U.S. Securities and Exchange CommissionWashington, D.C. 20549

Form 40-F

o

REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934ORý

ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934


For
the fiscal year endedDecember 31, 2011Commission 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 registeredCommon Shares (including Rights under
Shareholder Rights Plan)

New York Stock Exchange


Securities
registered pursuant to Section 12(g) of the Act:NoneSecurities 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, 2011, 703,861,065 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 theExchange
Actduring 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



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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


333-5916S-8


333-8470S-8


333-9130S-8


333-151736F-3


33-13564F-3


333-6132F-10


333-151781F-10


333-161929F-10


333-177788


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
Corporation Annual Report to Shareholder except as otherwise specifically incorporated by reference in the TransCanada Corporation 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 103 through 164 of the TransCanada Corporation 2011 Annual Report to
Shareholders included herein. See Note 25 of the Notes to Audited Consolidated Financial Statements on pages 157 through 164 of the TransCanada Corporation 2011 Annual Report to
Shareholders, reconciling the significant differences between Canadian and United States generally accepted accounting principles.

B.    Management's Discussion & Analysis

For management's discussion and analysis, see pages 6 through 102 of the TransCanada Corporation 2011 Annual Report to Shareholders included herein under the heading
"Management's Discussion & Analysis".

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

For management's report on internal control over financial reporting, see "Report of Management" that accompanies the Audited Consolidated Financial Statements on
page 103 of the TransCanada Corporation 2011 Annual Report to Shareholders included herein.

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UNDERTAKING

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to
furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the
obligation to file an Annual Report on Form 40-F arises; or transactions in said securities.

DISCLOSURE CONTROLS AND PROCEDURES

For information on disclosure controls and procedures, see "Controls and Procedures" in Management's Discussion and Analysis on pages 88
and 89 of the TransCanada Corporation 2011 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 2011 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

For information on principal accountant fees and services, see "Corporate governance  Audit
committee  Pre-approval policies and procedures" and "Corporate governance  Audit
committee  External auditor service fees" on pages 32 and 33 of the TransCanada Corporation 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
pages 67 and 68 of the TransCanada Corporation 2011 Annual Report to Shareholders.

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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


FORWARD-LOOKING INFORMATION

This document contains 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", "intend", "target", "plan" 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 plans and financial outlook. Forward-looking statements in this document may include, but are not limited to, statements
regarding:



These
forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance.
By their nature, forward-looking statements are subject to various assumptions, risks and uncertainties which could cause TransCanada's actual results and achievements to differ materially from the
anticipated results or expectations expressed or implied in such statements.

Key
assumptions on which TransCanada's forward-looking statements are based include, but are not limited to, assumptions about:



4

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The
risks and uncertainties that could cause actual results or events to differ materially from current expectations include, but are not limited to:



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 against placing undue reliance on 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 publicly update or revise any forward-looking information in this document or
otherwise, whether as a result of new information, future events or otherwise, except as required by law.

5

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SIGNATURES

Pursuant to the requirements of theExchange 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 CORPORATIONPer:

/s/ DONALD R. MARCHAND DONALD R. MARCHAND Executive Vice-President and Chief Financial OfficerDate: February 15, 2012


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DOCUMENTS FILED AS PART OF THIS REPORT

13.1

TransCanada Corporation Annual Information Form for the year ended December 31, 2011.13.2

Management's Discussion and Analysis (included on pages 6 through 102 of the TransCanada Corporation 2011 Annual Report to Shareholders).13.3

2011 Audited Consolidated Financial Statements (included on pages 103 through 164 of the TransCanada Corporation 2011 Annual Report to Shareholders), including the auditors' report thereon.13.4

Independent Auditors' Report of Registered Public Accounting Firm on the 2011 Audited Consolidated Financial Statements.13.5

Report of Independent Registered Public Accounting Firm on the effectiveness of TransCanada's Internal Control Over Financial Reporting, as of December 31, 2011.


EXHIBITS

23.1

Consent of KPMG LLP, Independent Registered Public Accounting Firm.31.1

Certification of Chief Executive Officer pursuant to Section 302 of theSarbanes-Oxley Act of 2002.31.2

Certification of Chief Financial Officer pursuant to Section 302 of theSarbanes-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.


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LOGO

TransCanada Corporation

2011 Annual information form February 13, 2012

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Table of Contents

Table of Contents


1Presentation of information


2Forward looking information


2TransCanada Corporation


3Corporate structure


3Intercorporate relationships


4General development of the business


4Developments in the Natural Gas Pipelines business


5Developments in the Oil Pipelines business


7Developments in the Energy business


8Business of TransCanada


9Natural Gas Pipelines business


9Oil Pipelines business


12Regulation of the Natural Gas and Oil Pipelines businesses


12Energy business


13General


15Employees


15Social and environmental policies


15Environmental protection


16Risk factors


17Environmental risk factors


17Other risk factors


19Dividends


19Description of capital structure


20Share capital


20Credit ratings


23DBRS Limited (DBRS)


23Moody's Investors Service, Inc. (Moody's)


24Standard & Poor's (S&P)


24Market for securities


24Common shares


25Series 1 Preferred Shares


25Series 3 Preferred Shares


25Series 5 Preferred Shares


26Directors and officers


26Directors


26Board committees


28Officers


28Conflicts of interest


30Corporate governance


31Audit committee


31Relevant education and experience of members


31Pre-approval policies and procedures


32External auditor service fees


33Legal proceedings and regulatory actions


33Transfer agent and registrar


34Interest of experts


34Additional information


34Glossary


35Schedule ASchedule B


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Presentation of information

Unless the context indicates otherwise, a reference in this Annual Information Form ("AIF") to "TransCanada", the "Company", "we",
"us" and "our" 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 headingTransCanada 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, 2011 ("Year End"). Amounts are expressed in Canadian dollars unless otherwise
indicated. Information in relation to metric conversion can be found at Schedule A to this AIF. Terms defined throughout this AIF are listed in the Glossaryfound at the end of this AIF.
Financial information is presented in accordance with Canadian generally accepted accounting principles.

