20	20	23	23
	2,339	2,379	2,452	2,503
Financial Liabilities(1)(3)
Notes payable	2,092	2,092	1,687	1,687
Accounts payable and deferred amounts(4)	1,436	1,436	1,538	1,538
Accrued interest	367	367	377	377
Long-term debt	17,922	21,523	16,664	19,377
Junior subordinated notes	985	992	1,036	976
Long-term debt of joint ventures	866	971	965	1,025
	23,668	27,381	22,267	24,980

⁽¹⁾

Consolidated Net Income in 2010 included gains of $8 million (2009 – gains of $6 million) for fair value adjustments related to interest rate swap agreements on US$250 million (2009 – US$250 million) of long-term debt. There were no other unrealized gains or losses from fair value adjustments to the financial instruments.

⁽²⁾

At December 31, 2010, the Consolidated Balance Sheet included financial assets of $1,271 million (2009 – $966 million) in Accounts Receivable, $40 million (2009 – nil) in Other Current Assets and $264 million (2009 – $489 million) in Intangibles and Other Assets.

⁽³⁾

Recorded at amortized cost except for $250 million (2009 – $250 million) of Long-Term Debt, which is adjusted to fair value.

⁽⁴⁾

At December 31, 2010, the Consolidated Balance Sheet included financial liabilities of $1,406 million (2009 – $1,513 million) in Accounts Payable and $30 million (2009 – $25 million) in Deferred Amounts.

MANAGEMENT'S DISCUSSION AND ANALYSIS        71

The following tables detail the remaining contractual maturities for TransCanada's non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2010:

Contractual Repayments of Financial Liabilities⁽¹⁾

		Payments Due by Period
(millions of dollars)	Total	2011	2012 and 2013	2014 and 2015	2016 and Thereafter
Notes payable	2,092	2,092	–	–	–
Long-term debt	17,922	894	2,012	2,034	12,982
Junior subordinated notes	985	–	–	–	985
Long-term debt of joint ventures	866	65	148	99	554
	21,865	3,051	2,160	2,133	14,521

⁽¹⁾

The anticipated timing of settlement of derivative contracts is presented in the Derivatives Financial Instrument Summary below.

Interest Payments on Financial Liabilities

		Payments Due by Period
(millions of dollars)	Total	2011	2012 and 2013	2014 and 2015	2016 and Thereafter
Long-term debt	16,721	1,140	2,190	1,973	11,418
Junior subordinated notes	410	63	126	126	95
Long-term debt of joint ventures	381	48	90	80	163
	17,512	1,251	2,406	2,179	11,676

72        MANAGEMENT'S DISCUSSION AND ANALYSIS

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments for 2010 is as follows:

December 31			2010
(all amounts in millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest
Derivative Financial Instruments Held for Trading(1)
Fair Values(2)
	Assets		$169		$144		$8		$20
	Liabilities		$(129	)	$(173	)	$(14	)	$(21	)
Notional Values
	Volumes(3)
		Purchases	15,610		158		–		–
		Sales	18,114		96		–		–
	Canadian dollars		–		–		–		736
	U.S. dollars		–		–		US 1,479		US 250
	Cross-currency		–		–		47/US 37		–
Net unrealized (losses)/gains in the year(4)			$(32	)	$27		$4		$43
Net realized gains/(losses) in the year(4)			$77		$(42	)	$36		(74	)
Maturity dates			2011-2015		2011-2015		2011-2012		2011-2016
Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(2)
	Assets		$112		$5		$–		$8
	Liabilities		$(186	)	$(19	)	$(51	)	$(26	)
Notional Values
	Volumes(3)
		Purchases	16,071		17		–		–
		Sales	10,498		–		–		–
	U.S. dollars		–		–		US 120		US 1,125
	Cross-currency		–		–		136/US 100		–
Net realized losses in the year(4)			$(9	)	$(35	)	$–		$(33	)
Maturity dates			2011-2015		2011-2013		2011-2014		2011-2015

⁽¹⁾

All derivative financial instruments in the held-for-trading classification have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.

⁽²⁾

Fair values equal carrying values.

⁽³⁾

Volumes for power and natural gas derivatives are in GWh and billion cubic feet (Bcf), respectively.

⁽⁴⁾

Realized and unrealized gains and losses on held-for-trading derivative financial instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of unrealized gains and losses on derivative financial instruments in hedging relationships is initially recognized in Other Comprehensive (Loss)/Income and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

⁽⁵⁾

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 and a notional amount of US$250 million. In 2010, net realized gains on fair value hedges were $4 million and were included in Interest Expense. In 2010, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

⁽⁶⁾

In 2010, Net Income included a gain of $1 million for changes in the 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 2010, there were no gains or losses included in Net Income for discontinued cash flow hedges. No amounts have been excluded from the assessment of hedge effectiveness.

MANAGEMENT'S DISCUSSION AND ANALYSIS        73

The anticipated timing of settlement of the derivative contracts assumes constant commodity prices, interest rates and foreign exchange rates from December 31, 2010. Settlements will vary based on the actual value of these factors at the date of settlement. The anticipated timing of settlement of these contracts is as follows:

Year ended December 31 (millions of dollars)		Total		2011		2012 and 2013		2014 and 2015		2016 and Thereafter
Derivative financial instruments held for trading
	Assets	341		221		102		17		1
	Liabilities	(337	)	(191	)	(121	)	(24	)	(1	)
Derivative financial instruments in hedging relationships
	Assets	306		76		204		26		–
	Liabilities	(282	)	(146	)	(120	)	(16	)	–
		28		(40	)	65		3		–

74        MANAGEMENT'S DISCUSSION AND ANALYSIS

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments for 2009 is as follows:

December 31			2009
(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		$150		$107		$5		$–		$25
	Liabilities		$(98	)	$(112	)	$(5	)	$(66	)	$(68	)
Notional Values
	Volumes(2)
		Purchases	15,275		238		180		–		–
		Sales	13,185		194		180		–		–
	Canadian dollars		–		–		–		–		574
	U.S. dollars		–		–		–		U.S. 444		U.S. 1,325
	Cross-currency		–		–		–		227/U.S. 157		–
Net unrealized gains/(losses) in the year(3)			$3		$(5	)	$1		$3		$27
Net realized gains/(losses) in the year(3)			$70		$(76	)	$–		$36		$(22	)
Maturity dates			2010-2015		2010-2014		2010		2010-2012		2010-2018
Derivative Financial Instruments in Hedging Relationships (4)(5)
Fair Values(1)
	Assets		$175		$2		$–		$–		$15
	Liabilities		$(148	)	$(22	)	$–		$(43	)	$(50	)
Notional Values
	Volumes(2)
		Purchases	13,641		33		–		–		–
		Sales	14,311		–		–		–		–
	U.S. dollars		–		–		–		U.S. 120		U.S. 1,825
	Cross-currency		–		–		–		136/U.S. 100		–
Net realized gains/(losses) in the year(3)			$156		$(29	)	$–		$–		$(37	)
Maturity dates			2010-2015		2010-2014		–		2010-2014		2010-2020

⁽¹⁾

Fair values equal carrying values.

⁽²⁾

Volumes for power, natural gas and oil products derivatives are in GWh, Bcf and thousands of barrels, respectively.

⁽³⁾

Realized and unrealized gains and losses on held-for-trading derivative financial instruments used to purchase and sell power, natural gas and fuel oil are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of unrealized gains and losses on derivative financial instruments in hedging relationships is initially recognized in Other Comprehensive (Loss)/Income and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

⁽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 $4 million and a notional amount of US$150 million. In 2009, realized gains on fair value hedges were $4 million and were included in Interest Expense. In 2009, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

⁽⁵⁾

In 2009, Net Income included losses of $5 million for changes in the 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 2009, there were no gains or losses included in Net Income for discontinued cash flow hedges. No amounts have been excluded from the assessment of hedge effectiveness.

MANAGEMENT'S DISCUSSION AND ANALYSIS        75

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)	2010		2009
Current
Other current assets	273		315
Accounts payable	(337	)	(340	)
Long term
Intangibles and other assets	374		260
Deferred amounts	(282	)	(272	)

Derivative Financial Instruments of Joint Ventures    Included in the Derivative Financial Instruments Summary tables 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 $48 million at December 31, 2010 (2009 – $105 million). These contracts mature from 2011 to 2015. The Company's proportionate share of the notional sales volumes of power associated with this exposure was 3,772 GWh at December 31, 2010 (2009 – 6,312 GWh). The Company's proportionate share of the notional purchased volumes of power associated with this exposure was 2,322 GWh at December 31, 2010 (2009 – 2,747 GWh).

76        MANAGEMENT'S DISCUSSION AND ANALYSIS

Fair Value Hierarchy

The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. In Level I, the fair value of assets and liabilities is determined by reference to quoted prices in active markets for identical assets and liabilities. In Level II, determination of the fair value of assets and liabilities includes valuations using inputs, other than quoted prices, for which all significant outputs are observable directly or indirectly. This category includes fair value determined using valuation techniques, such as option pricing models and extrapolation using observable inputs. In Level III, determination of the fair value of assets and liabilities is based on inputs that are not readily observable and are significant to the overall fair value measurement. Long-dated commodity transactions in certain markets are included in this category. Long-dated commodity prices are derived with a third-party modelling tool that uses market fundamentals to derive long-term prices.

There were no transfers between Level I and Level II in 2010 and 2009. Financial assets and liabilities measured at fair value, including both current and non-current portions, are categorized as follows:

		Quoted Prices in Active Markets (Level I)				Significant Other Observable Inputs (Level II)				Significant Unobservable Inputs (Level III)				Total
December 31 (millions of dollars, pre-tax)		2010		2009		2010		2009		2010		2009		2010		2009
Natural Gas Inventory		–		–		49		73		–		–		49		73
Derivative Financial Instrument Assets:
	Interest rate contracts	–		–		28		40		–		–		28		40
	Foreign exchange contracts	10		10		179		104		–		–		189		114
	Power commodity contracts	–		–		269		311		5		14		274		325
	Gas commodity contracts	93		55		56		49		–		–		149		104
	Oil commodity contacts	–		–		–		5		–		–		–		5
Derivative Financial Instrument Liabilities:
	Interest rate contracts	–		–		(47	)	(119	)	–		–		(47	)	(119	)
	Foreign exchange contracts	(11	)	(6	)	(54	)	(120	)	–		–		(65	)	(126	)
	Power commodity contracts	–		–		(299	)	(229	)	(8	)	(16	)	(307	)	(245	)
	Gas commodity contracts	(178	)	(103	)	(15	)	(27	)	–		–		(193	)	(130	)
	Oil commodity contacts	–		–		–		(5	)	–		–		–		(5	)
Non-Derivative Financial Instruments:
	Available-for-sale assets	20		23		–		–		–		–		20		23
		(66	)	(21	)	166		82		(3	)	(2	)	97		59

MANAGEMENT'S DISCUSSION AND ANALYSIS        77

The following table presents the net change in the Level III fair value category:

(millions of dollars, pre-tax)	Derivatives(1)
Balance at December 31, 2008	–
New contracts(2)	(14	)
Transfers into Level III(3)	12
Balance at December 31, 2009	(2	)
New contracts(2)	(16	)
Settlements	(3	)
Transfers into Level III(4)	3
Transfers out of Level III(4)(5)	(38	)
Change in unrealized gains recorded in Net Income	14
Change in unrealized gains recorded in Other Comprehensive (Loss)/Income	39
Balance at December 31, 2010	(3	)

⁽¹⁾

The fair value of derivative assets and liabilities is presented on a net basis.

⁽²⁾

At December 31, 2010, the total amount of net gains included in Net Income attributable to derivatives that were entered into during the year and still held at the reporting date was $1 million (2009 – nil).

⁽³⁾

These contracts were previously included in Level II but were reclassified to Level III due to reduced liquidity in the market to which they relate.

⁽⁴⁾

Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable.

⁽⁵⁾

As contracts near maturity, they are transferred out of Level III and into Level II.

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in an $8 million decrease or increase, respectively, in the fair value of outstanding derivative financial instruments included in Level III as at December 31, 2010.

OTHER RISKS

Development Projects and Acquisitions

TransCanada continues to focus on growing its Natural Gas Pipelines, Oil Pipelines and Energy operations through greenfield development projects and acquisitions. TransCanada 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 are expensed at the time it is discontinued to the extent that these costs and underlying materials cannot be utilized on another project. There is a risk with respect to TransCanada's acquisition of assets and operations that certain commercial opportunities and operational synergies may not materialize as expected and that the assets would subsequently be subject to an impairment write-down.

Asset Commissioning

Although each of TransCanada's newly-constructed assets goes through rigorous acceptance testing prior to being placed in service, there is a risk that these assets will have lower than expected availability or performance, especially in their first year of operations.

78        MANAGEMENT'S DISCUSSION AND ANALYSIS

Health, Safety and Environment Risk Management

Health, safety and environment (HS&E) are top priorities in all of TransCanada's operations and activities. These areas are guided by the Company's HS&E Commitment Statement, which outlines guiding principles for a safe and healthy environment for TransCanada's employees, contractors and the public, and for TransCanada's commitment to protect the environment. All employees are responsible for the Company's 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. TransCanada 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. TransCanada is committed to respecting the diverse environments and cultures in which it operates and to supporting open communication with its stakeholders.

The HS&E Committee of TransCanada's Board of Directors monitors compliance with the Company's HS&E corporate policy through regular reporting. TransCanada's HS&E management system is modeled on the International Organization for Standardization (ISO) standard for environmental management systems, ISO 14001, and focuses resources on the areas of significant risk to the organization's HS&E business activities. Management is informed regularly of all important HS&E operational issues and initiatives through formal reporting processes. TransCanada's HS&E management system and performance are assessed by an independent outside firm every three years. The most recent assessment occurred in December 2009 and did not identify any material issues. The HS&E management system is subject to ongoing internal review to ensure that it remains effective as circumstances change.

As one of TransCanada's priorities, safety is an integral part of the way its employees work. In 2010, one of the Company's objectives was to sustain health and safety performance. Overall, the Company's safety frequency rates in 2010 continued to be better than most industry benchmarks.

The safety and integrity of the Company's existing and newly-developed infrastructure also continued to be top priorities. All new assets are designed, constructed and commissioned with full consideration given to safety and integrity, and are brought into service only after all necessary requirements have been satisfied. The Company expects to spend approximately $250 million in 2011 for pipeline integrity on its wholly owned pipelines, an increase of approximately $95 million over 2010 primarily due to increased levels of in-line pipeline inspection on all systems and pipeline enhancements in areas of population encroachment. Under the approved regulatory models in Canada, non-capital pipeline integrity expenditures on NEB-regulated pipelines are treated on a flow-through basis and, as a result, these expenditures have no impact on TransCanada's earnings. Under the Keystone contracts, pipeline integrity expenditures are recovered through the tolling mechanism and, as a result, these expenditures have no impact on TransCanada's earnings. Expenditures for GTN may also be recovered through a cost-recovery mechanism in its rates if threshold expenditures are achieved. TransCanada's pipeline safety record in 2010 continued to be above industry benchmarks. TransCanada experienced no pipeline breaks in 2010. 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

TransCanada's facilities are subject to stringent federal, provincial, state and local environmental statutes and regulations, including requirements that establish compliance and remedial obligations. Such laws and regulations generally require facilities to obtain or comply with a wide variety of environmental restrictions, licences, permits and other approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements or the issuance of orders respecting future operations. TransCanada has ongoing inspection programs designed to keep all of its facilities in compliance with environmental requirements.

MANAGEMENT'S DISCUSSION AND ANALYSIS        79

As mentioned above, TransCanada'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, and with damage claims arising from the contamination of properties. It is not possible for the Company to estimate the amount and timing of all future expenditures related to environmental matters due to:

•

uncertainties in estimating pollution control and clean up costs, including at 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 the Company's 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 of them; and

•

the potential for litigation on existing or discontinued assets.

Environmental risks from TransCanada's operating facilities typically include: air emissions, such as nitrogen oxides, particulate matter and greenhouse gases (GHG); potential impacts on land, including land reclamation or restoration following construction; the use, storage and 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.

At December 31, 2010, TransCanada recorded liabilities of approximately $84 million (2009 – $91 million) for remediation obligations and compliance costs associated with environmental regulations. 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.

TransCanada is not aware of any material outstanding orders, claims or lawsuits against it in relation to the release or discharge of any material into the environment or in connection with environmental protection.

Regulation of air pollutant emissions under the U.S. Clean Air Act and state regulations continue to evolve. A number of EPA initiatives could lead to impacts ranging from requirements to install emissions control equipment, to additional administrative and reporting requirements. At this time, there is insufficient detail to accurately determine the potential impacts of these initiatives. While the majority of the proposals are not expected to be material to TransCanada, the Company anticipates additional future costs related to the monitoring and control of air emissions.

In addition to those climate change policies already in place, there are also several federal, Canada and U.S., regional and provincial initiatives currently in development. While recent political and economic events may significantly affect the scope and timing of new policies, TransCanada anticipates that most of the Company's facilities in Canada and the U.S. are or will be subject to federal or regional climate change regulations to manage industrial GHG emissions. Certain of these initiatives are outlined below.

In 2010, the Company owned assets in four regions, Alberta, Québec, B.C., and northeastern U.S., where regulations exist to address industrial GHG emissions. TransCanada has procedures in place to address these regulations.

In Alberta, under the Specified Gas Emitters Regulation, industrial facilities emitting GHGs over an intensity threshold level are required to reduce GHG emissions intensities by 12 per cent below an average baseline. TransCanada's Alberta-based facilities are subject to this regulation, as are the Sundance and Sheerness coal-fired power facilities with which TransCanada has PPAs. As an alternative to reducing emissions intensities, compliance can be achieved through acquiring offsets or making payments to a technology fund at a cost of $15 per tonne of carbon dioxide (CO₂) equivalents in excess of the mandated reduction. A program is in place to manage the compliance costs incurred by these assets as a result of regulation. Compliance costs on the Alberta System are recovered through rates paid by

80        MANAGEMENT'S DISCUSSION AND ANALYSIS

customers. Some of the compliance costs from the Company's power generation facilities in Alberta are recovered through market pricing and contract flow-through provisions. TransCanada has estimated and recorded related costs of $22 million for 2010, after contracted cost recovery.

In Québec, the natural gas distributor collects the hydrocarbon royalty on behalf of the provincial government through a green fund contribution charge on gas consumed. In 2010, the cost pertaining to the Bécancour facility arising from the hydrocarbon royalty was less than $1 million as a result of an agreement between TransCanada and Hydro-Québec to temporarily suspend the facility's power generation. The cost is expected to increase substantially when the plant returns to service.

The carbon tax in B.C., which came into effect in mid 2008, applies to CO₂ emissions 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 in 2010 were estimated to be $4 million. As specified by this law, the cost per tonne of CO₂ will increase in July 2011 to $25 from $20.

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 in January 2009. Under the RGGI, both the Ravenswood and OSP generation facilities will be required to submit allowances following the end of the first compliance period on December 31, 2011. TransCanada participated in the quarterly auctions of allowances for the Ravenswood and OSP generation facilities and incurred related costs of approximately $5 million in 2010. These costs were generally recovered through the power market and the net impact on TransCanada was not significant.

The Canadian government has continued to express interest in pursuing a harmonized continental climate change strategy. In January 2010, Environment Canada submitted a revised GHG reduction target to the United Nations Framework Convention on Climate Change as part of its submission for the Copenhagen Accord. The revised target represents a 17 per cent reduction in GHG emissions by 2020 relative to 2005 levels. In June 2010, the Federal government initiated consultation on its policy for coal-fired power operations with the stated intention of publishing the draft regulatory framework in Canada Gazette in early 2011. TransCanada participated in this consultation process directly through meetings with government officials and the Canadian Electricity Association. The new regulations to reduce GHG emissions for coal-fired operations are expected to come into effect July 2015.

In the U.S., the EPA is proceeding towards regulating industrial GHG emissions under the Clean Air Act. In May 2010, the EPA issued its final version of the Tailoring Rule, which outlines emissions thresholds and a schedule for phasing in certain permitting requirements under the Clean Air Act. Under this rule, the Prevention of Significant Deterioration (PSD) program stipulates the air pollution protection criteria a company must meet to obtain a construction permit. Requirements will apply to GHG emissions starting in January 2011. The second phase of the program will commence in July 2011, with new rulemaking in 2012 to establish emission thresholds and permitting requirements to take effect in 2013. In addition to the PSD requirements, the Tailoring Rule sets comparable emissions thresholds and timetables for new and existing facilities to obtain operating permits under Title V of the Clean Air Act. The regulation of GHG emissions by the EPA under the Clean Air Act would have implications for TransCanada with respect to permitting for existing, new and modified facilities.

The Western Climate Initiative (WCI) continues to work toward implementing a regional cap-and-trade program expected to come into effect in 2012. The cap-and-trade program would be a key component of the plan to help WCI members reach their goal of reducing GHG emissions 15 per cent below 2005 levels by 2020. Beginning in 2012, the cap would cover utilities and large industrial sectors, and expand by 2015 to cover transportation fuels, and commercial and residential fuels. The WCI comprises seven western U.S. states and four Canadian provinces. While TransCanada has assets located in all four Canadian member provinces (B.C., Manitoba, Ontario and Québec) and five of the member states (California, Oregon, Washington, Montana and Arizona), the cap-and-trade program is proposed to begin in 2012 in California and the Canadian provinces of B.C., Québec and Ontario. The programs would cover TransCanada's pipeline and power facilities, however, TransCanada expects the cost of compliance would be largely recoverable on the facilities that trigger emissions thresholds.

MANAGEMENT'S DISCUSSION AND ANALYSIS        81

In April 2010, the EPA published an "Advanced Notice of Proposed Rulemaking" to solicit comments with respect to the EPA's reassessment of current regulations under the Toxic Substances Control Act, governing the authorized use of polychlorinated biphenyls (PCB) in certain equipment. The proposed changes could require notification to the EPA when PCBs are discovered in any pipeline system, a phase out and eventual elimination of PCB use in pipeline systems and air compressor systems, and the immediate elimination of the storage of PCB equipment for reuse. If finalized as proposed, these changes are likely to have significant cost implications for the Company's U.S. assets.

TransCanada 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.

In 2010, the Keystone Wood River/Patoka phase became operational. Steel pipelines are a safe, efficient and economical method of transporting crude oil. The equipment and procedures put in place with respect to Keystone provide the capability to contain oil leaks quickly and safely.

TransCanada's pipelines are designed, constructed and operated to the highest industry standards and meet or exceed all regulatory requirements. Keystone is continuously monitored and is fully automated with remotely-started secure pumps and valves. A variety of methods are used to detect and prevent leaks. In the unlikely event of a leak or spill, valves can be closed to isolate the leak and limit spill volumes.

The Company has established emergency response plans to be enacted in the unlikely event of a leak or spill along TransCanada's operational crude oil pipeline. The plans encompass the necessary personnel and equipment to respond to any size of spill as well as clean-up and remediation operations to minimize any effects on the environment. The plans outline specific environmental features in the vicinity of the pipeline and containment and remediation efforts are based on practices that are well-understood and tested. In addition, TransCanada has an on-going program to provide local emergency responders with the information and training necessary to ensure their preparedness for responding to events.

The impact of new or proposed provincial, state or federal safety and environmental laws, regulations, guidelines and enforcement in Canada and the U.S. on TransCanada's business is not yet certain. TransCanada makes assumptions about possible expenditures to safety and environmental matters based on current laws and regulations and interpretations thereof. If the laws or regulations or the interpretation thereof changes, the Company's assumptions may change. Incremental costs may or may not be recoverable under existing rate structures or commercial agreements. Proposed changes in environmental policy, legislation or regulation are routinely monitored by TransCanada and where the risks are potentially large or uncertain the Company works independently or through industry associations to comment on proposals.

Future Abandonment Costs

Dependent on specific operating jurisdictions, the Company may have obligations to abandon its facilities in accordance with applicable laws and regulations.

To the extent legal obligations exist and can be reasonably estimated, the Company records Asset Retirement Obligations based on estimated fair value, which are accreted at the end of each period. The Company recorded Asset Retirement Obligations associated with the retirement of certain power generation facilities, natural gas pipelines and transportation facilities, and natural gas storage systems. The estimates or assumptions required to calculate Asset Retirement Obligations include scope of abandonment and reclamation activities, inflation rates, discount rates and timing of retirement assets. By their nature, these assumptions are subject to measurement uncertainty. The Company has determined that the scope and timing of asset retirement related to its regulated natural gas pipelines, oil pipelines and hydroelectric power plants are so uncertain that a reasonable estimate cannot be made. As a result, the Company has not recorded amounts for Asset Retirement Obligations related to these assets, with the exception of certain abandoned facilities.

82        MANAGEMENT'S DISCUSSION AND ANALYSIS

The NEB's Land Matters Consultation Initiative deals with pipeline abandonment, including related financial issues. The goal of this initiative is for all pipeline companies regulated under the National Energy Board Act (Canada) to begin collecting and setting aside funds to cover future abandonment costs by mid-2014. In its May 2009 decision, the NEB established several filing deadlines relating to the financial issues, including deadlines for preparing and filing an estimate of the abandonment costs to be used to begin collecting funds, developing a proposal for collecting these funds through tolls or some other satisfactory method and developing a proposed process to set aside the funds collected. TransCanada is preparing to file its estimates of abandonment costs for its Canadian oil and natural gas pipelines by May 31, 2011, as required by the NEB decision. These costs would be recovered from shippers through tolls in accordance with the NEB's determination that abandonment costs are a legitimate cost of providing service and are recoverable upon NEB approval from users of the system. The specific toll impacts have not yet been determined as they will be the subject of a subsequent NEB filing in late 2012.

For the foreseeable future, the Company intends to operate and maintain these assets as long as supply and demand exists for hydroelectric power generation, natural gas and oil. The Company continues to evaluate its obligations related to future abandonment costs and to monitor developments that could impact the amounts it records.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As at December 31, 2010, an evaluation of the effectiveness of TransCanada'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, as at December 31, 2010, the design and operation of TransCanada's disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by the Company in reports filed with, or submitted to, securities regulatory authorities is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and were effective to provide reasonable assurance that such information is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws.

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.

Based on this evaluation, management concluded that internal control over financial reporting was effective as at December 31, 2010, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

In 2010, there was no change in TransCanada's internal control over financial reporting that materially affected or is reasonably likely to materially affect TransCanada's internal control over financial reporting.

MANAGEMENT'S DISCUSSION AND ANALYSIS        83

CEO and CFO Certifications

TransCanada'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 TransCanada's public disclosures relating to its fiscal 2010 reports filed with the SEC and the Canadian securities regulators.

SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES

To prepare financial statements that conform with GAAP, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses, since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. TransCanada regularly assesses the assets and liabilities associated with these estimates and assumptions, and believes that no material adjustments are required. 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 on the Company's financial information.

Rate-Regulated Accounting

The Company accounts for the impacts of rate regulation in accordance with GAAP. The following three criteria must be met to use these accounting principles:

•

the rates for regulated services or activities must be established by or 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 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 rate-regulated accounting principles. The most significant impact from the use of these accounting principles is that the timing of recognition of certain Natural Gas Pipelines 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. At December 31, 2010, the Company reported regulatory assets of $1.5 billion and $0.3 billion in Regulatory Assets and Other Current Assets, respectively (2009 – $1.5 billion and $0.2 billion, respectively), and regulatory liabilities of $0.3 billion and $0.1 billion in Regulatory Liabilities and Accounts Payable, respectively (2009 – $0.4 billion and $31 million, respectively).

Financial Instruments and Hedges

Financial Instruments

The Company initially records all financial instruments on the Balance Sheet at their fair value. Subsequent measurement of the financial instruments is based on their classification as held for trading, available for sale, held-to-maturity investments, loans and receivables, and other financial liabilities. Changes in the fair value of financial instruments are recorded in Net Income except those for available-for-sale assets, whose fair value adjustments are recorded in Other Comprehensive (Loss)/Income.

Held-for-trading derivative financial assets and liabilities consist of swaps, options, forwards and futures. 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. Trade receivables and 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. The Company does not have any held-to-maturity investments. Other financial liabilities consist of liabilities not classified as held for trading and are recognized at amortized cost using the effective interest method.

84        MANAGEMENT'S DISCUSSION AND ANALYSIS

Hedges

The Company applies hedge accounting to its arrangements that qualify for hedge accounting treatment, which include fair value and cash flow hedges, and to 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. 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. Changes in fair value of the hedged and hedging items are recognized 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 (Loss)/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 (Loss)/Income (AOCI) 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 AOCI 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. Any gains and losses arising from changes in the fair value of these hedges can be recovered through the tolls charged by the Company. As a result, any gains and losses are deferred as Regulatory Assets or Regulatory Liabilities on behalf of the ratepayers. When the hedges are settled, the realized gains and losses are refunded to or collected from 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 (Loss)/Income and the ineffective portion is recognized in Net Income. The amounts recognized previously in AOCI are reclassified to Net Income in the event the Company reduces its investment in a foreign operation.

The fair value of financial instruments and hedges, where fair value does not approximate carrying value, is primarily derived from market values adjusted for credit risk, which can fluctuate widely from period to period. Since the changes in fair value are recorded through earnings, fluctuations can result in variability in Net Income.

Financial instruments and hedges, including risks associated with fluctuations to earnings and cash flows, are discussed further in the Risk Management and Financial Instruments section in this MD&A.

Depreciation and Amortization Expense

TransCanada's Plant, Property and Equipment are depreciated on a straight-line basis over their estimated useful lives once they are ready for their intended use. The estimation of useful lives requires management's judgement regarding the period of time the assets will be in use based on third-party engineering studies, experience and industry practice. The initial payment for the Company's PPAs is deferred and amortized on a straight-line basis over the terms of the contracts, which expire in 2017 and 2020.

Natural gas pipeline and compression equipment is depreciated at annual rates ranging from one per cent to six per cent. Oil pipeline and pumping equipment is depreciated at annual rates ranging from approximately two per cent to 2.5 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 by major component on a straight-line basis over estimated service lives at average annual rates ranging from two per cent to 20 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 Energy equipment is depreciated at various rates. Corporate Plant, Property and Equipment are

MANAGEMENT'S DISCUSSION AND ANALYSIS        85

depreciated on a straight-line basis over estimated useful lives at average annual rates ranging from three per cent to 20 per cent.

Depreciation and Amortization expense in 2010 was $1,354 million (2009 – $1,377 million; 2008 – $1,247 million) and was recorded in Natural Gas Pipelines and Energy. In Natural Gas 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 of depreciation through rates charged to customers, a change in the estimate of the useful lives of plant, property and equipment in the Natural Gas Pipelines segment will have no material impact on TransCanada's Net Income but will directly affect Funds Generated from Operations. PPA amortization expense of $58 million was included in Energy's Depreciation and Amortization expense for each year from 2008 through 2010.

Impairment of Long-Lived Assets and Goodwill

The Company reviews long-lived assets such as plant, property and equipment, as well as 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.

At December 31, 2010, the Company reported Goodwill of $3.6 billion (2009 – $3.8 billion). Goodwill is tested in the Natural Gas 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 test is done by comparing the fair value of the operations, which includes goodwill, to the book value of each reporting unit. If the 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 goodwill exceeds the 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 and capacity 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.

ACCOUNTING CHANGES

FUTURE ACCOUNTING CHANGES

Business Combinations, Consolidated Financial Statements and Non-Controlling Interests

The Canadian Institute of Chartered Accountants (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 the 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

86        MANAGEMENT'S DISCUSSION AND ANALYSIS

"Consolidated Financial Statements" and 1602 "Non-Controlling Interests". Sections 1601 and 1602 will require Non-Controlling Interests 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 of income between the controlling and non-controlling interests. These standards will be effective January 1, 2011. Changes resulting from the adoption of Section 1582 will be applied prospectively and changes resulting from the adoption of Sections 1601 and 1602 will be applied retrospectively.

International Financial Reporting Standards

The CICA's Accounting Standards Board (AcSB) previously announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. As an SEC registrant, TransCanada prepares and files a "Reconciliation to United States GAAP" and has the option to prepare and file its consolidated financial statements using U.S. GAAP. Previously, TransCanada disclosed that effective January 1, 2011, the Company expected to begin reporting under IFRS. As a result of the developments noted below, management expects that the Company will adopt U.S. GAAP effective January 1, 2012. The Company's IFRS conversion project was proceeding as planned to meet the conversion date of January 1, 2011, prior to these developments.

In accordance with GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. These RRA standards allow the timing of recognition of certain expenses and revenues to differ from the timing that may otherwise be expected in a non-rate-regulated business under GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. These timing differences are recorded as Regulatory Assets and Regulatory Liabilities on TransCanada's Consolidated Balance Sheet and represent current rights and obligations regarding cash flows expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities. At December 31, 2010, TransCanada reported regulatory assets of $1.8 billion and regulatory liabilities of $0.4 billion in addition to certain other impacts of RRA.

In July 2009, the IASB issued an Exposure Draft "Rate-Regulated Activities", which proposed a form of RRA under IFRS. At its September 2010 meeting, the IASB concluded that the development of RRA under IFRS requires further analysis and removed the RRA project from its current agenda. The IASB is considering what form a future project might take, if any, to address RRA. TransCanada does not expect a final RRA standard under IFRS to be effective for 2012.

In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises that use RRA in order to permit these entities to defer the adoption of IFRS for one year. Due to the continued uncertainty around the timing, scope and eventual adoption of an RRA standard under IFRS, TransCanada will defer its adoption of IFRS accordingly and continue preparing its consolidated financial statements in 2011 in accordance with Canadian GAAP, as defined by Part V of the CICA Handbook, in order to continue using RRA. TransCanada will continue to actively monitor IASB developments with respect to RRA and other IFRS.

U.S. GAAP Conversion Project

The impact of adopting U.S. GAAP is consistent with that currently reported in the Company's publicly filed "Reconciliation to United States GAAP". Significant changes to existing systems and processes are not required to implement U.S. GAAP as the Company's primary accounting standard.

TransCanada's IFRS conversion team has been redeployed to support the conversion to U.S. GAAP. All staff affected by the conversion will be provided with in-depth U.S. GAAP training and technical research will be conducted. The conversion team is led by a multi-disciplinary Steering Committee that provides directional leadership for the likely adoption of U.S. GAAP. Management also updates TransCanada's Audit Committee on the progress of this project and on any pertinent developments related to IFRS at each Audit Committee meeting.

MANAGEMENT'S DISCUSSION AND ANALYSIS        87

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA⁽¹⁾

		2010
(unaudited) (millions of dollars except per share amounts)		Fourth	Third	Second	First
Revenues		2,057	2,129	1,923	1,955
Net Income		283	391	295	303
Share Statistics
	Net income per share – basic and diluted	$0.39	$0.54	$0.41	$0.43
	Dividend declared per common share	$0.40	$0.40	$0.40	$0.40

		2009
(unaudited) (millions of dollars except per share amounts)		Fourth	Third	Second	First
Revenues		1,986	2,049	1,984	2,162
Net Income		387	345	314	334
Share Statistics
	Net income per share – basic and diluted	$0.56	$0.50	$0.50	$0.54
	Dividend declared per common share	$0.38	$0.38	$0.38	$0.38

⁽¹⁾

The selected quarterly consolidated financial data has been prepared in accordance with GAAP.

Factors Affecting Quarterly Financial Information

In Natural Gas Pipelines, which consists primarily of the Company's investments in regulated pipelines and regulated natural gas storage facilities, annual revenues and net income fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net income 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 Oil Pipelines, which consists of the Company's investment in a regulated crude oil pipeline, annual revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable with fluctuations resulting from changes in the amount of spot volumes transported and the associated rate charged. Spot volumes transported are affected by customer demand, market pricing, planned and unplanned outages of refineries, terminals and pipeline facilities, 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 income are affected by seasonal weather conditions, customer demand, market prices, capacity payments, planned and unplanned plant outages, acquisitions and divestitures, certain fair value adjustments and developments outside of the normal course of operations.

Significant developments that affected EBIT and Net Income in 2010 and 2009 were as follows:

•

Fourth Quarter 2010 Natural Gas Pipelines' EBIT decreased as a result of recording a $146 million pre-tax ($127 million after-tax) valuation provision for advances to the APG for the MGP. Energy's EBIT included contributions from the second phase of Kibby Wind, which was placed in service in October 2010, and net unrealized gains of

88        MANAGEMENT'S DISCUSSION AND ANALYSIS

$22 million pre-tax ($12 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

•

Third Quarter 2010 Natural Gas Pipelines' EBIT increased as a result of recording nine months of incremental earnings related to the Alberta System 2010 - 2012 Revenue Requirement Settlement, which resulted in a $33 million increase to Net Income. Energy's EBIT included contributions from Halton Hills, which was placed in service in September 2010, and net unrealized gains of $4 million pre-tax ($3 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

•

Second Quarter 2010 Energy's EBIT included net unrealized gains of $15 million pre-tax ($10 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities. Net Income reflected a decrease of $58 million after tax due to losses in 2010 compared to gains in 2009 for interest rate and foreign exchange rate derivatives that did not qualify as hedges for accounting purposes and the translation of U.S. dollar-denominated working capital balances.

•

First Quarter 2010 Energy's EBIT included net unrealized losses of $49 million pre-tax ($32 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

•

Fourth Quarter 2009 Natural Gas Pipelines EBIT included a dilution gain of $29 million pre-tax ($18 million after tax) resulting from TransCanada's reduced ownership interest in PipeLines LP, which was caused by PipeLines LP's issue of common units to the public. Energy's EBIT included net unrealized gains of $7 million pre-tax ($5 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities. Net Income included $30 million of favourable income tax adjustments resulting from reductions in the Province of Ontario's corporate income tax rates.

•

Third Quarter 2009 Energy's EBIT included net unrealized gains of $14 million pre-tax ($10 million after tax) due to changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

•

Second Quarter 2009 Energy's EBIT included net unrealized losses of $7 million pre-tax ($5 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities. Energy's EBIT also included contributions from Portlands Energy, which was placed in service in April 2009, and the negative impact of Western Power's lower overall realized power prices.

•

First Quarter 2009 Energy's EBIT included net unrealized losses of $13 million pre-tax ($9 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

MANAGEMENT'S DISCUSSION AND ANALYSIS        89

FOURTH QUARTER 2010 HIGHLIGHTS

Reconciliation of Comparable Earnings, Comparable EBITDA, Comparable EBIT and EBIT to Net Income Applicable to Common Shares

		Natural Gas Pipelines				Energy				Corporate				Total
Three months ended December 31 (unaudited)(millions of dollars except per share amounts)		2010		2009		2010		2009		2010		2009		2010		2009
Comparable EBITDA(1)		737		745		301		248		(33	)	(28	)	1,005		965
Depreciation and amortization		(241	)	(257	)	(103	)	(86	)	–		–		(344	)	(343	)
Comparable EBIT(1)		496		488		198		162		(33	)	(28	)	661		622
Specific items:
	Valuation provision for MGP	(146	)	–		–		–		–		–		(146	)	–
	Risk management activities	–		–		22		7		–		–		22		7
	Dilution gain from reduced interest in PipeLines LP	–		29		–		–		–		–		–		29
EBIT(1)		350		517		220		169		(33	)	(28	)	537		658
Interest expense														(173	)	(184	)
Interest expense of joint ventures														(15	)	(17	)
Interest income and other														61		22
Income taxes														(94	)	(67	)
Non-controlling interests														(33	)	(25	)
Net Income														283		387
Preferred share dividends														(14	)	(6	)
Net Income Applicable to Common Shares														269		381
Specific items (net of tax where applicable):
	Valuation provision for MGP													127		–
	Risk management activities													(12	)	(5	)
	Dilution gain from reduced interest in PipeLines LP													–		(18	)
	Income tax adjustments													–		(30	)
Comparable Earnings(1)														384		328
Net Income per Share – Basic and Diluted(2)														$0.39		$0.56

⁽¹⁾

Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA, Comparable EBIT, EBIT, Comparable Earnings and Comparable Earnings per Share.

⁽²⁾

For the three months ended December 31

(unaudited)		2010		2009
Comparable Earnings per Share(1)		$0.55		$0.48
Specific items (net of tax where applicable):
	Valuation provision for MGP	(0.18	)	–
	Risk management activities	0.02		0.01
	Dilution gain from reduced interest in PipeLines LP	–		0.03
	Income tax adjustments	–		0.04
Net Income per Share		$0.39		$0.56

90        MANAGEMENT'S DISCUSSION AND ANALYSIS

TransCanada's Net Income in fourth quarter 2010 was $283 million and Net Income Applicable to Common Shares was $269 million or $0.39 per share compared to $387 million and $381 million or $0.56 per share, respectively, in fourth quarter 2009.

Comparable Earnings in fourth quarter 2010 were $384 million or $0.55 per share, compared to $328 million or $0.48 per share for the same period in 2009. Comparable Earnings in fourth quarter 2010 excluded the $127 million after-tax ($146 million pre-tax) valuation provision for advances to the APG for the MGP. Comparable Earnings in fourth quarter 2010 also excluded net unrealized gains of $12 million after tax ($22 million pre-tax) (2009 – gains of $5 million after tax ($7 million pre-tax)) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities. Comparable Earnings in fourth quarter 2009 also excluded the $30 million of favourable income tax adjustments arising from a reduction in the Province of Ontario's corporate income tax rates and the $18 million after-tax ($29 million pre-tax) dilution gain resulting from TransCanada's reduced ownership interest in PipeLines LP, after a public offering of PipeLines LP common units in fourth quarter 2009. The $56 million increase in Comparable Earnings reflected:

•

increased Comparable EBIT from Natural Gas Pipelines primarily due to lower business development costs and higher earnings from the Alberta System revenue requirement settlement, increased revenues from Northern Border and reduced depreciation expense for Great Lakes, partially offset by lower revenues from the Canadian Mainline and Alberta System for amounts that are recovered on a flow-through basis;

•

increased Comparable EBIT from Energy primarily due to increased power generation at Bruce A, higher capacity revenues, sales volumes and realized prices for U.S. Power, and incremental earnings from the start-up of Halton Hills, which went into service in September 2010, partially offset by lower Bruce B lease expense in 2009, lower realized power prices for Western Power and Bruce B, and decreased proprietary and third-party storage revenues for Natural Gas Storage;

•

increased Comparable EBIT loss from Corporate primarily due to higher support services and other corporate costs;

•

decreased Interest Expense primarily due to increased capitalized interest, relating to Keystone and other capital projects, and the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest expense, partially offset by incremental interest expense on new debt issues in 2010;

•

increased Interest Income and Other, reflecting higher gains in fourth quarter 2010 compared to fourth quarter 2009 from changes in the fair value of derivatives used to manage the Company's exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income;

•

increased Income Taxes in fourth quarter 2010 compared to fourth quarter 2009 due to positive income tax adjustments that reduced income taxes in fourth quarter 2009, partially offset by lower pre-tax earnings in fourth quarter 2010; and

•

increased preferred share dividends recorded for preferred shares issued in 2010.

Natural Gas Pipelines' Comparable EBIT was $496 million in fourth quarter 2010 compared to $488 million in the same period in 2009. Comparable EBIT in fourth quarter 2010 excluded the $146 million pre-tax valuation provision for advances to the APG for the MGP. Comparable EBIT in 2009 excluded the $29 million pre-tax dilution gain resulting from TransCanada's reduced ownership interest in PipeLines LP, which occurred following public issuance of common units by PipeLines LP in fourth quarter 2009.

Canadian Mainline's net income in fourth quarter 2010 decreased $1 million to $71 million from $72 million for the same period in 2009. Net income in fourth quarter 2010 reflected a lower ROE of 8.52 per cent compared to 8.57 per cent in 2009 on a lower average investment base, partially offset by higher incentive earnings.

Canadian Mainline's Comparable EBITDA in fourth quarter 2010 of $269 million decreased $13 million from $282 million for the same period in 2009, primarily due to lower revenues as a result of lower income taxes and financial charges in the 2010 tolls, which are recovered on a flow-through basis and do not affect net income. The decrease in financial charges was primarily due to higher-cost debt that matured in 2009 and early 2010.

MANAGEMENT'S DISCUSSION AND ANALYSIS        91

The Alberta System's net income of $53 million in fourth quarter 2010 increased $8 million compared to the same period in 2009. Net income in fourth quarter 2010 reflected an ROE of 9.70 per cent on 40 per cent deemed common equity and a higher average investment base, earned under the Alberta System's 2010 - 2012 Revenue Requirement Settlement, partially offset by lower incentive earnings.

The Alberta System's Comparable EBITDA was $194 million in fourth quarter 2010 compared to $193 million for the same period in 2009. Comparable EBITDA in fourth quarter 2010 reflected the ROE earned under the Alberta System's 2010 - 2012 Revenue Requirement Settlement and an increased average investment base, partially offset by lower revenues as a result of lower financial charges, which are recovered on a flow-through basis, and lower incentive earnings compared to 2009.

Net income and Comparable EBITDA from Foothills in fourth quarter 2010 of $7 million and $33 million, respectively, increased $2 million and $1 million, respectively, compared to fourth quarter 2009. The increase was primarily due to a Foothills 2010 settlement agreement that established an ROE of 9.70 per cent on deemed common equity of 40 per cent for the years 2010 to 2012. Results in 2009 were based on the NEB ROE formula of 8.57 per cent on a deemed common equity of 36 per cent.

Comparable EBITDA from Other Canadian Natural Gas Pipelines was $11 million in fourth quarter 2010 compared to $15 million for the same period in 2009. The decrease in fourth quarter 2010 was primarily due to an adjustment to TQM's cost of capital in 2009.

ANR's Comparable EBITDA in fourth quarter 2010 was US$76 million compared to US$79 million for the same period in 2009. The decrease was primarily due to lower transportation sales and storage revenues as higher regional storage inventories and marginal supply from the U.S. Gulf Coast negatively affected transportation rates and demand for natural gas.

GTN's Comparable EBITDA in fourth quarter 2010 was US$45 million compared to US$41 million for the same period in 2009. The increase was primarily due to incremental proceeds accrued in 2010 relating to the Calpine bankruptcy distributions and lower OM&A costs, partially offset by the write-off of costs related to an unsuccessful information systems project in 2010.

Comparable EBITDA for the remainder of the U.S. Natural Gas Pipelines in fourth quarter 2010 was US$128 million compared to US$126 million for the same period in 2009. The increase was primarily due to the positive impact Northern Border's higher revenues had on PipeLines LP's earnings, partially offset by lower revenues from Great Lakes. U.S. Natural Gas Pipelines was also negatively affected by higher general, administrative and support costs primarily related to the start-up of Keystone.

Natural Gas Pipelines' Business Development Comparable EBITDA losses decreased $15 million to $21 million in fourth quarter 2010 from $36 million for the same period in 2009 primarily due to decreased business development costs related to the Alaska Pipeline Project.

Energy's Comparable EBIT was $198 million in fourth quarter 2010 compared to $162 million in the same period in 2009. Comparable EBIT in fourth quarter 2010 excluded net unrealized pre-tax gains of $22 million (2009 - gains of $7 million) from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

Western Power's Comparable EBITDA of $48 million in fourth quarter 2010 decreased $13 million compared to the same period in 2009, primarily due to lower overall realized power prices. Contracted prices in fourth quarter 2010 contributed positive margins compared to margins realized under spot prices, however, contracted prices were lower than in fourth quarter 2009 due to the continued impact of the North American economic downturn.

Eastern Power's Comparable EBITDA of $77 million in fourth quarter 2010 increased $21 million compared to the same period in 2009 primarily due to incremental earnings from Halton Hills, which went into service in September 2010.

92        MANAGEMENT'S DISCUSSION AND ANALYSIS

TransCanada's proportionate share of Bruce Power's Comparable EBITDA increased $29 million to $99 million in fourth quarter 2010 from $70 million in fourth quarter 2009.

TransCanada's proportionate share of Bruce A's Comparable EBITDA increased $62 million to $33 million in fourth quarter 2010 from losses of $29 million in fourth quarter 2009 as a result of higher volumes and lower operating expenses due to decreased outage days.

TransCanada's proportionate share of Bruce B's Comparable EBITDA decreased $33 million to $66 million in fourth quarter 2010 from $99 million in fourth quarter 2009 primarily due to higher lease expenses and lower realized prices resulting from the expiry of fixed-price contracts at higher prices.

U.S. Power's Comparable EBITDA in fourth quarter 2010 of US$59 million increased US$31 million compared to the same period in 2009 primarily due to higher capacity revenues, increased realized prices and higher volumes of power sold.

Natural Gas Storage's Comparable EBITDA in fourth quarter 2010 was $37 million compared to $49 million for the same period in 2009. The decrease in Comparable EBITDA in fourth quarter 2010 was primarily due to lower proprietary natural gas and third-party storage revenues as a result of reduced realized natural gas price spreads.

Interest Expense in fourth quarter 2010 decreased $11 million to $173 million from $184 million in fourth quarter 2009. The decrease reflected increased capitalized interest relating to the Company's capital growth program in 2010, primarily due to Keystone construction, the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest and Canadian dollar-denominated debt maturities in 2009 and 2010. These decreases were partially offset by incremental interest expense on new debt issues of US$1.25 billion in June 2010 and US$1.0 billion in September 2010.

Interest Income and Other in fourth quarter 2010 increased $39 million to $61 million from $22 million in fourth quarter 2009. The increase reflected higher gains in 2010 compared to 2009 from changes in the fair value of derivatives used to manage the Company's exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Income Taxes were $94 million in fourth quarter 2010 compared to $67 million for the same period in 2009. The increase was primarily due to positive income tax adjustments that reduced income taxes in 2009, including $30 million of favourable adjustments arising from a reduction in the Province of Ontario's corporate income tax rates, partially offset by lower pre-tax earnings in 2010.

SHARE INFORMATION

At February 10, 2011, TransCanada had 699 million issued and outstanding common shares, and had 22 million Series 1, 14 million Series 3 and 14 million Series 5 issued and outstanding first preferred shares that are convertible to 22 million Series 2, 14 million Series 4 and 14 million Series 6 preferred shares, respectively. In addition, there were eight million outstanding options to purchase common shares, of which six million were exercisable as at February 10, 2011.

OTHER INFORMATION

Additional information relating to TransCanada, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation.

Other selected consolidated financial information for 2001 to 2010 is found under the heading "Ten Year Financial Highlights" in the Supplementary Information section of the Company's Annual Report.

MANAGEMENT'S DISCUSSION AND ANALYSIS        93

GLOSSARY OF TERMS

AcSB	Accounting Standards Board
AECL	Atomic Energy of Canada Ltd.
AGIA	Alaska Gasline Inducement Act
Alaska Pipeline Project	A proposed natural gas pipeline extending from Prudhoe Bay, Alaska to either Alberta or Valdez, Alaska
Alberta System	A natural gas transmission system in Alberta and B.C.
AOCI	Accumulated Other Comprehensive (Loss)/Income
American Natural Resources (ANR)	A natural gas transmission system extending from producing fields located primarily in Texas, Oklahoma, the Gulf of Mexico and U.S. midcontinent region to markets located primarily in Wisconsin, Michigan, Illinois, Ohio and Indiana, and regulated underground natural gas storage facilities in Michigan
APG	Aboriginal Pipeline Group
ARO	Asset retirement obligation
AUC	Alberta Utilities Commission
B.C.	British Columbia
Bbl/d	Barrel(s) 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 natural gas pipeline extending from the Powder River Basin in Wyoming to Northern Border in North Dakota
BPC	BPC Generation Infrastructure Trust
BPRIA	Bruce Power Refurbishment Implementation Agreement
Broadwater	A proposed offshore LNG project in Long Island Sound, New York
Bruce A	A partnership interest in a nuclear power generation facility consisting of Units 1 to 4 of Bruce Power
Bruce B	A partnership interest in a nuclear power generation facility consisting of Units 5 to 8 of Bruce Power
Bruce Power	A nuclear power generation facility located northwest of Toronto, Ontario (Bruce A and Bruce B, collectively)
Calpine	Calpine 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
CAPP	Canadian Association of Petroleum Producers
Carseland	A natural gas-fired cogeneration plant near Carseland, Alberta
Cartier Wind	Five wind farms in Gaspé, Québec, three of which are operational and two under construction
Chinook	A proposed power transmission line 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 construction in Coolidge, Arizona
CrossAlta	An underground natural gas storage facility near Crossfield, Alberta
Cushing Extension	Second phase of the Keystone oil pipeline delivering crude oil to Cushing, Oklahoma
DB Plans	Defined benefit pension plans
DC Plans	Defined contribution pension plans
DRP	Dividend Reinvestment and Share Purchase Plan
EBIT	Earnings before interest and taxes

94        MANAGEMENT'S DISCUSSION AND ANALYSIS

EBITDA	Earnings before interest, taxes, depreciation and amortization
Edson	An underground natural gas storage facility near Edson, Alberta
EPA	Environmental Protection Agency (U.S.)
FCA	Fuel channel assemblies
FCM	Forward Capacity Market
FERC	Federal Energy Regulatory Commission (U.S.)
Foothills	A natural gas transmission system extending from central Alberta to the B.C./U.S. border and to the Saskatchewan/U.S. border
GAAP	Canadian generally accepted accounting principles
Gas Pacifico	A natural gas transmission system extending from Loma de la Lata, Argentina to Concepción, Chile
GHG	Greenhouse gas
Grandview	A natural gas-fired cogeneration plant in 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 Northwest (GTN)	A natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border, traversing Idaho, Washington and Oregon
GTNC	Gas Transmission Northwest Company
Guadalajara	A natural gas pipeline under construction in Mexico extending from Manzanillo, Colima to Guadalajara, Jalisco
GWh	Gigawatt hours
Halton Hills	A natural gas-fired, combined-cycle power plant in Halton Hills, Ontario
HS&E	Health, safety and environment
HVDC	High voltage direct current
IASB	International Accounting Standards Board
IESO	Independent Electricity System Operator
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 for Standardization
Keystone	Wood River/Patoka, Cushing Extension and U.S. Gulf Coast Expansion, collectively
Kibby Wind	A wind farm located in Kibby and Skinner townships in northwestern Franklin County, Maine
km	Kilometre(s)
LNG	Liquefied natural gas
MacKay River	A natural gas-fired cogeneration plant near Fort McMurray, Alberta
MD&A	Management's Discussion and Analysis
Mackenzie Gas Project (MGP)	A proposed natural gas pipeline extending from a point near Inuvik, Northwest Territories to the northern border of Alberta
mmcf/d	Million cubic feet per day
MOP	Maximum operating pressure
MW	Megawatt(s)
MWh	Megawatt hours
NCC	North Central Corridor
NEB	National Energy Board
NGTL	NOVA Gas Transmission Ltd.
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

MANAGEMENT'S DISCUSSION AND ANALYSIS        95

NYISO	New York Independent System Operator
OCI	Other Comprehensive (Loss)/Income
OM&A	Operating, maintenance and administration
OMERS	Ontario Municipal Employees Retirement System
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 GTN to the Columbia River northwest of Portland
PCB	Polychlorinated biphenyls
PipeLines LP	TC PipeLines, LP
PJM Interconnection	A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia
Portland	A natural gas transmission system extending from a point near East Hereford, Québec to the northeastern U.S.
Portlands Energy	A natural gas-fired, combined-cycle power plant in Toronto, Ontario
PPA	Power purchase arrangement
PSD	Prevention of Significant Deterioration
PWU	Power Workers' Union Trust
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 near Redwater, Alberta
RGGI	Regional Greenhouse Gas Initiative
ROE	Rate of return on common equity
RRA	Rate-regulated accounting
SEC	Securities and Exchange Commission (U.S.)
SEP	Society of Energy Professionals Trust
Sheerness	A coal-fired power generating facility near Hanna, Alberta
Sundance A	A coal-fired power generating facility near Wabamun, Alberta
Sundance B	A coal-fired power generating facility near Wabamun, Alberta
Tamazunchale	A natural gas pipeline in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi
TC Hydro	Hydroelectric generation assets in New Hampshire, Vermont and Massachusetts
TCPL	TransCanada PipeLines Limited
TCPL USA	TransCanada PipeLine USA Ltd.
Trans Québec & Maritimes (TQM)	A natural gas transmission system that connects with the Canadian Mainline near the Québec/Ontario border and transports natural gas to markets in Québec, and connects with Portland
TransAlta	TransAlta Corporation
TransCanada or the Company	TransCanada Corporation
TransGas	A natural gas transmission system extending from Mariquita to Cali in Colombia
Tuscarora	A natural gas transmission system extending from Malin, Oregon to Wadsworth, Nevada
U.S.	United States
U.S. GAAP	U.S. generally accepted accounting principles
U.S. Gulf Coast Expansion	A proposed extension and expansion of the Keystone oil pipeline to the U.S. Gulf Coast
VaR	Value-at-Risk
Ventures LP	A natural gas transmission system in Alberta supplying 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
Wood River/ Patoka	First phase of the Keystone oil pipeline delivering crude oil to Wood River and Patoka in Illinois
Zephyr	A proposed power transmission line project originating in Wyoming and terminating in Nevada

96        MANAGEMENT'S DISCUSSION AND ANALYSIS

Report of
Management The consolidated financial statements and Management's Discussion and Analysis (MD&A) included in this Annual Report are the responsibility of the management of TransCanada Corporation (TransCanada or the Company) and have been approved by the Board of Directors of the Company. The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles (GAAP) and include amounts that are based on estimates and judgements. The MD&A is based on the Company's financial results. It compares the Company's financial and operating performance in 2010 to that in 2009, and highlights significant changes between 2009 and 2008. The MD&A should be read in conjunction with the consolidated financial statements and accompanying notes. Financial information contained elsewhere in this Annual Report is consistent with the consolidated financial statements.

Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Management has designed and maintains a system of internal controls over financial reporting, including a program of internal audits to carry out its responsibility. Management believes these controls provide reasonable assurance that financial records are reliable and form a proper basis for the preparation of financial statements. The internal controls over financial reporting include management's communication to employees of policies that govern ethical business conduct.

Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal controls over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded, based on its evaluation, that internal controls over financial reporting are effective as of December 31, 2010, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

The Board of Directors is responsible for reviewing and approving the financial statements and MD&A and ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors carries out these responsibilities primarily through the Audit Committee, which consists of independent, non-management directors. The Audit Committee meets with management at least five times a year and meets independently with 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's responsibilities include overseeing management's performance in carrying out its financial reporting responsibilities and reviewing the Annual Report, including the consolidated financial statements and MD&A, before these documents are submitted to the Board of Directors for approval. The internal and independent external auditors have access to 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.

Russell K. Girling	Donald R. Marchand
President and Chief Executive Officer	Executive Vice-President and Chief Financial Officer
February 14, 2011

TRANSCANADA CORPORATION        97

Auditors'
Report To the Shareholders of TransCanada Corporation

We have audited the accompanying consolidated financial statements of TransCanada Corporation and its subsidiaries, which comprise the consolidated balance sheet as at December 31, 2010 and 2009, 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, 2010, and notes, comprising a summary of significant accounting policies and other explanatory information.


Management's Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.


Auditors' Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgement, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinions.

Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of TransCanada Corporation and its subsidiaries as at December 31, 2010 and 2009 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010 in accordance with Canadian generally accepted accounting principles.

Chartered Accountants
Calgary, Canada

February 14, 2011

98        CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA CORPORATION
CONSOLIDATED INCOME

Year ended December 31 (millions of dollars except per share amounts)	2010		2009		2008
Revenues	8,064		8,181		8,547
Operating and Other Expenses/(Income)
Plant operating costs and other	3,114		3,213		2,976
Commodity purchases resold	1,017		831		1,429
Depreciation and amortization	1,354		1,377		1,247
Valuation provision for MGP (Note 7)	146		–		–
Calpine bankruptcy settlements (Note 18)	–		–		(279	)
Write-down of Broadwater LNG project costs (Note 4)	–		–		41
	5,631		5,421		5,414
Financial Charges/(Income)
Interest expense (Note 10)	701		954		943
Interest expense of joint ventures (Note 11)	59		64		72
Interest income and other	(94	)	(121	)	(54	)
	666		897		961
Income before Income Taxes and     Non-Controlling Interests	1,767		1,863		2,172
Income Taxes (Recovery)/Expense (Note 19)
Current	(141	)	30		526
Future	521		357		76
	380		387		602
Non-Controlling Interests (Note 15)	115		96		130
Net Income	1,272		1,380		1,440
Preferred Share Dividends (Note 17)	45		6		–
Net Income Applicable to Common Shares	1,227		1,374		1,440
Net Income per Share (Note 16)
Basic	$1.78		$2.11		$2.53
Diluted	$1.77		$2.11		$2.52

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

CONSOLIDATED FINANCIAL STATEMENTS        99

TRANSCANADA CORPORATION
CONSOLIDATED CASH FLOWS

Year ended December 31 (millions of dollars)	2010		2009		2008
Cash Generated from Operations
Net income	1,272		1,380		1,440
Depreciation and amortization	1,354		1,377		1,247
Future income taxes (Note 19)	521		357		76
Non-controlling interests (Note 15)	115		96		130
Valuation provision for MGP (Note 7)	146		–		–
Employee future benefits funding (in excess of)/lower than expense (Note 22)	(69	)	(111	)	17
Write-down of Broadwater LNG project costs (Note 4)	–		–		41
Other	(8	)	(19	)	70
	3,331		3,080		3,021
(Increase)/decrease in operating working capital (Note 23)	(249	)	(90	)	135
Net cash provided by operations	3,082		2,990		3,156
Investing Activities
Capital expenditures	(5,036	)	(5,417	)	(3,134	)
Deferred amounts and other	(384	)	(594	)	(484	)
Acquisitions, net of cash acquired (Note 9)	–		(902	)	(3,229	)
Disposition of assets, net of current income taxes	–		–		28
Net cash used in investing activities	(5,420	)	(6,913	)	(6,819	)
Financing Activities
Dividends on common and preferred shares (Notes 16 and 17)	(754	)	(728	)	(577	)
Distributions paid to non-controlling interests	(112	)	(100	)	(141	)
Notes payable issued/(repaid), net (Note 20)	474		(244	)	1,293
Long-term debt issued, net of issue costs (Note 10)	2,371		3,267		2,197
Reduction of long-term debt	(494	)	(1,005	)	(840	)
Long-term debt of joint ventures issued (Note 11)	177		226		173
Reduction of long-term debt of joint ventures	(254	)	(246	)	(120	)
Common shares issued, net of issue costs (Note 16)	26		1,820		2,384
Preferred shares issued, net of issue costs (Note 17)	679		539		–
Partnership units of subsidiary issued, net of issue costs (Note 9)	–		193		–
Net cash provided by financing activities	2,113		3,722		4,369
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(8	)	(110	)	98
(Decrease)/Increase in Cash and Cash Equivalents	(233	)	(311	)	804
Cash and Cash Equivalents
Beginning of year	997		1,308		504
Cash and Cash Equivalents
End of year	764		997		1,308

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

100        CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA CORPORATION
CONSOLIDATED BALANCE SHEET

December 31 (millions of dollars)	2010	2009
ASSETS
Current Assets
Cash and cash equivalents	764	997
Accounts receivable	1,271	966
Inventories	425	511
Other	777	701
	3,237	3,175
Plant, Property and Equipment (Note 5)	36,244	32,879
Goodwill (Note 6)	3,570	3,763
Regulatory Assets (Note 14)	1,512	1,524
Intangibles and Other Assets (Note 7)	2,026	2,500
	46,589	43,841
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable (Note 20)	2,092	1,687
Accounts payable	2,243	2,195
Accrued interest	367	377
Current portion of long-term debt (Note 10)	894	478
Current portion of long-term debt of joint ventures (Note 11)	65	212
	5,661	4,949
Regulatory Liabilities (Note 14)	314	385
Deferred Amounts (Note 13)	694	743
Future Income Taxes (Note 19)	3,222	2,856
Long-Term Debt (Note 10)	17,028	16,186
Long-Term Debt of Joint Ventures (Note 11)	801	753
Junior Subordinated Notes (Note 12)	985	1,036
	28,705	26,908
Non-Controlling Interests (Note 15)	1,157	1,174
Shareholders' Equity	16,727	15,759
	46,589	43,841
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:

Russell K. Girling Director	Kevin E. Benson Director

CONSOLIDATED FINANCIAL STATEMENTS        101

TRANSCANADA CORPORATION
CONSOLIDATED COMPREHENSIVE INCOME

Year ended December 31 (millions of dollars)	2010		2009		2008
Net Income	1,272		1,380		1,440
Other Comprehensive (Loss)/Income, Net of Income Taxes
Change in foreign currency translation gains and losses on net investments in foreign operations(1)	(180	)	(471	)	571
Change in gains and losses on financial derivatives to hedge the net investments in foreign operations(2)	89		258		(589	)
Change in gains and losses on derivative instruments designated as cash flow hedges(3)	(137	)	77		(60	)
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)	(17	)	(24	)	(23	)
Change in gains and losses on available-for-sale financial instruments(5)	–		–		2
Other Comprehensive Loss	(245	)	(160	)	(99	)
Comprehensive Income	1,027		1,220		1,341

⁽¹⁾

Net of income tax expense of $65 million in 2010 (2009 – $92 million expense; 2008 – $104 million recovery).

⁽²⁾

Net of income tax expense of $37 million in 2010 (2009 – $124 million expense; 2008 – $303 million recovery).

⁽³⁾

Net of income tax recovery of $95 million in 2010 (2009 – $7 million expense; 2008 – $41 million recovery).

⁽⁴⁾

Net of income tax expense of $21 million in 2010 (2009 – $9 million expense; 2008 – $19 million recovery).

⁽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.

102        CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA CORPORATION
CONSOLIDATED ACCUMULATED OTHER COMPREHENSIVE (LOSS)/INCOME

(millions of dollars)	Currency Translation Adjustments		Cash Flow Hedges and Other		Total
Balance at January 1, 2008	(361	)	(12	)	(373	)
Change in foreign currency translation gains and losses on net investments in foreign operations(1)	571		–		571
Change in gains and losses on financial derivatives to hedge the net investments in foreign operations(2)	(589	)	–		(589	)
Change in gains and losses on derivative instruments designated as cash flow hedges(3)	–		(60	)	(60	)
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)	–		(23	)	(23	)
Change in gains and losses on available-for-sale financial instruments(5)	–		2		2
Balance at December 31, 2008	(379	)	(93	)	(472	)
Change in foreign currency translation gains and losses on net investments in foreign operations(1)	(471	)	–		(471	)
Change in gains and losses on financial derivatives to hedge the net investments in foreign operations(2)	258		–		258
Change in gains and losses on derivative instruments designated as cash flow hedges(3)	–		77		77
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)	–		(24	)	(24	)
Balance at December 31, 2009	(592	)	(40	)	(632	)
Change in foreign currency translation gains and losses on net investments in foreign operations(1)	(180	)	–		(180	)
Change in gains and losses on financial derivatives to hedge the net investments in foreign operations(2)	89		–		89
Change in gains and losses on derivative instruments designated as cash flow hedges(3)	–		(137	)	(137	)
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)(6)	–		(17	)	(17	)
Balance at December 31, 2010	(683	)	(194	)	(877	)

⁽¹⁾

Net of income tax expense of $65 million in 2010 (2009 – $92 million expense; 2008 – $104 million recovery).

⁽²⁾

Net of income tax expense of $37 million in 2010 (2009 – $124 million expense; 2008 – $303 million recovery).

⁽³⁾

Net of income tax recovery of $95 million in 2010 (2009 – $7 million expense; 2008 – $41 million recovery).

⁽⁴⁾

Net of income tax expense of $21 million in 2010 (2009 – $9 million expense; 2008 – $19 million recovery).

⁽⁵⁾

Net of income tax expense of nil in 2008.

⁽⁶⁾

Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net Income in 2011 are estimated to be $94 million ($60 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.

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

CONSOLIDATED FINANCIAL STATEMENTS        103

TRANSCANADA CORPORATION
CONSOLIDATED SHAREHOLDERS' EQUITY

Year ended December 31 (millions of dollars)	2010		2009		2008
Common Shares
Balance at beginning of year	11,338		9,264		6,662
Shares issued under dividend reinvestment plan (Note 16)	378		254		218
Proceeds from shares issued on exercise of stock options (Note 16)	29		28		21
Proceeds from shares issued under public offering, net of issue costs (Note 16)	–		1,792		2,363
Balance at end of year	11,745		11,338		9,264
Preferred Shares
Balance at beginning of year	539		–		–
Proceeds from shares issued under public offering, net of issue costs (Note 17)	685		539		–
Balance at end of year	1,224		539		–
Contributed Surplus
Balance at beginning of year	328		279		276
Issuance of stock options, net of exercises	3		2		3
Increased ownership in PipeLines LP (Note 9)	–		47		–
Balance at end of year	331		328		279
Retained Earnings
Balance at beginning of year	4,186		3,827		3,220
Net income	1,272		1,380		1,440
Common share dividends	(1,109	)	(1,015	)	(833	)
Preferred share dividends	(45	)	(6	)	–
Balance at end of year	4,304		4,186		3,827
Accumulated Other Comprehensive (Loss)/Income
Balance at beginning of year	(632	)	(472	)	(373	)
Other comprehensive loss	(245	)	(160	)	(99	)
Balance at end of year	(877	)	(632	)	(472	)
	3,427		3,554		3,355
Total Shareholders' Equity	16,727		15,759		12,898

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

104        CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1    DESCRIPTION OF TRANSCANADA'S BUSINESS

TransCanada Corporation (TransCanada or the Company) is a leading North American energy company. TransCanada operates in three business segments, Natural Gas Pipelines, Oil Pipelines and Energy, each of which offers different products and services.

Natural Gas Pipelines

The Natural Gas Pipelines segment consists of the Company's investments in regulated natural gas pipelines and regulated natural gas storage facilities. Through its Natural Gas Pipelines segment, TransCanada owns and operates:

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a natural gas transmission system extending from the Alberta/Saskatchewan border east into Québec (Canadian Mainline);

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a natural gas transmission system in Alberta and northeastern British Columbia (B.C.) (Alberta System);

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a natural gas transmission system extending from producing fields primarily located in Texas, Oklahoma, the Gulf of Mexico and Louisiana to markets primarily located in Wisconsin, Michigan, Illinois, Ohio and Indiana, and to regulated natural gas storage facilities in Michigan (ANR);

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a natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border (GTN);

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a natural gas transmission system extending from central Alberta to the B.C./Idaho border and to the Saskatchewan/Montana border (Foothills);

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a natural gas transmission system extending from the Powder River Basin in Wyoming to Northern Border in North Dakota (Bison);

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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); and

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a natural gas transmission system in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi (Tamazunchale).

Through its Natural Gas Pipelines segment, TransCanada operates and has ownership interests in natural gas pipeline systems as follows:

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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 United States (U.S.) (Great Lakes);

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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);

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a 50 per cent interest in a natural gas transmission system that connects with the Canadian Mainline near the Québec/Ontario border and transports natural gas to markets in Québec and to the Portland system (TQM); and

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a 38.2 per cent controlling interest in TC PipeLines, LP (PipeLines LP), whose ownership interests in pipelines operated by TransCanada are as follows:

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a 46.4 per cent interest in Great Lakes, in which TransCanada has a combined 71.3 per cent effective ownership interest through PipeLines LP and a direct interest described above;

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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 TransCanada has a 19.1 per cent effective ownership interest through PipeLines LP;

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a 100 per cent interest in a natural gas transmission system extending from Arizona to Baja California at the Mexico/California border (North Baja), in which TransCanada has a 38.2 per cent effective ownership interest through PipeLines LP; and

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a 100 per cent interest in a natural gas transmission system extending from Malin, Oregon, to Wadsworth, Nevada (Tuscarora), in which TransCanada has a 38.2 per cent effective ownership interest through PipeLines LP.

TransCanada does not operate but has ownership interests in natural gas pipelines and natural gas marketing activities as follows:

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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);

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a 46.5 per cent interest in a natural gas transmission system extending from Mariquita to Cali in Colombia (TransGas); and

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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).

TransCanada is constructing and expects to operate a natural gas pipeline in Mexico that will transport natural gas from Manzanillo to Guadalajara (Guadalajara).

Oil Pipelines

The Oil Pipelines segment consists of a wholly owned and operated crude oil pipeline extending from Hardisty, Alberta to U.S. markets at Wood River and Patoka in Illinois (Wood River/Patoka) and from Steele City, Nebraska to Cushing, Oklahoma (Cushing Extension). The

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        105

Company plans to expand and extend the oil pipeline to the U.S. Gulf Coast (U.S. Gulf Coast Expansion) (collectively, Keystone) with physical construction to commence upon receipt of final permits.

Energy

The Energy segment primarily consists of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities. Through its Energy segment, the Company owns and operates:

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natural gas-fired cogeneration plants in Alberta at Carseland, Redwater, Bear Creek and MacKay River;

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a waste-heat fuelled power plant at the Cancarb thermal carbon black facility in Medicine Hat, Alberta (Cancarb);

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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);

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a natural gas-fired, combined-cycle power plant in Halton Hills, Ontario (Halton Hills);

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hydroelectric generation assets located in New Hampshire, Vermont and Massachusetts (TC Hydro);

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a natural gas-fired, combined-cycle plant in Burrillville, Rhode Island (Ocean State Power);

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a natural gas-fired cogeneration plant near Trois-Rivières, Québec (Bécancour);

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a natural gas-fired cogeneration plant near Saint John, New Brunswick (Grandview);

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a natural gas storage facility near Edson, Alberta (Edson); and

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a wind farm located in Kibby and Skinner townships in northwestern Franklin County, Maine (Kibby Wind).

TransCanada does not operate but has ownership interests in power generation plants and non-regulated natural gas storage facilities as follows:

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a 48.8 per cent partnership interest and a 31.6 per cent partnership interest in the nuclear power generation facilities of Bruce A and Bruce B (collectively Bruce Power), respectively, located near Tiverton, Ontario;

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a 50 per cent interest in a natural gas-fired, combined-cycle plant in Toronto, Ontario (Portlands Energy);

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a 62 per cent interest in the Baie-des-Sables, Anse-à-Valleau and Carleton wind farms, three of five planned wind farms in Gaspé, Québec (Cartier Wind); and

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a 60 per cent interest in an underground natural gas storage facility near Crossfield, Alberta (CrossAlta).

TransCanada also has long-term power purchase arrangements (PPA) in place for:

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100 per cent of the production of the Sundance A power facilities and 50 per cent of the production of the Sundance B power facilities near Wabamun, Alberta; and

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756 megawatts (MW) of generating capacity from the Sheerness power facility near Hanna, Alberta.

TransCanada has interests in the following Energy projects which are under construction and which it expects to operate:

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a natural gas-fired, simple-cycle peaking power plant in Coolidge, Arizona (Coolidge); and

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a 62 per cent interest in the Gros-Morne and Montagne-Sèche wind farms, the fourth and fifth wind farms of Cartier 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, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful 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 Company's significant accounting policies summarized below.

Basis of Presentation

The consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada proportionately consolidates its share of the accounts of joint ventures in which the Company is able

106        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to exercise joint control. TransCanada uses the equity method of accounting for investments over which the Company is able to exercise significant influence.

Regulation

The Canadian regulated natural gas pipelines are subject to the authority of the National Energy Board (NEB) of Canada. Prior to April 2009, the Alberta System was regulated by the Alberta Utilities Commission (AUC). The natural gas pipelines and regulated storage assets in the U.S. are subject to the authority of the U.S. Federal Energy Regulatory Commission (FERC). The Company's 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 rate-regulated businesses may differ from that otherwise expected in non-rate-regulated businesses under Canadian GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls.

The NEB in Canada and FERC in the U.S. regulate construction and operations of Keystone, the Company's oil pipeline. The Company does not apply rate-regulated accounting (RRA) on its oil pipeline and, as a result, the regulators' decisions regarding operations and tolls on the oil pipeline generally do not have an impact on timing of recognition of revenues and expenses.

Revenue Recognition

Canadian Natural Gas Pipelines

Revenues from Canadian natural gas pipelines subject to rate regulation are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline rates are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include an appropriate return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are not subject to risks related to variances in revenues and most costs. These variances are subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines are periodically subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to account for the incentives. Revenues are recognized on firm contracted capacity over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to the NEB's decision on rates reflect the NEB's last approved return on equity assumptions. Adjustments to revenue are recorded when the NEB decision is received.

U.S. Natural Gas Pipelines

Revenues from U.S. natural gas pipelines subject to rate regulation are recorded in accordance with FERC rules and regulations. The Company's U.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. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made.

Oil Pipelines

The Company's oil pipeline revenues are generated from the transportation of crude oil and contractual arrangements for committed capacity. Transportation revenues are recognized in the period the product is delivered. Transportation revenues are based on actual volumes and rates and are adjusted to reflect under-recovery or over-recovery of certain transportation costs. Revenues earned from contract capacity arrangements are recognized in the period in which the capacity is made available.

Energy

i)      Power

Revenues from the Company's power business are primarily derived from the sale of electricity through energy marketing activities and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, which are earned monthly, and revenues earned through the use of energy derivative contracts. The accounting for energy derivative contracts 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, which is generally over the term of the contract. 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 in storage, 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        107

Inventories

Inventories primarily consist of materials and supplies, including spare parts and fuel, and are carried at the lower of average cost and net realizable value. The Company values its proprietary natural gas inventory in storage at fair value, measured using a weighted average of forward prices for the following four months, less selling costs. To record inventory at fair value, TransCanada 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 proprietary natural gas inventory in storage are reflected in Inventories and in Revenues.

Plant, Property and Equipment

Natural Gas Pipelines

Plant, property and equipment for natural gas pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to six per cent, and metering and other plant equipment are depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component 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 in Plant, Property and Equipment. The equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines.

When regulated natural gas 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.

Oil Pipelines

Plant, property and equipment for oil pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from approximately two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction.

Energy

Major power generation and natural gas storage plant, equipment and structures are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 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 of the overhauls. Interest is capitalized on facilities under construction.

Corporate

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

Impairment of Long-Lived Assets

The Company reviews long-lived assets, such as plant, property 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 value 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 test is done by comparing the fair value of the operations, which includes goodwill, to the book value of each reporting unit. If the 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 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 goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded.

108        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 the Company's PPAs were deferred in Other Assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. The PPAs under which TransCanada 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 TransCanada records the margin earned from the subleases as a component of Revenues.

Stock Options

TransCanada's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. The contractual life of options granted in 2003 and thereafter and of options granted prior to 2003 is seven years and 10 years, respectively. The Company uses the Black-Scholes model to determine fair value of the options on their grant date. Options may be exercised at a price determined at the time the option is awarded and vest 33.3 per cent on the anniversary date in each of the three years following the award. Forfeiture of stock options results from their expiration, and if not previously vested, upon resignation or retirement of the option holder or upon termination of the option holder's employment. Stock options become null and void upon forfeiture. The Company records compensation expense over the three-year vesting period, assuming a 15 per cent forfeiture rate, with an offset to Contributed Surplus. This charge is reflected in Corporate. Upon exercise of stock options, adjusted for forfeited stock options, amounts originally recorded against Contributed Surplus are reclassified to Common Shares.

Income Taxes

The Company uses the liability method of accounting for income taxes. This method requires the recognition of future income tax assets and liabilities 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 at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

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 the period-end exchange rates and items included in the Consolidated Statements of Income, Shareholders' Equity, Comprehensive Income, Accumulated Other Comprehensive (Loss)/Income (AOCI) and Cash Flows are translated at the exchange rates in effect at the time of the transaction. Translation adjustments are reflected in Other Comprehensive (Loss)/Income (OCI).

Exchange gains and losses on monetary assets and liabilities are recorded in income except for exchange gains and losses on the foreign currency debt related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

Financial Instruments

The Company initially records all financial instruments on the Balance Sheet at fair value. Where possible, fair value is determined by reference to quoted market prices. In the absence of quoted prices, other pricing and valuation techniques are used that maximize the use of observable data. The entity's own credit risk and the credit risk of its counterparties are taken into consideration when measuring the fair value of financial assets and financial liabilities. 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 as 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 when it is entered into with the intention of generating a profit. The Company has not designated any of its 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. Realized gains and losses on derivatives used to manage the Company's operating assets are presented on a net basis in Revenues. Changes in the fair value of interest rate held-for-trading instruments are recorded in Interest Expense and changes in the fair value of foreign exchange rate held-for-trading instruments are recorded in Interest Income and Other. Realized gains and losses are included in the same financial statement category as their underlying position upon settlement of the financial instrument.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        109

The available-for-sale classification includes non-derivative financial assets that are designated as available for sale or are not included in any of the other three classifications. TransCanada'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 OCI. Income from the settlement of available-for-sale financial assets is 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. The Company's loans and receivables include trade accounts receivable, interest-bearing and non-interest-bearing third-party loans, and notes 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 costs are included in Interest Expense and in Interest Expense 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 normal purchase, sale or usage requirements. 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. Embedded derivatives are measured at fair value if their economic characteristics are not closely related to those of the host instrument, their terms 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. When changes in the fair value of embedded derivatives are recorded separately, they are included in Net Income.

The recognition of gains and losses on the derivatives for the Canadian natural gas regulated pipelines exposures is determined through the regulatory process. The gains and losses on derivatives accounted for as part of RRA 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 natural gas 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 value of its portion 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, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Deferred Amounts.

Hedges

The Company applies hedge accounting to arrangements that qualify for hedge accounting treatment, which include fair value and cash flow hedges, and to hedges of foreign currency exposures of net investments in self-sustaining foreign operations. Documentation is prepared at the inception of each hedging arrangement in order to qualify for hedge accounting treatment. In addition, the Company performs an assessment of effectiveness at the inception of the contract and at each reporting date. 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 and these changes 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 Interest Expense, 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 initially recognized in OCI, while any ineffective portion is recognized in Net Income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, during the periods when the variability in cash flows of the hedged item affects Net Income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to Net Income from AOCI when the hedged item is sold or terminated early, or when an anticipated transaction is no longer expected to occur.

110        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company also enters into cash flow hedges and fair value hedges for activities subject to rate regulation. The gains and losses arising from changes in the 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 Regulatory Assets or Regulatory Liabilities. When the hedges are settled, the realized gains or losses are refunded to or collected from 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 OCI and the ineffective portion is recognized in Net Income. The amounts recognized previously in AOCI are reclassified to Net Income in the event the Company reduces its net investment in a foreign operation.

Asset Retirement Obligations

The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation 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.

The scope and timing of asset retirements related to regulated natural gas pipelines, oil pipelines and hydroelectric power plants is uncertain. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities. The Company has not recorded an amount for ARO related to the nuclear assets, 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. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.

Emission allowances or credits purchased for compliance are recorded on the Balance Sheet at historical cost and expensed when they are retired. Compliance payments are expensed when incurred. Allowances granted to or internally generated by TransCanada are not attributed a value for accounting purposes. When required, TransCanada accrues emission liabilities on the Balance Sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and recorded in Revenues.

Employee Benefit and Other Plans

The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a Savings Plan and other post-employment benefit plans. Contributions made by the Company to the DC Plans and Savings Plan are expensed when incurred. The cost of the DB Plans and other post-employment benefits received 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 age 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 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, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits 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

Business Combinations, Consolidated Financial Statements and Non-Controlling Interests

The Canadian Institute of Chartered Accountants (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,

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        111

recognition of additional assets and liabilities, and increased disclosure. Adopting the 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". Sections 1601 and 1602 will require Non-Controlling Interests 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 of income between the controlling and non-controlling interests. These standards will be effective January 1, 2011. Changes resulting from the adoption of Section 1582 will be applied prospectively and changes resulting from the adoption of Sections 1601 and 1602 will be applied retrospectively.

International Financial Reporting Standards

The CICA Accounting Standards Board (AcSB) previously announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) effective January 1, 2011. As a U.S. Securities and Exchange Commission registrant, TransCanada prepares and files a "Reconciliation to United States GAAP" and has the option to prepare and file its consolidated financial statements using U.S. GAAP. Previously, TransCanada disclosed that, effective January 1, 2011, the Company expected to begin reporting under IFRS. As a result of the developments noted below, management expects that the Company will adopt U.S. GAAP effective January 1, 2012. The Company's IFRS conversion project was proceeding as planned to meet the conversion date of January 1, 2011, prior to these developments.

In accordance with Canadian GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. These RRA standards allow the timing of recognition of certain expenses and revenues to differ from the timing that may otherwise be expected in a non-rate-regulated business under Canadian GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. These timing differences are recorded as Regulatory Assets and Regulatory Liabilities on TransCanada's Consolidated Balance Sheet and represent current rights and obligations regarding cash flows expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities. At December 31, 2010, TransCanada reported regulatory assets of $1.8 billion and regulatory liabilities of $0.4 billion in addition to certain other impacts of RRA.

In July 2009, the IASB issued an Exposure Draft, Rate-Regulated Activities, which proposed a form of RRA under IFRS. At its September 2010 meeting, the IASB concluded that the development of RRA under IFRS requires further analysis and removed the RRA project from its current agenda. The IASB is considering what form a future project might take, if any, to address RRA. TransCanada does not expect a final RRA standard under IFRS to be effective for 2012.

In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises that use RRA in order to permit these entities to defer the adoption of IFRS for one year. Due to the continued uncertainty around the timing, scope and eventual adoption of an RRA standard under IFRS, TransCanada will defer its adoption of IFRS accordingly and continue preparing its consolidated financial statements in 2011 in accordance with Canadian GAAP, as defined by Part V of the CICA Handbook, in order to continue using RRA. TransCanada will continue to actively monitor IASB developments with respect to RRA and other IFRS.

U.S. GAAP Conversion Project

The impact of adopting U.S. GAAP is consistent with that currently reported in the Company's publicly filed "Reconciliation to United States GAAP". Significant changes to existing systems and processes are not required to implement U.S. GAAP as the Company's primary accounting standard.

TransCanada's IFRS conversion team has been redeployed to support the conversion to U.S. GAAP. All staff affected by the conversion will be provided with in-depth U.S. GAAP training and technical research will be conducted. The conversion team is led by a multi-disciplinary Steering Committee that provides directional leadership for the likely adoption of U.S. GAAP. Management also updates TransCanada's Audit Committee on the progress of this project and on any pertinent developments related to IFRS at each Audit Committee meeting.

NOTE 4    SEGMENTED INFORMATION

During 2010, the Company recognized a separate segment, Oil Pipelines. Also during this period, Keystone Wood River/Patoka began delivering oil at reduced operating pressure due to regulatory restrictions. Therefore, the Company continued to classify Wood River/Patoka as under construction along with the Cushing Extension and the U.S. Gulf Coast Expansion. At December 31, 2010, Keystone capital costs were net of $99 million of operating cash flows relating to Wood River/Patoka. Total assets and capital expenditures relating to TransCanada's Oil Pipelines segment are separately identified in this note. The corresponding items of segmented information have been restated, where necessary, in the 2009 and 2008 comparative figures.

112        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year ended December 31, 2010 (millions of dollars)	Natural Gas Pipelines		Energy		Corporate		Total
Revenues	4,373		3,691		–		8,064
Plant operating costs and other(1)	(1,458	)	(1,557	)	(99	)	(3,114	)
Commodity purchases resold	–		(1,017	)	–		(1,017	)
Depreciation and amortization	(977	)	(377	)	–		(1,354	)
Valuation provision for MGP	(146	)	–		–		(146	)
	1,792		740		(99	)	2,433
Interest expense							(701	)
Interest expense of joint ventures							(59	)
Interest income and other							94
Income taxes							(380	)
Non-controlling interests							(115	)
Net Income							1,272
Preferred share dividends							(45	)
Net Income Applicable to Common Shares							1,227

⁽¹⁾

In 2010, Natural Gas Pipelines included $17 million of general, administrative and support costs relating to Keystone.

Year ended December 31, 2009 (millions of dollars)	Natural Gas Pipelines		Energy		Corporate		Total
Revenues	4,729		3,452		–		8,181
Plant operating costs and other	(1,607	)	(1,489	)	(117	)	(3,213	)
Commodity purchases resold	–		(831	)	–		(831	)
Depreciation and amortization	(1,030	)	(347	)	–		(1,377	)
	2,092		785		(117	)	2,760
Interest expense							(954	)
Interest expense of joint ventures							(64	)
Interest income and other							121
Income taxes							(387	)
Non-controlling interests							(96	)
Net Income							1,380
Preferred share dividends							(6	)
Net Income Applicable to Common Shares							1,374
Year ended December 31, 2008 (millions of dollars)	Natural Gas Pipelines		Energy		Corporate		Total
Revenues	4,650		3,897		–		8,547
Plant operating costs and other	(1,614	)	(1,258	)	(104	)	(2,976	)
Commodity purchases resold	–		(1,429	)	–		(1,429	)
Depreciation and amortization	(989	)	(258	)	–		(1,247	)
Calpine bankruptcy settlements	279		–		–		279
Write-down of Broadwater LNG project costs(1)	–		(41	)	–		(41	)
	2,326		911		(104	)	3,133
Interest expense							(943	)
Interest expense of joint ventures							(72	)
Interest income and other							54
Income taxes							(602	)
Non-controlling interests							(130	)
Net Income							1,440

⁽¹⁾

In 2008, TransCanada wrote down $41 million of capitalized costs related to the Broadwater liquefied natural gas (LNG) project after the New York Department of State rejected a proposal to construct this facility.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        113

TOTAL ASSETS

December 31 (millions of dollars)	2010	2009
Natural Gas Pipelines	23,592	23,724
Oil Pipelines	8,501	5,784
Energy	12,847	12,477
Corporate	1,649	1,856
	46,589	43,841

GEOGRAPHIC INFORMATION

Year ended December 31 (millions of dollars)	2010	2009	2008
Revenues(1)
Canada – domestic	4,368	5,079	4,551
Canada – export	838	756	1,125
United States and other	2,858	2,346	2,871
	8,064	8,181	8,547

⁽¹⁾

Revenues are attributed based on the country in which the product or service originated.

December 31 (millions of dollars)	2010	2009
Plant, Property and Equipment
Canada	21,561	20,266
United States and other	14,683	12,613
	36,244	32,879

CAPITAL EXPENDITURES

Year ended December 31 (millions of dollars)	2010	2009	2008
Natural Gas Pipelines	1,196	965	916
Oil Pipelines	2,696	2,939	938
Energy	1,129	1,487	1,266
Corporate	15	26	14
	5,036	5,417	3,134

114        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5    PLANT, PROPERTY AND EQUIPMENT

		2010			2009
December 31 (millions of dollars)		Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
Natural Gas Pipelines(1)
Canadian Mainline
	Pipeline	8,768	4,730	4,038	8,752	4,501	4,251
	Compression	3,385	1,651	1,734	3,379	1,529	1,850
	Metering and other	381	167	214	364	153	211
		12,534	6,548	5,986	12,495	6,183	6,312
	Under construction	14	–	14	27	–	27
		12,548	6,548	6,000	12,522	6,183	6,339
Alberta System
	Pipeline	6,528	2,917	3,611	6,002	2,777	3,225
	Compression	1,707	1,045	662	1,696	983	713
	Metering and other	909	378	531	879	342	537
		9,144	4,340	4,804	8,577	4,102	4,475
	Under construction	71	–	71	281	–	281
		9,215	4,340	4,875	8,858	4,102	4,756
ANR
	Pipeline	858	96	762	848	79	769
	Compression	507	74	433	489	65	424
	Metering and other	548	74	474	646	67	579
		1,913	244	1,669	1,983	211	1,772
	Under construction	7	–	7	23	–	23
		1,920	244	1,676	2,006	211	1,795
GTN
	Pipeline	1,079	233	846	1,135	205	930
	Compression	395	67	328	414	59	355
	Metering and other	78	19	59	93	22	71
		1,552	319	1,233	1,642	286	1,356
	Under construction	5	–	5	22	–	22
		1,557	319	1,238	1,664	286	1,378
Joint Ventures and Others
	Great Lakes	1,540	698	842	1,608	694	914
	Foothills	1,650	975	675	1,645	917	728
	Northern Border	1,252	608	644	1,316	613	703
	Other(2)	2,913	633	2,280	2,307	587	1,720
		7,355	2,914	4,441	6,876	2,811	4,065
		32,595	14,365	18,230	31,926	13,593	18,333
Oil Pipelines
Keystone
	Under construction(3)	8,184	–	8,184	5,305	–	5,305
		8,184	–	8,184	5,305	–	5,305
Energy
Nuclear(4)		1,586	536	1,050	1,536	451	1,085
Natural Gas – Ravenswood		1,710	144	1,566	1,712	82	1,630
Natural Gas – Other(5)(6)		2,767	588	2,179	2,032	522	1,510
Hydro		599	69	530	625	56	569
Wind(7)		659	65	594	611	41	570
Natural Gas Storage		423	67	356	418	56	362
Other		160	96	64	156	89	67
		7,904	1,565	6,339	7,090	1,297	5,793
Under construction – Nuclear(8)		2,678	–	2,678	2,078	–	2,078
Under construction – Other(9)		728	–	728	1,287	–	1,287
		11,310	1,565	9,745	10,455	1,297	9,158
Corporate		125	40	85	110	27	83
		52,214	15,970	36,244	47,796	14,917	32,879

⁽¹⁾

In 2010, the Company capitalized $35 million (2009 – $33 million) relating to the equity portion of AFUDC for natural gas pipelines with a corresponding amount recorded in Interest Income and Other.

⁽²⁾

Includes in-service assets of Portland, Iroquois, TQM, North Baja, Tamazunchale, Ventures LP and Tuscarora, and under construction amounts of $622 million (2009 – $200 million) and $277 million (2009 – $29 million) for Bison and Guadalajara, respectively. Bison went into service in January 2011.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        115

⁽³⁾

Includes $1.4 billion at December 31, 2010 relating to the Keystone U.S. Gulf Coast Expansion. This phase of Keystone remains subject to regulatory approvals.

⁽⁴⁾

Includes assets under capital lease relating to Bruce Power.

⁽⁵⁾

Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $89 million and $19 million, respectively, at December 31, 2010 (2009 – $93 million and $17 million, respectively). Revenues of $15 million were recognized in 2010 (2009 – $15 million; 2008 – $14 million) through the sale of electricity under the related PPAs.

⁽⁶⁾

Includes Halton Hills effective September 1, 2010.

⁽⁷⁾

Includes phase two of Kibby Wind effective October 2010.

⁽⁸⁾

Nuclear assets under construction primarily includes expenditures for the refurbishment and restart of Bruce A.

⁽⁹⁾

Other Energy assets under construction at December 31, 2010 includes amounts for Coolidge and two Cartier Wind farms, Gros-Morne and Montagne-Sèche.

NOTE 6    GOODWILL

The Company has recorded the following goodwill on its acquisitions in the U.S.:

(millions of dollars)	Natural Gas Pipelines		Energy		Total
Balance at January 1, 2009	3,382		1,015		4,397
Foreign exchange	(491	)	(143	)	(634	)
Balance at December 31, 2009	2,891		872		3,763
Foreign exchange	(144	)	(49	)	(193	)
Balance at December 31, 2010	2,747		823		3,570

NOTE 7    INTANGIBLES AND OTHER ASSETS

December 31 (millions of dollars)	2010	2009
PPAs(1)	539	593
Employee benefit plans (Note 22)	473	383
Fair value of derivative contracts (Note 18)	374	260
Loans and advances(2)	241	417
Equity investments(3)	78	84
Margin calls	76	91
Deferred project development costs(4)	–	470
Other	245	202
	2,026	2,500

⁽¹⁾

The following amounts related to PPAs are included in the consolidated financial statements:

	2010			2009
December 31 (millions of dollars)	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
PPAs	919	380	539	915	322	593

Amortization expense for the PPAs was $58 million for the year ended December 31, 2010 (2009 and 2008 – $58 million). The expected annual amortization expense in each of the next five years is $57 million.

⁽²⁾

As at December 31, 2010, TransCanada held a $281 million (2009 – $317 million) note receivable from the seller of Ravenswood which bears interest at 6.75 per cent and matures in 2039. Loans and advances includes $241 million (2009 – $274 million) of this note receivable.

⁽³⁾

The balance primarily relates to the Company's 46.5 per cent ownership interest in TransGas.

⁽⁴⁾

At December 31, 2009, $470 million related to the Keystone U.S. Gulf Coast Expansion. This project is included in Plant, Property and Equipment at December 31, 2010.

116        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Advances to Aboriginal Pipeline Group

The Mackenzie Delta gas producers, the Aboriginal Pipeline Group (APG) and TransCanada have an agreement governing TransCanada's role in the Mackenzie Gas Project (MGP). The project is expected to result in a natural gas pipeline being constructed from Inuvik, Northwest Territories, to the northern border of Alberta, where it would connect to the Alberta System. Under the agreement, TransCanada agreed to finance the APG for its one-third share of project pre-development costs.

The MGP proponents continue to pursue the required regulatory approvals for the project and the Canadian government's support of an acceptable fiscal framework. In December 2010, the NEB released a decision granting approval of the project's application for a Certificate of Public Convenience and Necessity. The approval contained 264 conditions including the requirement to file an updated cost estimate and report on the decision to construct by the end of 2013 and, further, that construction must commence by December 31, 2015.

Nevertheless, uncertainty persists with respect to the project's ultimate commercial structure and fiscal framework, the timeframes under which the project would proceed and if and when the Company's advances to the APG will be repaid. Accordingly, at December 31, 2010, TransCanada recorded a valuation provision for its $146 million loan to the APG. Future amounts advanced to the APG in furtherance of the MGP will be expensed. TransCanada remains committed to advancing the project. At December 31, 2010, Loans and Advances included nil (2009 – $143 million) for advances to the APG.

NOTE 8    JOINT VENTURE INVESTMENTS

		TransCanada's Proportionate Share
		Income before Income Taxes Year Ended December 31			Net Assets December 31
(millions of dollars)	Ownership Interest as at December 31, 2010	2010	2009	2008	2010	2009
Natural Gas Pipelines
Northern Border(1)		69	47	59	389	420
Iroquois	44.5%	40	44	32	181	183
TQM	50.0%	16	22	12	85	82
Other	Various	16	17	8	36	56
Energy
Bruce A	48.8%	35	3	46	3,011	2,386
Bruce B	31.6%	138	236	136	505	585
CrossAlta	60.0%	45	55	44	73	77
Portlands Energy(2)	50.0%	33	24	–	335	358
Cartier Wind(3)	62.0%	24	26	12	355	327
Other	Various	8	4	9	103	99
		424	478	358	5,073	4,573

⁽¹⁾

The results reflect a 50 per cent interest in Northern Border as a result of the Company fully consolidating PipeLines LP. At December 31, 2010, TransCanada had an ownership interest in PipeLines LP of 38.2 per cent (2009 – 38.2 per cent; 2008 – 32.1 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 19.1 per cent (2009 – 19.1 per cent; 2008 – 16.1 per cent).

⁽²⁾

Portlands Energy began operating in April 2009.

⁽³⁾

TransCanada proportionately consolidates its 62 per cent interest in the Cartier Wind assets. Carleton, the third phase of the five-phase Cartier Wind project, began operating in November 2008.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        117

Summarized Financial Information of Joint Ventures

Year ended December 31 (millions of dollars)	2010		2009		2008
Income
Revenues	1,602		1,598		1,474
Plant operating costs and other	(913	)	(856	)	(893	)
Depreciation and amortization	(208	)	(196	)	(154	)
Interest expense and other	(57	)	(68	)	(69	)
Proportionate Share of Joint Venture Income before Income Taxes	424		478		358

Year ended December 31 (millions of dollars)	2010		2009		2008
Cash Flows
Operating activities	345		203		389
Investing activities	(926	)	(399	)	(1,754	)
Financing activities(1)	588		130		1,353
Effect of foreign exchange rate changes on cash and cash equivalents	(1	)	(17	)	23
Proportionate Share of Increase/(Decrease) in Cash and Cash Equivalents of Joint Ventures	6		(83	)	11

⁽¹⁾

Financing activities included cash outflows resulting from distributions paid to TransCanada of $239 million in 2010 (2009 – $252 million; 2008 – $287 million) and cash inflows resulting from capital contributions paid by TransCanada of $902 million in 2010 (2009 – $864 million; 2008 – $1,170 million).

December 31 (millions of dollars)	2010		2009
Balance Sheet
Cash and cash equivalents	104		98
Other current assets	438		552
Plant, property and equipment	5,704		5,239
Intangibles and other assets/(deferred amounts), net	14		10
Current liabilities	(387	)	(572	)
Long-term debt	(801	)	(753	)
Future income taxes	1		(1	)
Proportionate Share of Net Assets of Joint Ventures	5,073		4,573

118        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9    ACQUISITIONS AND DISPOSITIONS

Oil Pipelines

Keystone

In August 2009, TransCanada purchased ConocoPhillips' remaining ownership interest in Keystone of approximately 20 per cent for US$553 million plus the assumption of US$197 million of short-term debt. The acquisition increased TransCanada's ownership interest in Keystone to 100 per cent and was recorded in Plant, Property and Equipment. The purchase price reflected ConocoPhillips' capital contributions to date and included capitalization of interest during construction. TransCanada began fully consolidating Keystone upon acquisition.

In 2008, TransCanada entered into an agreement with ConocoPhillips to increase its equity ownership in Keystone to approximately 80 per cent from 50 per cent, with ConocoPhillips' equity ownership in Keystone being reduced concurrently to approximately 20 per cent from 50 per cent. Pursuant to this agreement in 2008 and prior to August 2009, TransCanada funded 100 per cent of the construction expenditures until the participants' project capital contributions were aligned with their revised ownership interests. In 2009, prior to August, TransCanada funded $1.3 billion of cash calls for Keystone, resulting in the Company acquiring an increase in ownership of approximately 18 per cent for $313 million. In 2008, the Company funded $362 million of cash calls, resulting in an increase in ownership of approximately 12 per cent for $176 million. TransCanada's ownership interest was approximately 80 per cent and 62 per cent in August 2009 and at December 31, 2008, respectively. TransCanada proportionately consolidated the Keystone partnerships prior to August 2009.

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 $67 million, with no gain recognized on the sale.

Natural Gas Pipelines

TC PipeLines, LP

In November 2009, PipeLines LP completed an offering of five million common units at a price of US$38.00 per unit, resulting in net proceeds to PipeLines LP of US$182 million. TransCanada contributed an additional US$3.8 million to maintain its general partnership interest but did not purchase any other units. Upon completion of this offering, the Company's ownership interest in PipeLines LP decreased to 38.2 per cent and the Company recognized a dilution gain of $18 million after tax ($29 million pre-tax).

In July 2009, TransCanada sold North Baja to PipeLines LP. As part of the transaction, TransCanada agreed to amend its general partner incentive distribution rights arrangement with PipeLines LP. TransCanada received aggregate consideration totalling approximately US$395 million from PipeLines LP, including US$200 million in cash and 6,371,680 common units of PipeLines LP. TransCanada recorded no gain or loss as a result of the transaction. TransCanada's ownership in PipeLines LP increased to 42.6 per cent as a result of the transaction. TransCanada's increased ownership in PipeLines LP also resulted in a decrease in Non-Controlling Interests and an increase in Contributed Surplus.

Energy

Ravenswood

In August 2008, TransCanada acquired from National Grid plc 100 per cent of the 2,480 MW Ravenswood power facility for US$2.9 billion. TransCanada began consolidating Ravenswood into its Energy segment after the acquisition date. The purchase price was allocated as follows:

(millions of US dollars)
Current assets	128
Plant, property and equipment	1,666
Other non-current assets	305
Goodwill	834
Current liabilities	(11	)
Other non-current liabilities	(10	)
	2,912

The allocation of the purchase price was made using the fair value of the net assets at the date of acquisition. Factors that contributed to goodwill included the opportunity to expand the Energy segment further into the U.S. market and to gain a stronger competitive position in the North American power generation business. The goodwill recognized on the transaction is amortizable for tax purposes.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        119

NOTE 10    LONG-TERM DEBT

			2010		2009
Outstanding loan amounts (millions of dollars)		Maturity Dates	Outstanding December 31	Interest Rate(1)	Outstanding December 31	Interest Rate(1)
TRANSCANADA PIPELINES LIMITED
Debentures
	Canadian dollars	2014 to 2020	872	10.9%	1,002	10.9%
	U.S. dollars (2010 and 2009 – US$600)	2012 to 2021	595	9.5%	626	9.5%
Medium-Term Notes
	Canadian dollars	2011 to 2039	4,150	6.2%	4,148	6.2%
Senior Unsecured Notes
	U.S. dollars (2010 – US$8,626; 2009 –  US$6,496)(2)	2013 to 2040	8,490	5.7%	6,727	6.7%
			14,107		12,503
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
	Canadian dollars	2014 to 2024	390	11.4%	430	11.5%
	U.S. dollars (2010 and 2009 – US$375)	2012 to 2023	371	8.2%	390	8.2%
Medium-Term Notes
	Canadian dollars	2025 to 2030	502	7.4%	502	7.4%
	U.S. dollars (2010 and 2009 – US$33)	2026	32	7.5%	34	7.5%
			1,295		1,356
TRANSCANADA PIPELINE USA LTD.
Bank Loan
	U.S. dollars (2010 and 2009 – US$700)	2012	696	0.5%	733	0.5%
ANR PIPELINE COMPANY
Senior Unsecured Notes
	U.S. dollars (2010 – US$432; 2009 – US$443)	2021 to 2025	429	8.9%	462	9.1%
GAS TRANSMISSION NORTHWEST CORPORATION
Senior Unsecured Notes
	U.S. dollars (2010 – US$325; 2009 – US$400)	2015 to 2035	322	5.5%	417	5.4%
TC PIPELINES, LP
Unsecured Loan
	U.S. dollars (2010 – US$483; 2009 – US$484)	2011	480	0.8%	506	1.0%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
	U.S. dollars (2010 – US$392; 2009 – US$411)	2011 to 2030	389	7.8%	429	7.8%
TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
	U.S. dollars (2010 – US$31; 2009 – US$57)	2012 to 2017	31	4.4%	60	7.3%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes(3)
	U.S. dollars (2010 – US$164; 2009 – US$180)	2018	161	6.1%	186	6.1%
OTHER
Senior Notes
	U.S. dollars (2010 and 2009 – US$12)	2011	12	7.3%	12	7.3%
			17,922		16,664
Less: Current Portion of Long-Term Debt			894		478
			17,028		16,186

120        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

⁽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 of $8 million (2009 – $6 million) for interest rate swap agreements on US$250 million of debt at December 31, 2010 (2009 – US$250 million).

⁽³⁾

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: 2011 – $894 million; 2012 – $1,118 million; 2013 – $894 million; 2014 – $970 million; and 2015 – $1,064 million.

TransCanada PipeLines Limited

In September 2010, TransCanada PipeLines Limited (TCPL) issued US$1.0 billion of Senior Notes maturing October 1, 2020, and bearing interest at 3.80 per cent.

In June 2010, TCPL issued US$500 million and US$750 million of Senior Notes maturing on June 1, 2015 and June 1, 2040, respectively, and bearing interest at 3.40 per cent and 6.10 per cent, respectively.

In February 2010, TCPL retired US$120 million of 6.125 per cent Medium-Term Notes and in August 2010, TCPL retired $130 million of 10.50 per cent debentures.

In October 2009, TCPL retired $250 million of 10.625 per cent debentures.

In February 2009, TCPL issued $300 million and $400 million of Medium-Term Notes maturing in February 2014 and February 2039, respectively, and bearing interest at 5.05 per cent and 8.05 per cent, respectively. Also in February 2009, TCPL retired $200 million of 4.10 per cent Medium-Term Notes.

In January 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. Also in January 2009, TCPL retired US$227 million of 6.49 per cent Medium-Term Notes.

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, 2010.

TransCanada PipeLine USA Ltd.

TransCanada PipeLine USA Ltd. (TCPL USA) has a US$1.0 billion committed, unsecured, syndicated credit facility, guaranteed by TransCanada, consisting of a US$700 million five-year term loan maturing in 2012 and a US$300 million revolving facility maturing in February 2013, described further in Note 20. Included in Long-Term Debt was an outstanding balance of US$700 million on the term loan at December 31, 2010 and 2009.

TC PipeLines, LP

PipeLines LP has available a committed, unsecured syndicated senior credit facility consisting of a US$475 million senior term loan and a US$250 million senior revolving credit facility maturing December 2011. At December 31, 2010, US$8 million (2009 – US$9 million) was drawn on the US$250 million senior revolving credit facility. Included in long-term debt were combined draws of US$483 million at December 31, 2010 (2009 – US$484 million).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        121

Interest Expense

Year ended December 31 (millions of dollars)	2010		2009		2008
Interest on long-term debt	1,149		1,212		970
Interest on junior subordinated notes	65		73		68
Interest on short-term debt	15		10		32
Capitalized interest	(587	)	(358	)	(141	)
Amortization and other financial charges(1)	59		17		14
	701		954		943

⁽¹⁾

Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to rising interest rates.

The Company made interest payments of $652 million in 2010 (2009 – $916 million; 2008 – $833 million) on long-term debt and junior subordinated notes, net of interest capitalized on construction projects.

NOTE 11    LONG-TERM DEBT OF JOINT VENTURES

			2010		2009
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
	U.S. dollars (2010 and 2009 – US$175)	2016 to 2021	174	7.1%	182	7.1%
Bank Facility
	U.S. dollars (2010 – US$96; 2009 –  US$108)	2012	94	0.5%	112	0.5%
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
Senior Unsecured Notes
	U.S. dollars (2010 – US$178; 2009 –  US$210)	2019 to 2027	176	6.1%	219	7.8%
BRUCE POWER L.P. AND BRUCE POWER A L.P.
Capital Lease Obligations		2018	207	7.5%	222	7.5%
Term Loan		2031	90	7.1%	93	7.1%
TRANS QUÉBEC & MARITIMES PIPELINE INC.
Bonds		2014 to 2017	87	4.2%	125	5.2%
Term Loan		2011	35	1.6%	10	0.4%
OTHER		2012 to 2015	3	2.7%	2	2.7%
			866		965
Less: Current Portion of Long-Term Debt of Joint Ventures			65		212
			801		753

⁽¹⁾

Amounts outstanding represent TransCanada's proportionate share, except for Northern Border, which reflects a 50 per cent interest as a result of the Company fully consolidating PipeLines LP.

⁽²⁾

Interest rates are the effective interest rates except for 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, 2010, the effective interest rate resulting from swap agreements was nil on the Northern Border bank facility (2009 – 0.5 per cent).

The long-term debt of joint ventures is non-recourse to TransCanada, except that TransCanada 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 TransCanada, except to the extent of TransCanada's investment. TQM has two series of bonds which mature in 2014 and 2017, respectively. The bonds are secured by the pledge of a bond and

122        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

promissory note of certain affiliated entities. All security interests with respect to the TQM bonds terminate on redemption or repayment of the series of bonds maturing in 2014.

Subject to meeting certain requirements, the Bruce Power capital lease agreements provide for a series of 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: 2011 – $49 million; 2012 – $103 million; 2013 – $7 million; 2014 – $44 million; and 2015 – $7 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: 2011 – $16 million; 2012 – $18 million; 2013 – $20 million; 2014 – $22 million; and 2015 – $26 million.

In September 2009, Northern Border retired US$200 million of 7.75 per cent Senior Notes. In August 2009, Northern Border issued US$100 million of Senior Unsecured Notes maturing in August 2016 and bearing interest at 6.24 per cent.

In April 2010, Iroquois retired US$200 million of Series I bonds bearing interest at 9.16 per cent and issued US$150 million of bonds maturing in April 2020 and bearing interest at 4.96 per cent.

In May 2009, Iroquois issued US$140 million of Senior Unsecured Notes maturing in May 2019 and bearing interest at 6.63 per cent.

In September 2010, TQM retired $100 million of 7.53 per cent Series I bonds and $75 million of 3.906 per cent Series J bonds. In July 2010, TQM issued $100 million of bonds maturing in September 2017 and bearing interest at 4.25 per cent.

In September 2009, TQM issued $75 million of bonds maturing in September 2014 and bearing interest at 4.05 per cent. In August 2009, TQM retired $100 million of 6.50 per cent Series H bonds.

Sensitivity

A one per cent change in interest rates would have the following effect on Net Income assuming all other variables were to remain constant:

(millions of dollars)	Increase	Decrease
Effect on interest expense of variable interest rate debt	1	(1	)

Interest Expense of Joint Ventures

Year ended December 31 (millions of dollars)	2010	2009		2008
Interest on long-term debt	39	51		45
Interest on capital lease obligations	16	17		18
Short-term interest and other financial charges	4	(4	)	9
	59	64		72

The Company's proportionate share of the interest payments by joint ventures was $42 million in 2010 (2009 – $41 million; 2008 – $50 million), net of interest capitalized on construction projects.

The Company's proportionate share of interest payments from the capital lease obligations of Bruce Power was $16 million in 2010 (2009 – $17 million; 2008 – $18 million).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        123

NOTE 12    JUNIOR SUBORDINATED NOTES

		2010		2009
Outstanding loan amount (millions of dollars)	Maturity Date	Outstanding December 31	Effective Interest Rate	Outstanding December 31	Effective Interest Rate
TRANSCANADA PIPELINES LIMITED
U.S. dollars (2010 and 2009 – US$1,000)	2017	985	6.5%	1,036	6.5%

Junior Subordinated Notes of US$1.0 billion mature in 2067 and bear interest at 6.35 per cent per year until May 15, 2017, when interest will convert to a floating rate that is reset quarterly to the three-month London Interbank Offered Rate plus 221 basis points. The Company has the option to defer payment of interest for periods of up to 10 years without giving rise to a default and without permitting acceleration of payment under the terms of the Junior Subordinated Notes. However, the Company would be prohibited from paying dividends during any such 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 other 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.

NOTE 13    DEFERRED AMOUNTS

December 31 (millions of dollars)	2010	2009
Fair value of derivative contracts (Note 18)	282	272
Employee benefit plans (Note 22)	251	235
Asset retirement obligations (Note 21)	65	110
Other	96	126
	694	743

NOTE 14    RATE-REGULATED BUSINESSES

TransCanada's businesses that apply RRA currently include Canadian and U.S. natural gas pipelines and regulated U.S. natural gas storage. Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities. In addition to Canadian GAAP financial reporting, TransCanada's regulated natural gas pipelines file financial reports using accounting regulations required by their respective regulators.

Canadian Regulated Operations

Canadian natural gas transmission services are supplied under natural 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 TransCanada's Canadian regulated pipelines are typically set through a process that involves filing an application with the regulators for a change in rates. Regulated rates are underpinned by the total annual revenue requirement, which comprises a specified annual return on capital, including debt and equity, and all necessary operating expenses, taxes and depreciation.

TransCanada's Canadian regulated natural gas pipelines have generally been subject to a cost-of-service model wherein forecasted costs, including a return on capital, determine 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. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they are incurred.

The Canadian Mainline, Alberta System, Foothills and TQM pipelines are regulated by the NEB under the National Energy Board Act (Canada). In April 2009, the NEB determined that the Alberta System was within federal jurisdiction and would be subject to NEB regulation. Prior to

124        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

April 2009, the Alberta System was regulated by the AUC. The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems.

In October 2009, the NEB issued a decision that its RH-2-94 Decision, which established a rate of return on common equity (ROE) formula that had formed the basis of determining tolls for natural gas pipelines under NEB jurisdiction since 1995, would no longer be in effect. The decision meant a company's cost of capital will now be determined by negotiations between pipeline companies and their shippers or by the NEB if a pipeline company files a cost of capital application. The decision has affected TransCanada's NEB regulated pipelines. However, the Canadian Mainline continues to base its return on the RH-2-94 NEB ROE formula in accordance with the terms of the current Canadian Mainline tolls settlement, described below.

Canadian Mainline

The Canadian Mainline currently operates under a five-year tolls settlement, which is effective January 1, 2007 to December 31, 2011. The Canadian Mainline's cost of capital for establishing tolls under the settlement reflects ROE as determined by the NEB's RH-2-94 ROE formula on a deemed common equity of 40 per cent. The allowed ROE in 2010 for the Canadian Mainline was 8.52 per cent (2009 – 8.57 per cent). The balance of the capital structure is comprised of short- and long-term debt.

The settlement also established the Canadian Mainline's fixed operating, maintenance and administration (OM&A) costs for each of the five years. Variances between actual OM&A costs and those agreed to in the settlement accrued fully to TransCanada from 2007 to 2009. Variances in OM&A costs were shared equally between TransCanada 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 performance-based incentive arrangements. In 2009, the NEB approved an adjustment charge account, which was established to reduce tolls in 2010 under a settlement with stakeholders. In accordance with the terms of the settlement, balances in the adjustment charge account are to be amortized at the composite depreciation rate and included in tolls beginning in 2011.

Alberta System

In September 2010, the NEB approved the Alberta System's 2010 – 2012 Revenue Requirement Settlement Application. The settlement provides for a 9.70 per cent ROE on a deemed common equity of 40 per cent and fixes certain annual OM&A costs during the term. Any variances between actual costs and those agreed to in the settlement accrue to TransCanada. All other costs are treated on a flow-through basis. In 2009, the Alberta System operated under the 2008 – 2009 Revenue Requirement Settlement which established fixed amounts for ROE, income taxes and certain OM&A costs.

Foothills

In June 2010, TransCanada reached an agreement to establish a cost of capital for Foothills that reflects a 9.70 per cent ROE on a deemed common equity of 40 per cent for 2010 to 2012. In 2009, the ROE for Foothills was 8.57 per cent on a deemed common equity of 36 per cent based on the NEB's RH-2-94 ROE formula. A component of OM&A costs is fixed, subject to the terms of the B.C. System/Foothills Integration Settlement, and variances between actual and fixed amounts are shared with customers.

TQM

In June 2010, the NEB approved TQM's final 2009 tolls consisting of a 6.4 per cent after-tax weighted average cost of capital return on rate base and all the cost components addressed in a three-year partial settlement for the years 2007 to 2009, as approved by the NEB in September 2008. In November 2010, the NEB approved TQM's multi-year settlement with its interested parties regarding its annual revenue requirements for 2010, 2011 and 2012. As part of the settlement, the annual revenue requirement comprises fixed and flow-through components. The fixed component includes certain OM&A costs, return on rate base, depreciation, and municipal taxes. Any variances between actual costs and those included in the fixed component accrue to TQM.

U.S. Regulated Operations

TransCanada's U.S. natural gas 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 natural gas storage and transportation services are regulated by the FERC and operate in accordance with FERC-approved tariffs. These tariffs include maximum and minimum rates for services and permit ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline Company rates were established pursuant to a settlement approved by the FERC and effective in 1997. ANR Storage Company's rates were established pursuant to a settlement approved by the FERC and effective in 1990. None of ANR's FERC-regulated operations are required to file for new rates at any time in the future, nor are any of the operations prohibited from filing a case for new rates.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        125

GTN

GTN is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for various services. GTN is permitted to discount or negotiate these rates on a non-discriminatory basis. GTN's rates were established pursuant to a settlement approved by the FERC in January 2008. Under the settlement, a five-year moratorium was established during which GTN and the settling parties are prohibited from taking certain actions under the Natural Gas Act of 1938, including any filings to adjust rates. The settlement requires GTN to file a rate case within seven years of the effective date.

Great Lakes

Great Lakes is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for its various services and permits Great Lakes to discount or negotiate rates on a non-discriminatory basis. In November 2009, the FERC initiated an investigation to determine whether Great Lakes' rates were just and reasonable. In July 2010, the FERC approved a settlement stipulation and agreement filed by Great Lakes that applies to all current and future shippers. The settlement rates were effective May 1, 2010 and will remain in effect until at least November 30, 2011. The settlement includes a moratorium on participants and customers from filing a rate case to place new rates into effect prior to November 1, 2012. There is also a moratorium on Great Lakes from filing a rate case prior to June 1, 2011 to place new rates into effect prior to December 1, 2011.

Regulatory Assets and Liabilities

Year ended December 31 (millions of dollars)	2010	2009	Remaining Recovery/ Settlement Period
			(years)
Regulatory Assets
Future income taxes(1)	1,256	1,305	n/a
Operating and debt-service regulatory assets(2)	237	221	1
Adjustment charge(3)	85	–	32
Other(4)	174	219	n/a
	1,752	1,745
Less: Current portion included in Other Current Assets	240	221
	1,512	1,524
Regulatory Liabilities
Foreign exchange on long-term debt(5)	200	218	1 - 19
Operating and debt-service regulatory liabilities(2)	98	31	1
Other(4)	150	167	n/a
	448	416
Less: Current portion included in Accounts Payable	134	31
	314	385

⁽¹⁾

These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.

⁽²⁾

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 following calendar year. Pre-tax operating results in 2010 would have been $51 million higher (2009 – $424 million lower) had these amounts not been recorded as regulatory assets and liabilities.

⁽³⁾

A regulatory adjustment account of $85 million was established and agreed upon by Canadian Mainline stakeholders to reduce tolls in 2010. The adjustment account will be amortized at the composite depreciation rate commencing in 2011.

⁽⁴⁾

Pre-tax operating results in 2010 would have been $28 million higher (2009 – $82 million lower) had these amounts had not been recorded as regulatory assets and liabilities.

⁽⁵⁾

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 historical foreign exchange rate at the time of issue. 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 RRA, Canadian GAAP would have required the inclusion of these unrealized gains or losses in Net Income.

126        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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)	2010	2009
Non-controlling interest in PipeLines LP(1)	686	705
Preferred shares of subsidiary	389	389
Non-controlling interest in Portland	82	80
	1,157	1,174

The Company's non-controlling interests included in the Consolidated Income Statement were as follows:

Year ended December 31 (millions of dollars)	2010	2009	2008
Non-controlling interest in PipeLines LP(1)	87	66	62
Preferred share dividends of subsidiary	22	22	22
Non-controlling interest in Portland	6	8	46
	115	96	130

⁽¹⁾

Effective November 18, 2009, the non-controlling interest in PipeLines LP was 61.8 per cent (July 1, 2009 to November 17, 2009 – 57.4 per cent; February 22, 2007 to June 30, 2009 – 67.9 per cent).

The non-controlling interests in PipeLines LP and Portland as at December 31, 2010 represented the 61.8 per cent and 38.3 per cent interest, respectively, not owned by TransCanada (2009 – 61.8 per cent and 38.3 per cent, respectively; 2008 – 67.9 per cent and 38.3 per cent, respectively).

In 2010, TransCanada received fees of $2 million from PipeLines LP (2009 and 2008 – $2 million) and $7 million from Portland (2009 – $8 million; 2008 – $7 million) for services provided.

Preferred Shares of Subsidiary

December 31	Number of Shares	Dividend Rate per Share	Redemption Price per Share	2010	2009
	(thousands)			(millions of dollars)	(millions of dollars)
Cumulative First Preferred Shares of Subsidiary
Series U	4,000	$2.80	$50.00	195	195
Series Y	4,000	$2.80	$50.00	194	194
				389	389

The authorized number of preferred shares of TCPL issuable in each series is unlimited. All of the cumulative first preferred shares of TCPL are without par value.

On or after October 15, 2013, TCPL may redeem the Series U preferred shares at $50 per share, and on or after March 5, 2014, TCPL may redeem the Series Y shares at $50 per share.

Cash Dividends

Cash dividends of $22 million or $2.80 per share were paid on the Series U and Series Y preferred shares in each of 2010, 2009 and 2008.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        127

NOTE 16    COMMON SHARES

		Number of Shares	Amount
		(thousands)	(millions of dollars)
Outstanding at January 1, 2008		539,765	6,662
	Issuance of common shares(1)	69,805	2,363
	Dividend reinvestment and share purchase plan	5,976	218
	Exercise of options	925	21
Outstanding at December 31, 2008		616,471	9,264
	Issuance of common shares(1)	58,420	1,792
	Dividend reinvestment and share purchase plan	8,220	254
	Exercise of options	1,248	28
Outstanding at December 31, 2009		684,359	11,338
	Dividend reinvestment and share purchase plan	10,670	378
	Exercise of options	1,201	29
Outstanding at December 31, 2010		696,230	11,745

⁽¹⁾

Net of underwriting commissions and future income taxes.

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares without par value.

In June 2009, TransCanada completed a public offering of 58.4 million common shares at a purchase price of $31.50 per share. The issue, including the full exercise of a 15 per cent over-allotment option by the underwriters, resulted in gross proceeds of $1.8 billion.

In fourth quarter 2008, TransCanada completed a public offering of 35.1 million common shares at a purchase price of $33.00 per share. The issue, including the full exercise of a 15 per cent over-allotment option by the underwriters, resulted in gross proceeds of $1.2 billion.

In May 2008, TransCanada completed a public offering of 34.7 million common shares at a purchase price of $36.50 per share. The issue, including the full exercise of a 15 per cent over-allotment option by the underwriters, resulted in gross proceeds of $1.3 billion.

Net Income per Share

Net income per share is calculated by dividing Net Income Applicable to Common Shares by the weighted average number of common shares. During the year, the weighted average number of common shares of 690.5 million and 691.7 million (2009 – 651.8 million and 652.8 million; 2008 – 569.6 million and 571.5 million) were used to calculate basic and diluted earnings per share, respectively. The increase in the weighted average number of shares for the diluted earnings per share calculation is due to the options exercisable under TransCanada's Stock Option Plan.

128        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock Options

	Number of Options		Weighted Average Exercise Prices	Options Exercisable
	(thousands)			(thousands)
Outstanding at January 1, 2008	8,609		$27.32	6,118
Granted	872		$39.75
Exercised	(925)		$22.26
Forfeited	(55)		$35.23
Outstanding at December 31, 2008	8,501		$29.10	6,461
Granted	1,191		$31.96
Exercised	(1,248)		$21.22
Forfeited	(170)		$35.58
Outstanding at December 31, 2009	8,274		$30.56	6,212
Granted	1,367		$35.32
Exercised	(1,201	)	$22.04
Forfeited	(34	)	$27.35
Outstanding at December 31, 2010	8,406		$32.57	6,458

Stock options outstanding were as follows:

December 31, 2010		Options Outstanding			Options Exercisable
Range of Exercise Prices		Number of Options	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life	Number of Options	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life
		(thousands)		(years)	(thousands)		(years)
$18.01 to $21.43		1,086	$20.54	1.1	1,086	$20.54	1.1
$26.85 to $31.93		1,387	$29.06	2.8	1,316	$28.91	1.9
$31.97 to $33.08		1,677	$32.37	4.6	1,126	$32.57	4.2
	$35.08	1,145	$35.08	6.2	244	$35.08	6.2
	$35.23	1,001	$35.23	2.2	1,001	$35.23	2.2
$36.26 to $38.10		1,163	$37.80	4.3	941	$38.10	3.1
$38.14 to $39.75		947	$39.58	4.1	744	$39.54	4.1
		8,406	$32.57	3.2	6,458	$31.92	2.5

An additional 5.3 million common shares were reserved for future issuance under TransCanada's Stock Option Plan at December 31, 2010. The weighted average fair value of options granted to purchase common shares under the Company's Stock Option Plan was determined to be $5.76 for the year ended December 31, 2010 (2009 – $4.78; 2008 – $3.97). The Company used the Black-Scholes model for determining the fair value of options granted applying the following weighted average assumptions for 2010: four years of expected life (2009 and 2008 – four years); 2.0 per cent interest rate (2009 – 1.7 per cent; 2008 – 3.5 per cent); 27 per cent volatility (2009 – 29 per cent; 2008 – 16 per cent); and 4.7 per cent dividend yield (2009 – 5.2 per cent; 2008 – 4.0 per cent). The amount expensed for stock options, with a corresponding increase in contributed surplus, was $4 million in 2010 (2009 and 2008 – $4 million).

The total intrinsic value of options exercised in 2010 was $17 million (2009 and 2008 – $15 million). As at December 31, 2010, the aggregate intrinsic value of the total options exercisable was $40 million and the total intrinsic value of options outstanding was $47 million. In 2010, the 1.5 million (2009 – 1.2 million; 2008 – 1.4 million) shares that vested had a fair value of $57 million (2009 – $43 million; 2008 – $45 million).

Shareholder Rights Plan

TransCanada's Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any takeover offer for the Company. Under certain circumstances, each common share is entitled to one right that entitles certain holders to purchase two common shares of the Company for the price of one.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        129

Cash Dividends

Cash dividends of $710 million, net of the Dividend Reinvestment and Share Purchase Plan (DRP), or $1.58 per common share were paid in 2010 (2009 – $722 million or $1.50 per common share; 2008 – $577 million or $1.42 per common share).

Dividend Reinvestment and Share Purchase Plan

TransCanada's Board of Directors has authorized the issuance of common shares from treasury at a discount to participants in the Company's DRP. Under this plan, eligible holders of common or preferred shares of TransCanada and preferred shares of TCPL may reinvest their dividends and make optional cash payments to obtain 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 three per cent in 2009 and 2010, and was reduced to two per cent commencing with the dividends declared in February 2011. The discount was set at two per cent for 2008 and was increased to three per cent commencing with the dividends declared in February 2009. The Company reserves the right to alter the discount or to satisfy its DRP obligations by instead purchasing shares on the open market at any time. In 2010, dividends of $378 million were paid (2009 – $254 million; 2008 – $218 million) through the issuance of 10.7 million (2009 – 8.2 million; 2008 – 6.0 million) common shares from treasury in accordance with the DRP.

NOTE 17    PREFERRED SHARES

December 31	Number of Shares Authorized and Outstanding	Dividend Rate per Share	Redemption Price per Share	2010	2009
	(thousands)			(millions of dollars)(1)	(millions of dollars)(1)
Cumulative First Preferred Shares
Series 1	22,000	$1.15	$25.00	539	539
Series 3	14,000	$1.00	$25.00	343	–
Series 5	14,000	$1.10	$25.00	342	–
				1,224	539

⁽¹⁾

Net of underwriting commissions and future income taxes.

In June 2010, TransCanada completed a public offering of 14 million Series 5 cumulative redeemable first preferred shares, including the full exercise of an underwriters' option of two million shares. The preferred shares were issued at a price of $25 per share, resulting in gross proceeds of $350 million including the underwriters' option. The holders of the Series 5 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.10 per share, payable quarterly, yielding 4.4 per cent per annum for the initial five-and-a-half-year period ending January 30, 2016. The dividend rate will reset on January 30, 2016 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.54 per cent. The Series 5 preferred shares are redeemable by TransCanada on January 30, 2016 and on January 30 of every fifth year thereafter at a price of $25 per share plus all accrued and unpaid dividends.

The Series 5 preferred shareholders have the right to convert their shares into Series 6 cumulative redeemable first preferred shares on January 30, 2016 and on January 30 of every fifth year thereafter. The holders of Series 6 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.54 per cent.

In March 2010, TransCanada completed a public offering of 14 million Series 3 cumulative redeemable first preferred shares, including the full exercise of an underwriters' option of two million shares. The preferred shares were issued at a price of $25 per share, resulting in gross proceeds of $350 million including the underwriters' option. The holders of the Series 3 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly, yielding 4.0 per cent per annum for the initial five-year period ending June 30, 2015. The dividend rate will reset on June 30, 2015 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.28 per cent. The Series 3 preferred shares are redeemable by TransCanada on June 30, 2015 and on June 30 of every fifth year thereafter at a price of $25 per share plus all accrued and unpaid dividends.

The Series 3 preferred shareholders have the right to convert their shares into Series 4 cumulative redeemable first preferred shares on June 30, 2015 and on June 30 of every fifth year thereafter. The holders of Series 4 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.28 per cent.

130        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In September 2009, TransCanada completed a public offering of 22 million Series 1 cumulative redeemable first preferred shares for gross proceeds of $550 million. The holders of the Series 1 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.15 per share, payable quarterly, yielding 4.6 per cent per annum for the initial five-year period ending December 31, 2014. The dividend rate will reset on December 31, 2014 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield plus 1.92 per cent. The preferred shares are redeemable by TransCanada on or after December 31, 2014 at a price of $25 per share plus all accrued and unpaid dividends.

The Series 1 preferred shareholders have the right to convert their shares into Series 2 cumulative redeemable first preferred shares on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 2 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.92 per cent.

The preferred shareholders are eligible to participate in the Company's DRP.

Cash Dividends

In 2010, the Company made cash dividend payments of $24 million, net of DRP, or $1.15 per Series 1 preferred share (2009 – $6 million or $0.2875 per share), $11 million, net of DRP, or $0.8041 per Series 3 preferred share and $9 million, net of DRP, or $0.3707 per Series 5 preferred share.

NOTE 18    RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

TransCanada has exposure to market risk, counterparty credit risk and liquidity risk. TransCanada engages in risk management activities with the objective of protecting earnings, cash flow and, ultimately, shareholder value.

Risk management strategies, policies and limits are designed to ensure TransCanada'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.

Market Risk

The Company constructs and invests in large infrastructure projects, purchases and sells energy 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 strategy to manage the 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. TransCanada 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.

Where possible, derivative financial instruments are designated as hedges, but in some cases derivatives do not meet the specific criteria for hedge accounting treatment and are accounted for at fair value with changes in fair value recorded in Net Income in the period of change. This may expose the Company to increased variability in reported operating results because the fair value of the derivative instruments can fluctuate significantly from period to period. However, the Company enters into the arrangements as they are considered to be effective economic hedges.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        131

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 its overall risk management strategy, the Company commits a 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 sale price of electricity on the cost of natural gas, effectively locking in a margin. A significant portion of the electricity needed to fulfil the Company's power sales commitments is fulfilled through power generation or purchased through contracts, thereby reducing the Company's exposure to fluctuating commodity prices.

•

The Company enters into offsetting or back-to-back positions using 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 fair value accounting is not required, 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 and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain exemptions.

Natural Gas Storage Commodity Price Risk

TransCanada manages its exposure to seasonal natural gas price spreads in its non-regulated 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. TransCanada 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 natural gas price movements. Fair value adjustments recorded each period on proprietary natural gas inventory in storage and on these forward contracts are not representative of the amounts that will be realized on settlement.

At December 31, 2010, the fair value of proprietary natural gas inventory in storage, measured using a weighted average of forward prices for the following four months less selling costs, was $49 million (2009 – $73 million). The change in fair value of proprietary natural gas inventory in storage in 2010 resulted in pre-tax unrealized losses of $16 million (2009 – gains of $3 million; 2008 – losses of $7 million), which were recorded as a decrease to Revenues and to Inventories. The change in fair value of natural gas forward purchase and sales contracts in 2010 resulted in pre-tax unrealized gains of $6 million (2009 – losses of $2 million; 2008 – gains of $7 million), which were recorded as an increase to Revenues and to Inventories.

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 market interest rates.

A portion of TransCanada's earnings from its Natural Gas Pipelines and Energy segments is generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TransCanada's net income. This foreign exchange impact is partially offset by U.S. dollar-denominated financing costs and by the Company's hedging activities. TransCanada has a greater exposure to U.S. currency fluctuations than in prior years due to growth in its U.S. operations, partially offset by increased levels of U.S. dollar-denominated interest expense.

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 foreign exchange rate exposures of the Alberta System and Foothills operations. Certain of the realized gains and losses on these derivatives 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.

TransCanada has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of 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, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At December 31, 2010, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $9.8 billion (US$9.8 billion) (2009 – $7.9 billion (US$7.6 billion)) and a fair value of $11.3 billion (US$11.4 billion) (2009 – $9.8 billion (US$9.3 billion)). At December 31, 2010, $181 million was included in Intangibles and Other Assets (2009 – $96 million) for the fair value of the forwards, swaps and options used to hedge the Company's net U.S. dollar investment in foreign operations.

132        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows:

		2010		2009
Asset/(Liability) December 31 (millions of dollars)		Fair Value(1)	Notional or Principal Amount	Fair Value(1)	Notional or Principal Amount
U.S. dollar cross-currency swaps
	(maturing 2011 to 2016)	179	US 2,800	86	US 1,850
U.S. dollar forward foreign exchange contracts
	(maturing 2011)	2	US    100	9	US    765
U.S. dollar options
	(matured in 2010)	–	–	1	US    100
		181	US 2,900	96	US 2,715

⁽¹⁾

Fair values equal carrying values.

VaR Analysis

TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its liquid open positions. VaR represents the potential change in pre-tax earnings over a given holding period for a specified confidence level. The VaR number used by TransCanada is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its liquid open 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.

TransCanada'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 regulated natural gas pipelines, as the nature of the rate-regulated pipeline business reduces the impact of market risks. TransCanada'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. TransCanada's consolidated VaR was $12 million at December 31, 2010 (2009 – $12 million).

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 they will protect it against all material losses.

TransCanada's maximum counterparty credit exposure with respect to financial instruments at the Balance Sheet date, without taking into account security held, consisted of accounts receivable, the fair value of derivative assets and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table located in the Fair Values section of this note. Letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties that are investment grade. At December 31, 2010, there were no significant amounts past due or impaired.

At December 31, 2010, the Company had a credit risk concentration of $317 million (2009 – $334 million) due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.

TransCanada 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 TransCanada's exposure to non-creditworthy counterparties.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        133

As a level of uncertainty continues to exist in the global financial markets, TransCanada continues to closely monitor and reassess the creditworthiness of its counterparties. This has resulted in TransCanada reducing or mitigating its exposure to certain counterparties where it was deemed warranted and permitted under contractual terms. As part of its ongoing operations, TransCanada must balance its market and counterparty credit risks when making business decisions.

Calpine Corporation (Calpine) and certain of its subsidaries filed for bankruptcy protection in Canada or the U.S. in 2005. Gas Transmission Northwest Corporation (GTNC) and Portland reached agreements with Calpine for allowed unsecured claims in the Calpine bankruptcy. In February 2008, GTNC and Portland received initial distributions of 9.4 million common shares and 6.1 million common shares, respectively, of Calpine, which represented approximately 85 per cent of their agreed-upon claims. In 2008, these shares were 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 were passed onto shippers on these systems in 2008 and 2009. In 2010, the Company accrued an additional pre-tax gain of $15 million related to expected future proceeds with respect to the GTNC and Portland claims.

Liquidity Risk

Liquidity risk is the risk that TransCanada will not be able to meet its financial obligations as they become due. The Company's approach to managing liquidity risk is to ensure that sufficient cash and credit facilities are available to meet its operating, financing and capital expenditure obligations when due, under both normal and stressed economic conditions.

Management continuously 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 in the Capital Management section of this note.

At December 31, 2010, the Company had unutilized committed revolving bank lines of US$1.0 billion, $2.0 billion and US$0.8 billion maturing in November 2011, December 2012 and December 2012, respectively. The Company has also maintained continuous access to the Canadian commercial paper market on competitive terms.

Capital Management

The primary objective of capital management is to ensure TransCanada has strong credit ratings to support its businesses and maximize shareholder value. In 2010, the overall objective and policy for managing capital remained unchanged from the prior year.

TransCanada 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 comprises Notes Payable, 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 TransCanada's joint ventures.

The total capital managed by the Company was as follows:

December 31 (millions of dollars)	2010		2009
Notes payable	2,081		1,678
Long-term debt	17,922		16,664
Junior subordinated notes	985		1,036
Cash and cash equivalents	(660	)	(896	)
Net debt	20,328		18,482
Non-controlling interests	1,157		1,174
Shareholders' equity	16,727		15,759
Total equity	17,884		16,933
	38,212		35,415

Fair Values

Certain financial instruments included in Cash and Cash Equivalents, Accounts Receivable, Intangibles and Other Assets, Notes Payable, Accounts Payable, Accrued Interest and Deferred Amounts have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity. The fair value of foreign exchange and interest rate derivatives has been calculated using year-end market rates and applying a discounted cash flow valuation model. The fair value of power, natural gas and oil products derivatives, and of available-for-sale investments, has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used.

134        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of the Company's Notes Receivable is calculated by discounting future payments of interest and principal using forward interest rates. Long-Term Debt was estimated based on quoted market prices for the same or similar debt instruments. Credit risk has been taken into consideration when calculating the fair value of derivatives, Notes Receivable and Long-Term Debt.

Non-Derivative Financial Instruments Summary

The carrying and fair values of non-derivative financial instruments were as follows:

	2010		2009
December 31 (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Financial Assets(1)
Cash and cash equivalents	764	764	997	997
Accounts receivable and other(2)(3)	1,555	1,595	1,432	1,483
Available-for-sale assets(2)	20	20	23	23
	2,339	2,379	2,452	2,503
Financial Liabilities(1)(3)
Notes payable	2,092	2,092	1,687	1,687
Accounts payable and deferred amounts(4)	1,436	1,436	1,538	1,538
Accrued interest	367	367	377	377
Long-term debt	17,922	21,523	16,664	19,377
Junior subordinated notes	985	992	1,036	976
Long-term debt of joint ventures	866	971	965	1,025
	23,668	27,381	22,267	24,980

⁽¹⁾

Consolidated Net Income in 2010 included gains of $8 million (2009 – gains of $6 million) for fair value adjustments related to interest rate swap agreements on US$250 million (2009 – US$250 million) of long-term debt. There were no other unrealized gains or losses from fair value adjustments to the financial instruments.

⁽²⁾

At December 31, 2010, the Consolidated Balance Sheet included financial assets of $1,271 million (2009 – $966 million) in Accounts Receivable, $40 million (2009 – nil) in Other Current Assets and $264 million (2009 – $489 million) in Intangibles and Other Assets.

⁽³⁾

Recorded at amortized cost except for $250 million (2009 – $250 million) of Long-Term Debt, which is adjusted to fair value.

⁽⁴⁾

At December 31, 2010, the Consolidated Balance Sheet included financial liabilities of $1,406 million (2009 – $1,513 million) in Accounts Payable and $30 million (2009 – $25 million) in Deferred Amounts.

The following tables detail the remaining contractual maturities for TransCanada's non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2010:

Contractual Repayments of Financial Liabilities⁽¹⁾

		Payments Due by Period
(millions of dollars)	Total	2011	2012 and 2013	2014 and 2015	2016 and Thereafter
Notes payable	2,092	2,092	–	–	–
Long-term debt	17,922	894	2,012	2,034	12,982
Junior subordinated notes	985	–	–	–	985
Long-term debt of joint ventures	866	65	148	99	554
	21,865	3,051	2,160	2,133	14,521

⁽¹⁾

The anticipated timing of settlement of derivative contracts is presented in the Derivatives Financial Instrument Summary in this note.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        135

Interest Payments on Financial Liabilities

		Payments Due by Period
(millions of dollars)	Total	2011	2012 and 2013	2014 and 2015	2016 and Thereafter
Long-term debt	16,721	1,140	2,190	1,973	11,418
Junior subordinated notes	410	63	126	126	95
Long-term debt of joint ventures	381	48	90	80	163
	17,512	1,251	2,406	2,179	11,676

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments for 2010 is as follows:

			2010
December 31 (all amounts in millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest
Derivative Financial Instruments Held for Trading(1)
Fair Values(2)
	Assets		$169		$144		$8		$20
	Liabilities		$(129	)	$(173	)	$(14	)	$(21	)
Notional Values
	Volumes(3)
		Purchases	15,610		158		–		–
		Sales	18,114		96		–		–
	Canadian dollars		–		–		–		736
	U.S. dollars		–		–		US 1,479		US 250
	Cross-currency		–		–		47/US 37		–
Net unrealized (losses)/gains in the year(4)			$(32	)	$27		$4		$43
Net realized gains/(losses) in the year(4)			$77		$(42	)	$36		$(74	)
Maturity dates			2011-2015		2011-2015		2011-2012		2011-2016
Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(2)
	Assets		$112		$5		$–		$8
	Liabilities		$(186	)	$(19	)	$(51	)	$(26	)
Notional Values
	Volumes(3)
		Purchases	16,071		17		–		–
		Sales	10,498		–		–		–
	U.S. dollars		–		–		US 120		US 1,125
	Cross-currency		–		–		136/US 100		–
Net realized losses in the year(4)			$(9	)	$(35	)	$–		$(33	)
Maturity dates			2011-2015		2011-2013		2011-2014		2011-2015

⁽¹⁾

All derivative financial instruments in the held-for-trading classification have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.

⁽²⁾

Fair values equal carrying values.

⁽³⁾

Volumes for power and natural gas derivatives are in GWh and billion cubic feet (Bcf), respectively.

⁽⁴⁾

Realized and unrealized gains and losses on held-for-trading derivative financial instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of unrealized gains and losses on derivative financial instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

136        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

⁽⁵⁾

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 and a notional amount of US$250 million. In 2010, net realized gains on fair value hedges were $4 million and were included in Interest Expense. In 2010, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

⁽⁶⁾

In 2010, Net Income included a gain of $1 million for changes in the 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 2010, there were no gains or losses included in Net Income for discontinued cash flow hedges. No amounts have been excluded from the assessment of hedge effectiveness.

The anticipated timing of settlement of the derivative contracts assumes constant commodity prices, interest rates and foreign exchange rates from December 31, 2010. Settlements will vary based on the actual value of these factors at the date of settlement. The anticipated timing of settlement of these contracts is as follows:

Year ended December 31 (millions of dollars)		Total		2011		2012 and 2013		2014 and 2015		2016 and Thereafter
Derivative financial instruments held for trading
	Assets	341		221		102		17		1
	Liabilities	(337	)	(191	)	(121	)	(24	)	(1	)
Derivative financial instruments in hedging relationships
	Assets	306		76		204		26		–
	Liabilities	(282	)	(146	)	(120	)	(16	)	–
		28		(40	)	65		3		–

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        137

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments for 2009 is as follows:

			2009
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		$150		$107		$5		$–		$25
	Liabilities		$(98	)	$(112	)	$(5	)	$(66	)	$(68	)
Notional Values
	Volumes(2)
		Purchases	15,275		238		180		–		–
		Sales	13,185		194		180		–		–
	Canadian dollars		–		–		–		–		574
	U.S. dollars		–		–		–		US 444		US 1,325
	Cross-currency		–		–		–		227/US 157		–
Net unrealized gains/(losses) in the year(3)			$3		$(5	)	$1		$3		$27
Net realized gains/(losses) in the year(3)			$70		$(76	)	$–		$36		$(22	)
Maturity dates			2010-2015		2010-2014		2010		2010-2012		2010-2018
Derivative Financial Instruments in Hedging Relationships(4)(5)
Fair Values(1)
	Assets		$175		$2		$–		$–		$15
	Liabilities		$(148	)	$(22	)	$–		$(43	)	$(50	)
Notional Values
	Volumes(2)
		Purchases	13,641		33		–		–		–
		Sales	14,311		–		–		–		–
	U.S. dollars		–		–		–		US 120		US 1,825
	Cross-currency		–		–		–		136/US 100		–
Net realized gains /(losses) in the year(3)			$156		$(29	)	$–		$–		$(37	)
Maturity dates			2010-2015		2010-2014		–		2010-2014		2010-2020

⁽¹⁾

Fair values equal carrying values.

⁽²⁾

Volumes for power, natural gas and oil products derivatives are in GWh, Bcf and thousands of barrels, respectively.

⁽³⁾

Realized and unrealized gains and losses on held-for-trading derivative financial instruments used to purchase and sell power, natural gas and fuel oil are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of unrealized gains and losses on derivative financial instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

⁽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 $4 million and a notional amount of US$150 million. In 2009, realized gains on fair value hedges were $4 million and were included in Interest Expense. In 2009, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

⁽⁵⁾

In 2009, Net Income included losses of $5 million for changes in the 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 2009, there were no gains or losses included in Net Income for discontinued cash flow hedges. No amounts have been excluded from the assessment of hedge effectiveness.

138        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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)	2010		2009
Current
Other current assets	273		315
Accounts payable	(337	)	(340	)
Long term
Intangibles and other assets (Note 7)	374		260
Deferred amounts (Note 13)	(282	)	(272	)

Derivative Financial Instruments of Joint Ventures

Included in the Derivative Financial Instruments Summary tables 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 $48 million at December 31, 2010 (2009 – $105 million). These contracts mature from 2011 to 2015. The Company's proportionate share of the notional sales volumes of power associated with this exposure was 3,772 gigawatt hours (GWh) at December 31, 2010 (2009 – 6,312 GWh). The Company's proportionate share of the notional purchased volumes of power associated with this exposure was 2,322 GWh at December 31, 2010 (2009 – 2,747 GWh).

Fair Value Hierarchy

The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. In Level I, the fair value of assets and liabilities is determined by reference to quoted prices in active markets for identical assets and liabilities. In Level II, determination of the fair value of assets and liabilities includes valuations using inputs, other than quoted prices, for which all significant outputs are observable directly or indirectly. This category includes fair value determined using valuation techniques, such as option pricing models and extrapolation using observable inputs. In Level III, determination of the fair value of assets and liabilities is based on inputs that are not readily observable and are significant to the overall fair value measurement. Long-dated commodity transactions in certain markets are included in this category. Long-dated commodity prices are derived with a third-party modelling tool that uses market fundamentals to derive long-term prices.

There were no transfers between Level I and Level II in 2010 and 2009. Financial assets and liabilities measured at fair value, including both current and non-current portions, are categorized as follows:

		Quoted Prices             in Active             Markets             (Level I)		Significant             Other             Observable             Inputs             (Level II)		Significant             Unobservable             Inputs             (Level III)		Total
December 31 (millions of dollars, pre-tax)		2010	2009	2010	2009	2010	2009	2010	2009
Natural Gas Inventory		–	–	49	73	–	–	49	73
Derivative Financial Instrument Assets:
	Interest rate contracts	–	–	28	40	–	–	28	40
	Foreign exchange contracts	10	10	179	104	–	–	189	114
	Power commodity contracts	–	–	269	311	5	14	274	325
	Gas commodity contracts	93	55	56	49	–	–	149	104
	Oil commodity contracts	–	–	–	5	–	–	–	5
Derivative Financial Instrument Liabilities:
	Interest rate contracts	–	–	(47 )	(119 )	–	–	(47 )	(119	)
	Foreign exchange contracts	(11 )	(6 )	(54 )	(120 )	–	–	(65 )	(126	)
	Power commodity contracts	–	–	(299 )	(229 )	(8 )	(16 )	(307 )	(245	)
	Gas commodity contracts	(178 )	(103 )	(15 )	(27 )	–	–	(193 )	(130	)
	Oil commodity contracts	–	–	–	(5 )	–	–	–	(5	)
Non-Derivative Financial Instruments:
	Available-for-sale assets	20	23	–	–	–	–	20	23
		(66 )	(21 )	166	82	(3 )	(2 )	97	59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        139

The following table presents the net change in the Level III fair value category:

(millions of dollars, pre-tax)	Derivatives(1)
Balance at December 31, 2008	–
New contracts(2)	(14	)
Transfers into Level III(3)	12
Balance at December 31, 2009	(2	)
New contracts(2)	(16	)
Settlements	(3	)
Transfers into Level III(4)	3
Transfers out of Level III(4)(5)	(38	)
Change in unrealized gains recorded in Net Income	14
Change in unrealized gains recorded in Other Comprehensive (Loss)/Income	39
Balance at December 31, 2010	(3	)

⁽¹⁾

The fair value of derivative assets and liabilities is presented on a net basis.

⁽²⁾

At December 31, 2010, the total amount of net gains included in Net Income attributable to derivatives that were entered into during the year and still held at the reporting date was $1 million (2009 – nil).

⁽³⁾

These contracts were previously included in Level II but were reclassified to Level III due to reduced liquidity in the market to which they relate.

⁽⁴⁾

Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable.

⁽⁵⁾

As contracts near maturity, they are transferred out of Level III and into Level II.

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in an $8 million decrease or increase, respectively, in the fair value of outstanding derivative financial instruments included in Level III as at December 31, 2010.

NOTE 19    INCOME TAXES

Provision for Income Taxes

Year ended December 31 (millions of dollars)	2010		2009		2008
Current
Canada	29		(70	)	383
Foreign	(170	)	100		143
	(141	)	30		526
Future
Canada	170		339		(1	)
Foreign	351		18		77
	521		357		76
Income Tax Expense	380		387		602

Geographic Components of Income

Year ended December 31 (millions of dollars)	2010	2009	2008
Canada	798	1,095	1,234
Foreign	969	768	938
Income before Income Taxes and Non-Controlling Interests	1,767	1,863	2,172

140        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Reconciliation of Income Tax Expense

Year ended December 31 (millions of dollars)	2010		2009		2008
Income before income taxes and non-controlling interests	1,767		1,863		2,172
Federal and provincial statutory tax rate	28.0	%	29.0	%	29.5	%
Expected income tax expense	495		540		641
Income tax differential related to regulated operations	8		39		44
Lower effective foreign tax rates	(36	)	(63	)	(5	)
Tax rate and legislative changes	–		(30	)	–
Income from equity investments and non-controlling interests	(40	)	(37	)	(45	)
Change in valuation allowance	–		–		(9	)
Other	(47	)	(62	)	(24	)
Actual Income Tax Expense	380		387		602

Future Income Tax Assets and Liabilities

December 31 (millions of dollars)	2010	2009
Operating loss carryforwards	494	148
Unrealized losses on derivatives	113	56
Other post-employment benefits	75	72
Deferred amounts	42	42
Other	143	127
Future income tax assets	867	445
Difference in accounting and tax bases of plant, equipment and PPAs	3,434	2,642
Taxes on future revenue requirement	321	338
Unrealized foreign exchange gains on long-term debt	161	96
Pension benefits	96	75
Deferred credits	40	57
Unrealized gains on derivatives	9	32
Other	28	61
Future income tax liabilities	4,089	3,301
Net Future Income Tax Liabilities	3,222	2,856

At December 31, 2010, the Company has recognized the benefit of unused non-capital loss carryforwards of $42 million (2009 – $9 million) for federal and provincial purposes in Canada, which expire from 2014 to 2030.

At December 31, 2010, the Company has recognized the benefit of unused net operating loss carryforwards of US$1,320 million (2009 – US$379 million) for federal purposes in the U.S., which expire from 2028 to 2030.

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 at December 31, 2010, by approximately $105 million (2009 – $101 million) if there had been a provision for these taxes.

Income Tax Payments

Income tax payments of $53 million, net of refunds received, were made in 2010 (2009 – $83 million; 2008 – $491 million).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        141

NOTE 20    NOTES PAYABLE

	2010		2009
	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	601	1.2%	327	0.3%
U.S. dollars (2010 – US$1,499; 2009 – US$1,299)	1,491	0.7%	1,360	0.4%
	2,092		1,687

Notes payable consists of commercial paper outstanding and draws on bridge and line-of-credit facilities.

At December 31, 2010, total committed revolving and demand credit facilities of $5.1 billion were available. 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. These unsecured credit facilities included the following:

•

a $2.0 billion committed, syndicated, revolving TCPL credit facility maturing December 2012. The facility was fully available at December 31, 2010. The cost to maintain the credit facility was $2 million in each of 2010 and 2009;



•

a US$300 million committed, syndicated, revolving credit facility, guaranteed by TransCanada and maturing February 2013. This facility is part of a US$1.0 billion TCPL USA credit facility discussed in Note 10. At December 31, 2010, this facility was fully drawn. The cost to maintain the US$1.0 billion credit facility was $1 million in each of 2010 and 2009;



•

a US$1.0 billion committed, syndicated, revolving extendible TransCanada Keystone Pipeline, L.P. credit facility, guaranteed by TCPL and TCPL USA and maturing November 2011. The facility was fully available at December 31, 2010. The cost to maintain the credit facility was $5 million in 2010 (2009 – $2 million);



•

a US$1.0 billion committed, syndicated, revolving TCPL USA credit facility maturing December 2012 with a one-year extension at the option of the borrower and guaranteed by TransCanada. At December 31, 2010, US$200 million was drawn on this facility. The cost to maintain the credit facility was $4 million in 2010 (2009 – nil); and



•

demand lines totalling $800 million, which support the issuance of letters of credit and provide additional liquidity. At December 31, 2010, the Company had used approximately $382 million of these demand lines for letters of credit.

At December 31, 2008, TransCanada had drawn $255 million on a committed, unsecured, one-year bridge loan facility, which was used to fund a portion of the Ravenswood acquisition. In February 2009, the US$255 million was repaid and the facility was cancelled.

142        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 21    ASSET RETIREMENT OBLIGATIONS

The estimated undiscounted cash flows required to settle the ARO with respect to certain regulated and non-regulated operations in the Natural Gas Pipelines segment were $62 million at December 31, 2010 (2009 – $64 million), calculated using an annual inflation rate ranging from one per cent to four per cent. The carrying value of these liabilities was $24 million at December 31, 2010 (2009 – $24 million) after discounting the estimated cash flows at rates ranging from 5.2 per cent to 11.0 per cent. At December 31, 2010, the expected timing of payment for settlement of the obligations ranged from 2011 to 2029.

The estimated undiscounted cash flows required to settle the ARO with respect to the Energy segment were $719 million at December 31, 2010 (2009 – $424 million), calculated using an annual inflation rate ranging from 2.0 per cent to 2.5 per cent. During 2010, the economic life of certain Energy assets was extended after reviewing market trends and asset conditions. As a result, the carrying value of this liability was revised to $42 million at December 31, 2010 (2009 – $87 million) after discounting the estimated cash flows at average rates ranging from 5.5 per cent to 6.8 per cent. At December 31, 2010, the expected timing of payment for settlement of the obligations ranged from 2018 to 2060.

Reconciliation of Asset Retirement Obligations⁽¹⁾

(millions of dollars)	Natural Gas Pipelines		Energy		Total
Balance at January 1, 2008	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
New obligations and revisions in estimated cash flows	(9	)	(4	)	(13	)
Accretion expense	2		6		8
Balance at December 31, 2009	24		87		111
New obligations and revisions in estimated cash flows	(1	)	(47	)	(48	)
Accretion expense	1		2		3
Balance at December 31, 2010	24		42		66

⁽¹⁾

At December 31, 2010, ARO totalling $65 million (2009 – $110 million) and $1 million (2009 – $1 million) were included in Deferred Amounts and Accounts Payable, respectively.

NOTE 22    EMPLOYEE FUTURE BENEFITS

The Company sponsors DB Plans that cover a significant majority of employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plans increase annually by a portion of the increase in the Consumer Price Index. Past service costs are amortized over the expected average remaining service life of employees, which is approximately eight years.

The Company also provides its employees with a Savings Plan in Canada, 401(k) Plans (DC Plans) in the U.S., and post-employment benefits other than pensions, including termination benefits and 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 12 years at December 31, 2010. Contributions to the Savings Plan and DC Plans are expensed as incurred. In 2010, the Company expensed $21 million (2009 and 2008 – $21 million) for the Savings Plan and DC Plans.

Total cash payments for employee future benefits, consisting of cash contributed by the Company to the DB Plans and other benefit plans, was $127 million in 2010 (2009 – $168 million; 2008 – $90 million), including $21 million in 2010 (2009 and 2008 – $21 million) related to the Savings Plan and DC Plans.

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, 2011, and the next required valuation will be as at January 1, 2012.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        143

	Pension Benefit Plans				Other Benefit Plans
December 31 (millions of dollars)	2010		2009		2010		2009
Change in Benefit Obligation
Benefit obligation – beginning of year	1,476		1,332		150		144
Current service cost	50		45		2		2
Interest cost	89		89		9		9
Employee contributions	4		4		1		1
Benefits paid	(73	)	(70	)	(9	)	(8	)
Actuarial loss	95		107		8		10
Transfers	(8	)	–		–		–
Foreign exchange rate changes	(11	)	(31	)	(2	)	(8	)
Benefit obligation – end of year	1,622		1,476		159		150
Change in Plan Assets
Plan assets at fair value – beginning of year	1,447		1,193		27		26
Actual return on plan assets	177		206		3		5
Employer contributions	98		140		8		7
Employee contributions	4		4		1		1
Benefits paid	(73	)	(70	)	(9	)	(8	)
Transfers	(8	)	–		–		–
Foreign exchange rate changes	(9	)	(26	)	(1	)	(4	)
Plan assets at fair value – end of year	1,636		1,447		29		27
Funded status – plan surplus/(deficit)	14		(29	)	(130	)	(123	)
Unamortized net actuarial loss	345		329		42		37
Unamortized past service costs	18		21		(3	)	(3	)
Accrued Benefit Asset/(Liability), Net of Valuation Allowance of Nil	377		321		(91	)	(89	)

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
December 31 (millions of dollars)	2010		2009		2010		2009
Intangibles and other assets	380		323		–		–
Deferred amounts	(3	)	(2	)	(91	)	(89	)
	377		321		(91	)	(89	)

Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded:

	Pension Benefit Plans				Other Benefit Plans
December 31 (millions of dollars)	2010		2009		2010		2009
Benefit obligation	(417	)	(390	)	(159	)	(150	)
Plan assets at fair value	391		358		29		27
Funded Status – Plan Deficit	(26	)	(32	)	(130	)	(123	)

The Company's expected contributions in 2011 are approximately $98 million for the DB Plans and approximately $28 million for the other benefit plans, Savings Plan and DC Plans.

144        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following are estimated future benefit payments, which reflect expected future service:

(millions of dollars)	Pension Benefits	Other Benefits
2011	82	9
2012	85	9
2013	89	9
2014	92	10
2015	96	10
2016 to 2020	540	56

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:

	Pension Benefit Plans		Other Benefit Plans
December 31	2010	2009	2010	2009
Discount rate	5.55%	6.00%	5.65%	6.00%
Rate of compensation increase	3.20%	3.20%

The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan cost were as follows:

	Pension Benefit Plans			Other Benefit Plans
Year ended December 31	2010	2009	2008	2010	2009	2008
Discount rate	6.00%	6.65%	5.30%	6.00%	6.50%	5.50%
Expected long-term rate of return on plan assets	6.95%	6.95%	6.95%	7.80%	7.75%	7.75%
Rate of compensation increase	3.20%	3.25%	3.60%

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 average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2020 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects:

(millions of dollars)	Increase	Decrease
Effect on total of service and interest cost components	1	(1	)
Effect on post-employment benefit obligation	14	(12	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        145

The Company's net benefit cost is as follows:

	Pension Benefit Plans						Other Benefit Plans
Year ended December 31 (millions of dollars)	2010		2009		2008		2010		2009		2008
Current service cost	50		45		52		2		2		2
Interest cost	89		89		80		9		9		8
Actual return on plan assets	(177	)	(206	)	222		(3	)	(5	)	10
Actuarial loss/(gain)	95		107		(261	)	8		10		(21	)
Plan amendment	–		–		–		–		–		(11	)
Elements of net benefit cost prior to adjustments to     recognize the long-term nature of net benefit cost	57		35		93		16		16		(12	)
Difference between expected and actual return on plan assets	68		107		(316	)	1		3		(12	)
Difference between actuarial loss/(gain) recognized and actual actuarial loss/(gain) on accrued benefit obligation	(86	)	(101	)	280		(6	)	(8	)	23
Difference between amortization of past service costs and actual plan amendments	4		4		4		–		–		11
Amortization of transitional obligation related to regulated business	–		–		–		2		2		2
	43		45		61		13		13		12

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	2010	2009	2010
Debt securities	37%	40%	35% to 60%
Equity securities	63%	60%	40% to 65%
	100%	100%

Debt securities included the Company's debt of $4 million (0.2 per cent of total plan assets) and $4 million (0.3 per cent of total plan assets) at December 31, 2010 and 2009, respectively. Equity securities included the Company's common shares of $3 million (0.2 per cent of total plan assets) and $8 million (0.6 per cent of total plan assets) at December 31, 2010 and 2009, 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 TransCanada. The following amounts in this note, including those in the accompanying tables, represent TransCanada'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 $58 million in 2010 (2009 – $54 million; 2008 – $42 million).

The Company's joint ventures measure the benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuations of the pension plans for funding purposes were as at January 1, 2011, and the next required valuations will be as at January 1, 2012.

146        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Pension Benefit Plans				Other Benefit Plans
December 31 (millions of dollars)	2010		2009		2010		2009
Change in Benefit Obligation
Benefit obligation – beginning of year	695		599		170		133
Current service cost	19		16		8		5
Interest cost	42		40		10		9
Employee contributions	7		6		–		–
Benefits paid	(31	)	(33	)	(5	)	(4	)
Actuarial loss	132		68		25		27
Foreign exchange rate changes	–		(1	)	–		–
Benefit obligation – end of year	864		695		208		170
Change in Plan Assets
Plan assets at fair value – beginning of year	641		556		–		–
Actual return on plan assets	57		63		–		–
Employer contributions	53		50		5		4
Employee contributions	7		6		–		–
Benefits paid	(31	)	(33	)	(5	)	(4	)
Foreign exchange rate changes	–		(1	)	–		–
Plan assets at fair value – end of year	727		641		–		–
Funded status – plan deficit	(137	)	(54	)	(208	)	(170	)
Unamortized net actuarial loss	230		113		49		25
Unamortized past service costs	–		–		2		2
Accrued Benefit Asset/(Liability), Net of Valuation Allowance of Nil	93		59		(157	)	(143	)

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
December 31 (millions of dollars)	2010	2009		2010		2009
Intangibles and other assets	93	60		–		–
Deferred amounts	–	(1	)	(157	)	(143	)
	93	59		(157	)	(143	)

The following amounts were included in the above benefit obligation and fair value of plan assets for plans that are not fully funded:

	Pension Benefit Plans				Other Benefit Plans
December 31 (millions of dollars)	2010		2009		2010		2009
Benefit obligation	(864	)	(695	)	(208	)	(170	)
Plan assets at fair value	727		641		–		–
Funded Status – Plan Deficit	(137	)	(54	)	(208	)	(170	)

The expected total contributions of the Company's joint ventures in 2011 are approximately $87 million for the pension benefit plans and approximately $7 million for the other benefit plans.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        147

The following are estimated future benefit payments, which reflect expected future service:

(millions of dollars)	Pension Benefits	Other Benefits
2011	40	6
2012	43	7
2013	47	7
2014	51	8
2015	54	9
2016 to 2020	324	55

The significant weighted average actuarial assumptions adopted in measuring the benefit obligations of the Company's joint ventures were as follows:

	Pension Benefit Plans		Other Benefit Plans
December 31	2010	2009	2010	2009
Discount rate	5.25%	6.00%	5.10%	5.80%
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 were as follows:

	Pension Benefit Plans			Other Benefit Plans
Year ended December 31	2010	2009	2008	2010	2009	2008
Discount rate	6.00%	6.75%	5.25%	5.80%	6.40%	5.15%
Expected long-term rate of return on plan assets	7.00%	7.00%	7.00%
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	26	(22	)

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)	2010		2009		2008		2010		2009		2008
Current service cost	19		16		27		8		5		8
Interest cost	42		40		42		10		9		9
Actual return on plan assets	(57	)	(63	)	78		–		–		–
Actuarial loss/(gain)	132		68		(229	)	25		27		(45	)
Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost	136		61		(82	)	43		41		(28	)
Difference between expected and actual return on plan assets	12		25		(122	)	–		–		–
Difference between actuarial loss/(gain) recognized and actual actuarial loss/(gain) on accrued benefit obligation	(128	)	(67	)	239		(24	)	(28	)	48
	20		19		35		19		13		20

148        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	2010	2009	2010
Debt securities	41%	40%	40%
Equity securities	59%	60%	60%
	100%	100%

Debt securities included the Company's debt of $1 million (0.2 per cent of total plan assets) and $1 million (0.1 per cent of total plan assets) at December 31, 2010 and 2009, respectively. Equity securities included the Company's common shares of $4 million (0.5 per cent of total plan assets) and $4 million (0.6 per cent of total plan assets) at December 31, 2010 and 2009, respectively.

The assets of the joint ventures' 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)	2010		2009		2008
(Increase)/decrease in accounts receivable	(305	)	314		(197	)
Decrease/(increase) in inventories	70		(19	)	82
Increase in other current assets	(89	)	(249	)	(61	)
Increase/(decrease) in accounts payable	84		(154	)	213
(Decrease)/increase in accrued interest	(9	)	18		98
(Increase)/Decrease in Operating Working Capital	(249	)	(90	)	135

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
2011	83	(9	)	74
2012	80	(5	)	75
2013	79	(4	)	75
2014	76	(4	)	72
2015	73	(3	)	70
2016 and thereafter	419	(1	)	418
	810	(26	)	784

The operating lease agreements for premises, services and equipment expire at various dates through 2052, with an option to renew certain lease agreements for periods of one year to 10 years. Net rental expense on operating leases in 2010 was $107 million (2009 – $91 million; 2008 – $52 million).

TransCanada's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs has been subleased to third parties under similar terms and conditions. Future payments under these PPAs have been excluded from operating leases in the above

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        149

table, as these payments are dependent upon plant availability among other factors. TransCanada's share of power purchased under the PPAs in 2010 was $363 million (2009 – $384 million; 2008 – $398 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

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

Other Commitments

At December 31, 2010, TransCanada was committed to Natural Gas Pipelines capital expenditures totalling approximately $0.2 billion, primarily related to construction costs of the Alberta System and Guadalajara.

At December 31, 2010, the Company was committed to Oil Pipelines capital expenditures totalling approximately $1.2 billion, primarily related to construction costs of the Keystone U.S. Gulf Coast Expansion.

At December 31, 2010, the Company was committed to Energy capital expenditures totalling approximately $0.6 billion, primarily related to its share of the construction costs of Bruce Power and Cartier Wind.

Contingencies

TransCanada is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2010, the Company accrued approximately $59 million (2009 – $67 million) related to operating facilities, which represents the estimated amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue.

TransCanada 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

TransCanada and its joint venture partners on Bruce Power, 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, a lease agreement and contractor services. The guarantees have terms ranging from 2018 to perpetuity. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the Ontario Power Authority to refurbish and restart Bruce A power generation units. The guarantees were provided as part of the reorganization of Bruce Power in 2005 and have terms ending in 2018 and 2019. TransCanada's share of the potential exposure under these Bruce A and Bruce B guarantees was estimated to be $739 million at December 31, 2010. The fair value of these Bruce Power guarantees is estimated to be $42 million. The Company's exposure under certain of these guarantees is unlimited.

In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, PPA payments and the payment of liabilities. TransCanada's share of the potential exposure under these guarantees was estimated at December 31, 2010 to range from $227 million to a maximum of $539 million. The fair value of these guarantees is estimated to be $9 million, which has been included in Deferred Amounts. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

150        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SUPPLEMENTARY INFORMATION

SELECTED QUARTERLY AND ANNUAL CONSOLIDATED FINANCIAL DATA

Toronto Stock Exchange (Stock trading symbol TRP)	First	Second	Third	Fourth	Annual
2010 (dollars)
High	37.87	38.16	38.88	39.28	39.28
Low	33.96	30.01	35.50	35.49	30.01
Close	37.22	35.61	38.17	37.99	37.99
Volume (millions of shares)	91.8	93.5	89.2	108.1	382.6
2009 (dollars)
High	35.00	34.40	34.00	36.49	36.49
Low	28.86	29.34	30.19	31.92	28.86
Close	29.83	31.32	33.37	36.19	36.19
Volume (millions of shares)	113.7	131.8	110.9	97.2	453.6
2008 (dollars)
High	40.97	40.71	40.65	39.26	40.97
Low	36.21	35.98	35.95	29.42	29.42
Close	39.55	39.50	38.17	33.17	33.17
Volume (millions of shares)	86.1	134.0	114.0	159.7	493.8
2007 (dollars)
High	41.35	40.29	39.83	40.73	41.35
Low	36.75	35.77	35.43	36.47	35.43
Close	38.35	36.64	36.47	40.54	40.54
Volume (millions of shares)	88.7	78.7	91.4	77.2	336.0
New York Stock Exchange (Stock trading symbol TRP)
2010 (U.S. dollars)
High	37.11	38.01	37.75	38.59	38.59
Low	31.58	25.80	32.86	34.77	25.80
Close	36.76	33.43	37.12	38.04	38.04
Volume (millions of shares)	17.8	23.8	19.7	23.6	84.9
2009 (U.S. dollars)
High	29.01	30.93	31.74	34.59	34.59
Low	20.01	23.20	25.88	29.66	20.01
Close	23.65	26.91	31.02	34.37	34.37
Volume (millions of shares)	42.1	27.2	20.9	21.7	111.9
2008 (U.S. dollars)
High	41.53	40.64	39.29	36.33	41.53
Low	35.60	35.33	34.01	23.52	23.52
Close	38.53	38.77	36.15	27.14	27.14
Volume (millions of shares)	8.7	8.8	9.8	17.2	44.5
2007 (U.S. dollars)
High	35.30	37.21	38.06	43.94	43.94
Low	31.33	32.91	32.92	36.68	31.33
Close	33.28	34.41	36.61	40.93	40.93
Volume (millions of shares)	8.2	5.7	9.0	7.9	30.8

SUPPLEMENTARY INFORMATION        151

TEN YEAR FINANCIAL HIGHLIGHTS

(millions of dollars except where indicated)			2010		2009		2008		2007		2006		2005		2004		2003		2002		2001
Income Statement
Revenues			8,064		8,181		8,547		8,731		7,414		6,082		5,497		5,636		5,225		5,285
EBITDA
		Pipelines	2,769		3,122		3,315		3,077		2,780		3,001		2,846		2,857		2,815		2,702
		Energy	1,117		1,132		1,169		970		880		883		621		458		373		383
		Corporate	(99	)	(117	)	(104	)	(102	)	(85	)	(87	)	(59	)	(65	)	(63	)	(82 )
			3,787		4,137		4,380		3,945		3,575		3,797		3,408		3,250		3,125		3,003
Depreciation			(1,354	)	(1,377	)	(1,247	)	(1,237	)	(1,117	)	(1,041	)	(972	)	(954	)	(876	)	(811 )
EBIT			2,433		2,760		3,133		2,708		2,458		2,756		2,436		2,296		2,249		2,192
Financial charges and other			(781	)	(993	)	(1,091	)	(995	)	(931	)	(937	)	(965	)	(981	)	(985	)	(1,026 )
Income taxes			(380	)	(387	)	(602	)	(490	)	(476	)	(610	)	(491	)	(514	)	(517	)	(480 )
Net income			1,272		1,380		1,440		1,223		1,051		1,209		980		801		747		686
Preferred share dividends			(45	)	(6	)	–		–		–		–		–		–		–		–
Net income applicable to common shares
	Continuing operations		1,227		1,374		1,440		1,223		1,051		1,209		980		801		747		686
	Discontinued operations		–		–		–		–		28		–		52		50		–		(67 )
			1,227		1,374		1,440		1,223		1,079		1,209		1,032		851		747		619
Comparable earnings			1,361		1,325		1,279		1,100		925		839		793		771		731		686
Cash Flow Statement
Funds generated from operations			3,331		3,080		3,021		2,621		2,378		1,951		1,703		1,822		1,843		1,625
(Increase)/decrease in operating working capital			(249	)	(90	)	135		63		(506	)	78		29		93		92		(487 )
Net cash provided by operations			3,082		2,990		3,156		2,684		1,872		2,029		1,732		1,915		1,935		1,138
Capital expenditures and acquisitions			5,036		6,319		6,363		5,874		2,042		2,071		2,046		965		851		1,082
Disposition of assets, net of current income taxes			–		–		28		35		23		671		410		–		–		1,170
Cash dividends paid on common and preferred shares			754		728		577		546		617		586		552		510		466		418
Balance Sheet
Assets
Plant, property and equipment
		Natural gas pipelines	18,230		18,333		19,339		18,122		17,141		16,528		17,306		16,064		16,158		16,562
		Oil pipelines	8,184		5,305		1,361		158		–		–		–		–		–		–
		Energy	9,745		9,158		8,435		5,127		4,302		3,483		1,421		1,368		1,340		1,116
		Corporate	85		83		54		45		44		27		37		50		64		66
Total assets
	Continuing operations		46,589		43,841		39,414		30,330		25,909		24,113		22,415		20,876		20,416		20,255
	Discontinued operations		–		–		–		–		–		–		7		11		139		276
Total assets			46,589		43,841		39,414		30,330		25,909		24,113		22,422		20,887		20,555		20,531
Capitalization
Long-term debt			17,028		16,186		15,368		12,377		10,887		9,640		9,749		9,516		8,899		9,444
Junior subordinated notes			985		1,036		1,213		975		–		–		–		–		–		–
Preferred securities			–		–		–		–		536		536		554		598		944		950
Non-controlling interests			1,157		1,174		1,194		999		755		783		700		713		677		675
Preferred shares			1,224		539		–		–		–		–		–		–		–		–
Common shareholders' equity			15,503		15,220		12,898		9,785		7,701		7,206		6,565		6,091		5,747		5,426

152        SUPPLEMENTARY INFORMATION

Per Common Share Data (dollars)
Net income – basic
	Continuing operations		$1.78	$2.11	$2.53		$2.31	$2.15	$2.49	$2.02	$1.66	$1.56	$1.44
	Discontinued operations		–	–	–		–	0.06	–	0.11	0.10	–	(0.14 )
			$1.78	$2.11	$2.53		$2.31	$2.21	$2.49	$2.13	$1.76	$1.56	$1.30
Net income – diluted
	Continuing operations		$1.77	$2.11	$2.52		$2.30	$2.14	$2.47	$2.01	$1.66	$1.55	$1.44
	Discontinued operations		–	–	–		–	0.06	–	0.11	0.10	–	(0.14 )
			$1.77	$2.11	$2.52		$2.30	$2.20	$2.47	$2.12	$1.76	$1.55	$1.30
Comparable earnings per share			$1.97	$2.03	$2.25		$2.08	$1.90	$1.72	$1.64	$1.60	$1.53	$1.44
Dividends declared			$1.60	$1.52	$1.44		$1.36	$1.28	$1.22	$1.16	$1.08	$1.00	$0.90
Book Value(1)(7)			$22.27	$22.24	$20.92		$18.13	$15.75	$14.79	$13.54	$12.61	$11.99	$11.38
Market Price
	Toronto Stock Exchange ($Cdn)
		High	39.28	36.49	40.97		41.35	40.90	37.90	30.35	28.49	23.91	21.13
		Low	30.01	28.86	29.42		35.43	30.77	28.94	25.37	20.77	19.05	14.85
		Close	37.99	36.19	33.17		40.54	40.61	36.65	29.80	27.88	22.92	19.87
		Volume (millions of shares)	382.60	453.6	493.8		336.0	268.6	238.0	280.1	277.9	280.6	288.2
	New York Stock Exchange ($US)
		High	38.59	34.59	41.53		43.94	35.40	32.41	24.91	21.88	15.56	13.41
		Low	25.80	20.01	23.52		31.33	27.40	23.36	18.75	14.16	11.89	9.88
		Close	38.04	34.37	27.14		40.93	34.95	31.48	24.87	21.51	14.51	12.51
		Volume (millions of shares)	84.94	111.9	44.5		30.8	27.7	31.6	33.0	21.2	16.3	16.8
Common shares outstanding (millions)
	Average for the year		690.5	651.8	569.6		529.9	488.0	486.2	484.1	481.5	478.3	475.8
	End of year		696.2	684.4	616.5		539.8	489.0	487.2	484.9	483.2	479.5	476.6
Registered common shareholders(1)			32,639	33,169	33,681		34,204	35,522	30,533	31,837	33,133	34,902	36,350
Per Preferred Share Data (dollars)
	Dividends declared:
	Series 1, 3 and 5 cumulative first preferred shares(2)		$2.51	$0.29	$–		$–	$–	$–	$–	$–	$–	$–
Financial Ratios
Return on average common shareholders' equity(3)			8.0%	9.8%	12.7%		14.0%	14.5%	17.6%	16.3%	14.4%	13.4%	11.6%
Dividend yield(4)(5)			4.2%	4.2%	4.3%		3.4%	3.2%	3.3%	3.9%	3.9%	4.4%	4.5%
Price/earnings multiple(5)(6)			21.3	17.2	13.1		17.5	18.4	14.7	14.0	15.8	14.7	15.3
Price/book multiple(5)(7)			1.7	1.6	1.6		2.2	2.6	2.5	2.2	2.2	1.9	1.7
Debt to debt plus shareholders' equity(8)			53%	53%	57%		59%	61%	59%	63%	64%	64%	67%
Total shareholder return(9)			9.7%	14.4%	(15%	)	3%	15%	28%	11%	27%	21%	21%
Earnings to fixed charges(10)			1.9	2.1	2.7		2.6	2.5	2.9	2.5	2.3	2.3	2.1

⁽¹⁾

As at December 31.

⁽²⁾

Preferred shares were issued for Series 1, 3 and 5 in September 2009, March 2010 and June 2010, respetively, with annual dividend rates of $1.15, $1.00 and $1.10 per share, respectively. The first quarterly dividends for each series were paid in December 2009, June 2010 and November 2010, respectively.

⁽³⁾

The return on average common shareholders' equity is determined by dividing net income applicable to common shares by average common shareholders' equity (i.e. opening plus closing common shareholders' equity divided by two) for each year.

⁽⁴⁾

The dividend yield is determined by dividing dividends per common share declared during the year by price per common share as at December 31.

⁽⁵⁾

Price per common share refers to market price per share as reported on the Toronto Stock Exchange as at December 31.

⁽⁶⁾

The price/earnings multiple is determined by dividing price per common share by the basic net income per share.

⁽⁷⁾

The price/book multiple is determined by dividing price per common share by book value per common share as calculated by dividing common shareholders' equity by the number of common shares outstanding as at December 31.

⁽⁸⁾

Debt includes Junior Subordinated Notes, total long-term debt, including the current portion of long-term debt, plus preferred securities as at December 31 and excludes long-term debt of joint ventures. Shareholders' equity in this ratio is as at December 31.

⁽⁹⁾

Total shareholder return is the sum of the change in price per common share plus the dividends received plus the impact of dividend re-investment in a calendar year, expressed as a percentage of the value of shares at the end of the previous year.

⁽¹⁰⁾

The earnings to fixed charges ratio is determined by dividing earnings by fixed charges. Earnings is calculated as the sum of EBIT and interest income and other, less income attributable to non-controlling interests with interest expense and undistributed earnings of investments accounted for by the equity method. Fixed charges is calculated as the sum of interest expense, interest expense of joint ventures and capitalized interest.

SUPPLEMENTARY INFORMATION        153

INVESTOR INFORMATION

STOCK EXCHANGES, SECURITIES AND SYMBOLS

TransCanada Corporation

Common shares are listed on the Toronto and New York stock exchanges under the symbol: TRP

First Preferred Shares, Series 1 are listed on the Toronto Stock Exchange under the symbol: TRP.PR.A

First Preferred Shares, Series 3 are listed on the Toronto Stock Exchange under the symbol: TRP.PR.B

First Preferred Shares, Series 5 are listed on the Toronto Stock Exchange under the symbol: TRP.PR.C

TransCanada PipeLines Limited (TCPL)*

Preferred shares are listed on the Toronto Stock Exchange under the following symbols:

First Preferred Shares, Series U: TCA.PR.X and Series Y: TCA.PR.Y

* TCPL is a wholly owned subsidiary of TransCanada Corporation.

Annual Meeting   The annual meeting of shareholders is scheduled for April 29, 2011 at 10:00 a.m. (Mountain Daylight Time) at the BMO Centre (formerly the Roundup Centre), Calgary, Alberta.

Dividend Payment Dates   Scheduled common share dividend payment dates in 2011 are January 31, April 29, July 29 and October 31.

For information on dividend payment dates for TransCanada Corporation and TCPL Preferred Shares visit our website at www.transcanada.com.

Dividend Reinvestment and Share Purchase Plan   TransCanada's dividend reinvestment and share purchase plan (Plan) allows common and preferred shareholders of TransCanada and preferred shareholders of TCPL to purchase common shares of TransCanada by reinvesting their cash dividends without incurring brokerage or administrative fees. Participants in the Plan may also buy additional common shares, up to Cdn$10,000 per quarter. For more information on the Plan please contact our Plan agent, Computershare Trust Company of Canada or visit our website at www.transcanada.com.

TRANSFER AGENTS, REGISTRARS AND TRUSTEE

TransCanada Corporation Common Shares   Computershare Trust Company of Canada (Montréal, Toronto, Calgary and Vancouver) and Computershare Trust Company, N.A. (Golden)

TransCanada Corporation First Preferred Shares, Series 1   Computershare Trust Company of Canada (Montréal, Toronto, Calgary and Vancouver)

TransCanada Corporation First Preferred Shares, Series 3   Computershare Trust Company of Canada (Montréal, Toronto, Calgary and Vancouver)

TransCanada Corporation First Preferred Shares, Series 5   Computershare Trust Company of Canada (Montréal, Toronto, Calgary and Vancouver)

TCPL First Preferred Shares, Series U and Series Y   Computershare Trust Company of Canada (Montréal, Toronto, Calgary and Vancouver)

TCPL Debentures

Canadian Series: BNY Trust Company of Canada (Halifax, Montréal, Toronto, Calgary and Vancouver)

11.10% series N	10.50% series P	11.90% series S	11.80% series U
9.80% series V	9.45% series W

U.S. Series: The Bank of New York (New York) 9.875% and 8.625%

TCPL Canadian Medium-Term Notes   BNY Trust Company of Canada (Halifax, Montréal, Toronto, Calgary and Vancouver)

TCPL U.S. Medium-Term Notes and Senior Notes   The Bank of New York Mellon (New York)

TCPL U.S. Junior Subordinated Notes   The Bank of Nova Scotia Trust Company of New York

154        TRANSCANADA CORPORATION

NOVA Gas Transmission Ltd. (NGTL) Debentures

Canadian Series: BNY Trust Company of Canada (Halifax, Montreal, Toronto, Calgary and Vancouver)

11.20% series 18 12.20% series 20 12.20% series 21   9.90% series 23

U.S. Series: U.S. Bank Trust National Association (New York) 8.50% and 7.875%

NGTL Canadian Medium-Term Notes   BNY Trust Company of Canada (Halifax, Montreal, Toronto, Calgary and Vancouver)

NGTL U.S. Medium-Term Notes   U.S. Bank Trust National Association (New York)

REGULATORY FILINGS

Annual Information Form   TransCanada's 2010 Annual Information Form, as filed with Canadian securities commissions and as filed under Form 40-F with the SEC, is available on our website at www.transcanada.com.

A printed copy may be obtained from:

Corporate Secretary, TransCanada Corporation, 450 1st Street SW, Calgary, Alberta, Canada T2P 5H1

TRANSCANADA CORPORATION        155

SHAREHOLDER ASSISTANCE

If you are a registered shareholder and have questions regarding your account, please contact our transfer agent in writing, by telephone or e-mail at:

Computershare Trust Company of Canada, 100 University Avenue, 9th Floor, North Tower, Toronto, Ontario, Canada M5J 2Y1

Toll-free: 1.800.340.5024

Telephone: 1.514.982.7959

E-mail: transcanada@computershare.com

www.computershare.com

If you hold your shares in a brokerage account (beneficial shareholder), questions should be directed to your broker on all administrative matters.

If you would like to receive quarterly reports, please contact Computershare or visit our website at www.transcanada.com.

Electronic Proxy Voting and Delivery of Documents   TransCanada is pleased to offer registered and beneficial shareholders the ability to receive their documents (annual report, management information circular, notice of meeting and view-only proxy form) and vote online.

In 2011, registered shareholders who opt to receive their documents electronically will have a tree planted on their behalf through eTree. For more information and to sign up online, registered shareholders can visit www.etree.ca/transcanada.

Shareholders who do not have access to e-mail, or who still prefer to receive their proxy materials by mail also have the ability to choose whether to receive TransCanada's annual report by regular mail. Each year, shareholders are required to renew their option and will receive a notification for doing so. The annual report is available on the TransCanada website at www.transcanada.com at the same time that the report is mailed to shareholders.

Electronic delivery and the ability to opt out of receiving the annual report by mail, provides increased convenience to shareholders, benefits to the environment and reduced mailing and printing costs for the company.

TransCanada in the Community   TransCanada's annual Corporate Responsibility Report is available at www.transcanada.com. If you would like to receive a copy of this report by mail, please contact:

Communications   450 1st Street SW, Calgary, Alberta T2P 5H1, 1.403.920.2000 or 1.800.661.3805 or Communications@transcanada.com

Visit our website at www.transcanada.com to access TransCanada's corporate and financial information, including quarterly reports, news releases, real-time conference call webcasts and investor presentations.

Si vous désirez vous procurer un exemplaire de ce rapport en français, veuillez consulter notre site web ou vous adresser par écrit à TransCanada Corporation, bureau du secrétaire.

156        TRANSCANADA CORPORATION

BOARD OF DIRECTORS

(as at December 31, 2010)

S. Barry Jackson⁽¹⁾⁽²⁾
Chairman
TransCanada Corporation
Calgary, Alberta

Harold N. Kvisle⁽⁹⁾
President and CEO
TransCanada Corporation
Calgary, Alberta

Russell K. Girling⁽¹⁰⁾
President and CEO
TransCanada Corporation
Calgary, Alberta

Kevin E. Benson⁽¹⁾⁽³⁾
Corporate Director
DeWinton, Alberta

Derek H. Burney, O.C.⁽¹⁾⁽⁴⁾
Senior Strategic Advisor
Ogilvy Renault LLP
Ottawa, Ontario

Wendy K. Dobson⁽²⁾⁽⁵⁾
Professor, Rotman School
of Management and Director,
Institute for International Business
University of Toronto
Uxbridge, Ontario
E. Linn Draper⁽⁴⁾⁽⁶⁾
Former Chairman, President and CEO
American Electric Power Co., Inc. (AEP)
Lampasas, Texas

The Hon. Paule Gauthier, P.C., O.C., O.Q., Q.C.⁽²⁾⁽⁵⁾
Senior Partner
Stein Monast L.L.P.
Québec, Québec

Kerry L. Hawkins⁽²⁾⁽⁵⁾
Retired President
Cargill Limited
Winnipeg, Manitoba

Paul L. Joskow⁽¹⁾⁽⁴⁾
President
Alfred P. Sloan Foundation
New York, New York
John A. MacNaughton⁽⁴⁾⁽⁷⁾
Chairman
Business Development Bank of Canada
Toronto, Ontario

David P. O'Brien, O.C.⁽¹⁾⁽²⁾
Chairman
EnCana Corporation
Royal Bank of Canada
Calgary, Alberta

W. Thomas Stephens⁽⁵⁾⁽⁸⁾
Former Chairman and
Chief Executive Officer
Boise Cascade, LLC
Greenwood Village, Colorado

D. Michael G. Stewart⁽¹⁾⁽⁴⁾
Corporate Director
Calgary, Alberta

⁽¹⁾

Member, Governance Committee

⁽²⁾

Member, Human Resources Committee

⁽³⁾

Chair, Audit Committee

⁽⁴⁾

Member, Audit Committee

⁽⁵⁾

Member, Health, Safety and Environment Committee

⁽⁶⁾

Chair, Health, Safety and Environment Committee

⁽⁷⁾

Chair, Governance Committee

⁽⁸⁾

Chair, Human Resources Committee

⁽⁹⁾

Mr. Kvisle retired from the Board of Directors effective June 30, 2010

⁽¹⁰⁾

Mr. Girling was appointed to the Board of Directors effective July 1, 2010

TRANSCANADA CORPORATION        157

CORPORATE GOVERNANCE

Please refer to TransCanada's Notice of 2011 Annual Meeting of Shareholders and Management Proxy Circular for the company's statement of corporate governance.

TransCanada's Corporate Governance Guidelines, Board charter, Committee charters, Chair and CEO terms of reference and codes of business conduct and ethics are available on our website at www.transcanada.com. Also available on our website is a summary of the significant ways in which TransCanada's corporate governance practices differ from those required to be followed by U.S. domestic companies under the New York Stock Exchange's listing standards.

Additional information relating to the company is filed with securities regulators in Canada on SEDAR at www.sedar.com and in the United States on EDGAR at www.sec.gov. The documents referred to in this Annual Report may be obtained free of charge by contacting TransCanada's Corporate Secretary at 450 1st Street SW, Calgary, Alberta, Canada T2P 5H1, or by telephoning 1.800.661.3805.

Ethics Help-Line The Audit Committee of the Board of Directors has established an anonymous and confidential toll-free telephone number for employees, contractors and others to call with respect to accounting irregularities and ethical violations. The Ethics Help-Line number is 1.888.920.2042.

158        TRANSCANADA CORPORATION

Contact Information Dennis McConaghy Executive Vice-President Corporate Development Sean McMaster Executive Vice-President Corporate and General Counsel Sarah Raiss Executive Vice-President Corporate Services Don Wishart Executive Vice-President Operations and Major Projects Russ Girling President and Chief Executive Officer Alex Pourbaix President Energy and Oil Pipelines Greg Lohnes President Natural Gas Pipelines Don Marchand Executive Vice-President and Chief Financial Officer TransCanada Corporation TransCanada Tower 450 1st Street SW Calgary, Alberta T2P 5H1 1.403.920.2000 1.800.661.3805 Visit our website for more information on: • Our Pipelines and Energy businesses • Projects and initiatives • Corporate responsibility • Corporate governance • Investor services www.transcanada.com TransCanada welcomes questions from shareholders and investors. Please contact: David Moneta, Vice-President, Investor Relations and Corporate Communications 1.800.361.6522 (Canada and U.S. Mainland) Please recycle Printed in Canada March 2011 Executive Officers

Our Vision TransCanada will be the leading energy infrastructure company in North America, with a strong focus on pipelines and power generation opportunities located in regions where we have or can develop significant competitive advantage.

TRANSCANADA CORPORATION

RECONCILIATION TO UNITED STATES GAAP

December 31, 2010

TRANSCANADA CORPORATION
RECONCILIATION TO UNITED STATES GAAP

The audited consolidated financial statements of TransCanada Corporation (TransCanada or the Company) for the year ended December 31, 2010 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, 2010, 2009, and 2008 are described below and should be read in conjunction with TransCanada's audited consolidated annual financial statements prepared in accordance with Canadian GAAP.

Reconciliation of Net Income and Comprehensive Income

Year Ended December 31 (millions of Canadian dollars, except per share amounts)		2010			2009			2008
Net Income in Accordance with Canadian GAAP			1,272			1,380			1,440
U.S. GAAP adjustments:
	Net income attributable to non-controlling interests(1)		115			96			130
	Unrealized loss/(gain) on natural gas inventory held in storage(2)		15			(3	)		32
	Tax impact of unrealized loss/(gain) on natural gas inventory held in storage		(5	)		1			(11	)
	Dilution gain(3)		–			(29	)		–
	Tax impact of dilution gain		–			11			–
	Tax recovery due to a change in tax legislation substantively enacted in Canada(4)		(4	)		–			–
Net Income in Accordance with U.S. GAAP			1,393			1,456			1,591
	Less: net income attributable to non-controlling interests(1)		(115	)		(96	)		(130	)
Net Income Attributable to TransCanada Corporation			1,278			1,360			1,461
	Less: preferred share dividends		(45	)		(6	)		–
Net Income Attributable to Common Shareholders in Accordance with U.S. GAAP			1,233			1,354			1,461
Other Comprehensive (Loss)/Income in Accordance with Canadian GAAP			(245	)		(160	)		(99	)
U.S. GAAP adjustments:
	Other comprehensive income/(loss) attributable to non-controlling interests(1)		6			7			(18	)
	Change in funded status of postretirement plan liability(5)		(11	)		7			(49	)
	Tax impact of change in funded status of postretirement plan liability		4			(2	)		10
	Change in funded status of postretirement plan liability of equity investment		(119	)		(48	)		107
Other Comprehensive Loss in Accordance with U.S. GAAP			(365	)		(196	)		(49	)
	Less: other comprehensive income attributable to non-controlling interests(1)		(6	)		(7	)		18
Other Comprehensive Loss Attributable to TransCanada Corporation in Accordance with U.S. GAAP			(371	)		(203	)		(31	)
Comprehensive Income Attributable to TransCanada Corporation in Accordance with U.S. GAAP			862			1,151			1,430
Net Income per Share in Accordance with U.S. GAAP:
	Basic	$	1.79		$	2.08		$	2.57
	Diluted	$	1.78		$	2.08		$	2.56

2

Condensed Balance Sheet in Accordance with U.S. GAAP⁽⁶⁾

December 31 (millions of Canadian dollars)	2010		2009
Current assets(2)	2,711		2,706
Long-term investments(6)	4,775		4,448
Plant, property and equipment(7)	30,987		28,048
Goodwill	3,457		3,644
Regulatory assets(5)	1,699		1,675
Intangibles and other assets(5)(8)	1,512		2,041
	45,141		42,562
Current liabilities(4)(7)	5,316		4,471
Deferred amounts(5)(6)	728		899
Regulatory liabilities	308		381
Deferred income taxes(2)(5)	3,169		2,802
Long-term debt and junior subordinated notes(8)	18,115		17,335
	27,636		25,888
Shareholders' equity:
Common shares	11,745		11,338
Preferred shares	1,224		539
Non-controlling interests(1)	1,157		1,174
Contributed surplus(3)	349		346
Retained earnings(2)(3)(4)	4,273		4,149
Accumulated other comprehensive (loss)/income(1)(5)	(1,243	)	(872	)
	17,505		16,674
	45,141		42,562

Reconciliation of Accumulated Other Comprehensive (Loss)/ Income

December 31 (millions of Canadian dollars)		2010		2009		2008
Accumulated Other Comprehensive Loss in Accordance with Canadian GAAP		(877	)	(632	)	(472	)
U.S. GAAP adjustments:
	Change in funded status of postretirement plan liability(5)	(214	)	(203	)	(210	)
	Tax impact of change in funded status of postretirement plan liability	55		51		53
	Change in funded status of postretirement plan liability of equity investment	(207	)	(88	)	(40	)
Accumulated Other Comprehensive Loss in Accordance with U.S. GAAP		(1,243	)	(872	)	(669	)

⁽¹⁾

In accordance with U.S. GAAP, Net Income and Other Comprehensive Loss include both the Company's and the Non-Controlling Interests' (NCI) share and NCI is presented in the Equity section of the Balance Sheet. In the Company's consolidated financial statements prepared under Canadian GAAP, Net Income and Other Comprehensive Loss include only the Company's share and NCI is presented outside of the Equity section of the Balance Sheet. There is no U.S. GAAP difference with respect to Accumulated Other Comprehensive (Loss)/Income (AOCI) attributable to NCI. At December 31, 2010, AOCI attributable to NCI of $11 million (2009 - $17 million) is included in NCI.

⁽²⁾

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.

⁽³⁾

Under U.S. GAAP, the dilution gain resulting from TC PipeLines, LP's equity issuance was accounted for as an equity transaction. Under Canadian GAAP, the dilution gain was included in net income.

⁽⁴⁾

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.

⁽⁵⁾

Under U.S. GAAP, an employer is required 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

3

Comprehensive Income (OCI), in the year in which the changes occur. The amounts recognized in the Company's balance sheet for its defined benefit plan and other postretirement benefits are as follows:

December 31 (millions of Canadian dollars)	2010		2009
Non-current assets	40		3
Deferred amounts	(156	)	(155	)
	(116	)	(152	)

                Pre-tax amounts recognized in AOCI are as follows:

	2010			2009			2008
December 31 (millions of                         Canadian dollars)	Pension Benefits	Other Benefits	Total	Pension Benefits	Other Benefits	Total	Pension Benefits	Other Benefits	Total
Net loss	179	24	203	170	21	191	173	22	195
Prior service cost	9	2	11	10	2	12	11	4	15
	188	26	214	180	23	203	184	26	210

                Pre-tax amounts recorded in OCI were as follows:

	2010						2009
December 31 (millions of Canadian dollars)	Pension Benefits		Other Benefits		Total		Pension Benefits		Other Benefits		Total
Amortization of net loss from AOCI to OCI	(5	)	(1	)	(6	)	(5	)	(1	)	(6	)
Amortization of prior service (credit)/cost from AOCI to OCI	(2	)	–		(2	)	(2	)	–		(2	)
Funded status adjustment	15		4		19		2		(1	)	1
	8		3		11		(5	)	(2	)	(7	)

                The funded status based on the accumulated benefit obligation for all defined benefit pension plans is as follows:

December 31 (millions of Canadian dollars)	2010	2009
Accumulated benefit obligation	1,463	1,326
Fair value of plan assets	1,636	1,447
Funded status — surplus	173	121

                Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded.

December 31 (millions of Canadian dollars)	2010		2009
Accumulated benefit obligation	182		176
Fair value of plan assets	178		165
Funded status — (deficit)	(4	)	(11	)

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $5 million and $1 million, respectively. The estimated net loss and prior service cost for the other postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year is $1 million and $1 million, respectively.

The rate used to discount pension and other postretirement benefit plan obligations was based on a yield curve from Moody's corporate AA bond yields at December 31, 2010 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 postretirement obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

⁽⁶⁾

Under Canadian GAAP, the Company accounts for certain investments using the proportionate consolidation basis of accounting whereby the Company's proportionate share of 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 certain of these investments be recorded on an equity basis of accounting. Information on the balances that have been proportionately consolidated is located in Note 8 to the Company's Canadian GAAP 2010 audited consolidated annual financial statements.

As a consequence of using equity accounting for certain of these joint ventures under U.S. GAAP, the Company is required to reflect an additional liability of $150 million at December 31, 2010 (December 31, 2009 - $261 million) for 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.

4

U.S. GAAP requires the disclosure of the difference, if any, between the carrying value of the investment and the investor's underlying equity in the net assets of the investee on an ongoing basis, rather than only at the date of purchase as required under Canadian GAAP. At December 31, 2010 the Company has a US$121 million (2009 - US$121 million) difference between the carrying value of Northern Border Pipeline Company (Northern Border) and the underlying equity in the net assets primarily as a result of goodwill recognized from TC PipeLines LP's April 2006 acquisition of an additional 20 per cent general partnership interest in Northern Border.

The distributed earnings from long-term investments for the year ended December 31, 2010 were $250 million (2009 - $265 million; 2008 - $295 million). The undistributed earnings from long-term investments as at December 31, 2010 were $1,361 million (2009 - $1,174 million, 2008 - $892 million).

⁽⁷⁾

In 2009, the Company purchased the remaining 20 per cent ownership interest in Keystone, increasing its ownership interest to 100 per cent. Under Canadian GAAP the transaction is considered to be an asset purchase; however, under U.S. GAAP it is considered to be a business combination. The purchase price was allocated to Plant, Property and Equipment (US$734 million) and Short-term Debt (US$197 million) using fair values of the net assets at the date of acquisition. There is no Income Statement impact under U.S. GAAP as no gain or loss was created.

⁽⁸⁾

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.

Hedging Instruments and Activities

U.S. standards for disclosures regarding derivatives and hedging are intended to provide additional information about how derivatives and hedging activities affect an entity's financial position, financial performance and cash flows. Many of these disclosures are provided in the Company's consolidated financial statements prepared under Canadian GAAP. Additional required information is provided below.

Derivatives in Cash Flow and Net Investment Hedging Relationships

	Cash Flow Hedges														Net Investment Hedges
	Power				Natural Gas				Foreign Exchange			Interest			Foreign Exchange
Year ended December 31 (unaudited) (millions of Canadian dollars, pre-tax)	2010		2009		2010		2009		2010	2009		2010		2009	2010		2009
Amount of (losses)/gains recognized in OCI on derivatives (effective portion)	(79	)	129		(26	)	(29	)	10	(20	)	(137	)	4	126		382
Amount of (losses)/gains reclassified from AOCI into income (effective portion)	(7	)	(63	)	(21	)	18		–	–		32		30	–	(1)	–	(1)
Amount of gains/(losses) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	1		(5	)	–		–		–	–		–		–	–	(2)	–	(2)

⁽¹⁾

Location of gain/(loss) is gain/(loss) on sale of subsidiary.

⁽²⁾

Location of gain/(loss) is other income/(expense).

Derivative contracts entered into to manage market risk often contain financial assurances provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at December 31, 2010, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $92 million (2009 - $122 million), for which the Company has provided collateral of $4 million (2009 - $8 million) in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on December 31, 2010, the Company would have been required to provide additional collateral of $88 million (2009 - $114 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

5

Postretirement Benefit Plan Assets

Pension assets are invested in high-quality asset classes designed to maximize returns and diversify risk, with consideration given to the demographics of the plan members. Asset mix strategies may incorporate equity securities, debt securities, real estate and derivatives that hedge against risk. Derivatives are not used for speculative purposes and the use of leveraged derivatives is prohibited.

All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted basis and by comparison to similar assets which are publicly traded.

The following table presents plan assets for defined benefit plans and other postretirement benefits measured at fair value, categorized as follows. There were no Level III items in 2010 and 2009.

			Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Total		Percentage of Total Portfolio
December 31 (unaudited)(millions of Canadian dollars)			2010	2009	2010	2009	2010	2009	2010	2009
Asset Category
Cash and cash equivalents			19	63	–	–	19	63	1%	4%
Equity Securities:
	Canadian		394	367	93	74	487	441	29%	30%
	U.S.		225	173	127	92	352	265	21%	18%
	International		31	–	210	197	241	197	15%	13%
Fixed Income Securities:
	Canadian Bonds:
		Federal	–	–	302	276	302	276	18%	19%
		Provincial	–	–	127	110	127	110	8%	8%
		Municipal	–	–	4	2	4	2	–	–
		Corporate	–	–	64	56	64	56	4%	4%
	U.S. Bonds:
		State	–	–	28	21	28	21	2%	1%
		Corporate	–	–	19	21	19	21	1%	1%
	Mortgage Backed		–	–	22	22	22	22	1%	2%
			669	603	996	871	1,665	1,474	100%	100%

Income Taxes

Below is the reconciliation of the annual changes in the total unrecognized tax benefit.

December 31 (millions of Canadian dollars)	2010		2009
Unrecognized tax benefits, beginning of year	55		80
Gross increases - tax positions in prior years	7		6
Gross decreases - tax positions in prior years	(1	)	(4	)
Gross increases - current year positions	9		16
Settlements	(7	)	(35	)
Lapses of statute of limitations	(1	)	(8	)
Unrecognized tax benefits, end of year	62		55

TransCanada 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 $16 million. Otherwise, subject to the results of audit examinations by taxing authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its financial statements.

6

TransCanada 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 2005. Substantially all material U.S. federal income tax matters have been concluded for years through 2006 and U.S. state and local income tax matters through 2005.

TransCanada'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, 2010 is $3 million of interest expense and nil for penalties (2009 - $8 million for interest income and nil for penalties; 2008 - $10 million for interest expense and nil for penalties). At December 31, 2010, the Company had $19 million accrued for interest expense and nil accrued for penalties (December 31, 2009 - $16 million accrued for interest expense and nil accrued for penalties).

Changes in Accounting Policies

In January 2010, the Financial Accounting Standards Board issued new guidance on "Fair Value Measurements and Disclosures" which requires further disclosures with respect to recurring or nonrecurring fair value measurements. The Company adopted the required disclosures for interim and annual periods ending after December 15, 2009. In addition, activity in Level III including purchases, sales, issuances and settlements must be disclosed on a gross basis for interim periods beginning after December 15, 2010. The Company has included these additional disclosures in Note 18 to the Company's Canadian GAAP 2010 audited consolidated annual financials statements.

7

Independent Auditors' Report of Registered Public Accounting Firm

To the Shareholders of TransCanada Corporation

We have audited the accompanying consolidated financial statements of TransCanada Corporation and its subsidiaries, which comprise the consolidated balance sheets as at December 31, 2010 and 2009, 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, 2010, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinions.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of TransCanada Corporation and its subsidiaries as at December 31, 2010 and 2009 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010 in accordance with Canadian generally accepted accounting principles.

Other Matters

Our audits were made for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. The related supplementary note attached as document 13.4 entitled "Reconciliation to United States GAAP" is presented for purposes of additional analysis and requirements under securities legislation. Such supplementary note has been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic consolidated financial statements taken as a whole.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), TransCanada Corporation's internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 14, 2011 expressed an unmodified opinion on the effectiveness of TransCanada Corporation's internal control over financial reporting.

/s/ KPMG LLP
Chartered Accountants
Calgary, Canada
February 14, 2011

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 Corporation ("TransCanada"), 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.

Based on this evaluation, management concluded that internal control over financial reporting is effective as at December 31, 2010, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

In 2010, there was no change in TransCanada's internal control over financial reporting that materially affected or is reasonably likely to materially affect TransCanada's internal control over financial reporting.

KPMG LLP, the independent auditors appointed by the shareholders of TransCanada, who have audited the consolidated financial statements of TransCanada, have also audited the effectiveness of TransCanada's internal control over financial reporting as of December 31, 2010 and have issued the report entitled "Report of Independent Registered Public Accounting Firm".

February 14, 2011

/s/ RUSSELL K. GIRLING
Russell K. Girling
President and
Chief Executive Officer /s/ DONALD R. MARCHAND
Donald R. Marchand
Executive Vice-President and
Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of TransCanada Corporation

We have audited TransCanada Corporation's internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). TransCanada Corporation'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 TransCanada Corporation'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, TransCanada Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited in accordance with Canadian generally accepted auditing standards and in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TransCanada Corporation and its subsidiaries as of December 31, 2010 and 2009, and the related 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, 2010, and our report dated February 14, 2011 expressed an unmodified opinion on those consolidated financial statements.

/s/ KPMG LLP
Chartered Accountants
Calgary, Canada
February 14, 2011

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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 CORPORATION RECONCILIATION TO UNITED STATES GAAP
TRANSCANADA CORPORATION RECONCILIATION TO UNITED STATES GAAP