Certain
portions of TransCanada's Management's Discussion and Analysis dated February 13, 2012 ("MD&A") are incorporated by reference into this AIF as stated below. The MD&A can be found on
SEDAR (www.sedar.com) under TransCanada's profile.

Effective
January 1, 2012, TransCanada adopted U.S. generally accepted accounting principles ("U.S. GAAP") for reporting purposes. For more information regarding TransCanada's
adoption of U.S. GAAP, refer to the MD&A under the headingsAccounting Changes  Future Accounting
ChangesU.S. GAAP.

Forward looking information

This AIF, including the MD&A disclosure incorporated by reference herein, contains 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", "intend", "target", "plan" 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 plans and financial outlook. Forward-looking statements in this document may
include, but are not limited to, statements regarding:



These
forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance.
By their nature, forward-looking statements are subject to various assumptions, risks and uncertainties which could cause TransCanada's actual results and achievements to differ materially from the
anticipated results or expectations expressed or implied in such statements.

2    TransCanada Corporation

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Key
assumptions on which TransCanada's forward-looking statements are based include, but are not limited to, assumptions about:



The
risks and uncertainties that could cause actual results or events to differ materially from current expectations include, but are not limited to:



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 against placing undue reliance on forward-looking information, which is given as of the date it is expressed in this AIF, or the MD&A disclosure incorporated by reference herein,
and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to publicly update or revise any forward-looking
information in this AIF or the MD&A disclosure incorporated by reference herein whether as a result of new information, future events or otherwise, except as required by law.

TransCanada Corporation

Corporate structure

Our 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 theCanada 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

2011 Annual information form    3

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TCPL
common shares for one common share of TransCanada. The debt securities and preferred shares of TCPL remained obligations and securities of TCPL. TCPL continues to 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.

Intercorporate relationships

The
following diagram presents the name and jurisdiction of incorporation, continuance or formation of TransCanada's principal subsidiaries as at Year End. 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 Year End. TransCanada beneficially owns, controls or directs, directly or indirectly, 100 per cent of the voting shares in each of these subsidiaries, with the exception of
TransCanada Keystone Pipeline, LP in which TransCanada indirectly holds 100 per cent of the partnership interests.

GRAPHIC

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 Year End.

General development of the business

Our reportable business segments are "Natural Gas Pipelines", "Oil Pipelines" and "Energy". Natural Gas Pipelines and Oil Pipelines
are principally comprised of the Company's respective natural gas and oil pipelines in Canada, the U.S. and Mexico and our 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. Further information regarding our Natural Gas Pipelines, Oil Pipelines and Energy businesses is
available in this AIF under the headingBusiness of TransCanada.

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.

4    TransCanada Corporation

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Developments in the Natural Gas Pipelines business

Date

Description of developmentCanadian MainlineDecember 2009

The National Energy Board ("NEB") approved TransCanada's application for 2010 final tolls for the 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 tolls for 2010 compared to 2009.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 then current 2010 tolls as interim commencing January 1, 2011.January - February 2011

TransCanada received approval for revised interim tolls, effective March 1, 2011 which increased interim tolls to more closely align with tolls calculated in accordance with the 2007-2011 settlement with stakeholders
and will more closely reflect the Canadian Mainline's costs and throughput for 2011.September - October 2011

TransCanada filed with the NEB a 2012 Tolls Application and Restructuring Proposal (the "Restructuring Proposal") designed to enhance the long-term economic viability of the Canadian Mainline. The application also
seeks approval of tolls for 2012-2013, including an after tax weighted average cost of capital return of 7.0 percent assuming the Restructuring Proposal is approved. The Restructuring Proposal includes toll design and service and pricing
modifications, a depreciation proposal, and geographic extension of the Alberta System service by NOVA Gas Transmission Ltd. ("NGTL") acquiring capacity on the Canadian Mainline and Foothills systems. The application has been set down for
hearing (proceeding RH-003-2011) in the second to fourth quarters of 2012, and a decision is expected in late 2012 or early 2013.November 2011

TransCanada refiled a supplemental application with the NEB to construct $130 million of new pipeline infrastructure on the Canadian Mainline, to receive Marcellus shale natural gas from the U.S. at the Niagara
Falls receipt point for further transportation to Eastern markets. Subject to regulatory approval, deliveries from Niagara Falls are expected to begin at a rate of 230 million cubic feet per day ("MMcf/d") in November 2012 and then
increase to 350 MMcf/d by November 2013.November - December 2011

TransCanada filed for and received approval to implement interim 2012 tolls on the Canadian Mainline effective January 1, 2012, at the same level as the currently approved 2011 final tolls. The NEB approved
TransCanada's application for 2011 final tolls for the Canadian Mainline at the level of the tolls that were being charged on an interim basis. Final 2011 tolls were calculated in accordance with previously approved toll methodologies and were based
on the principles contained in the 2007-2011 settlement with stakeholders, with adjustments to reduce toll impacts. Certain aspects of the 2011 revenue requirement were rolled into the RH-003-2011 proceeding referred to above.Alberta SystemFebruary 2009

The NEB approved TransCanada's June 2008 application for federal regulation of the Alberta System effective April 29, 2009.February 2009

TransCanada announced the successful completion of a binding open season, securing support for firm transportation contracts of 378 MMcf/d for the Horn River pipeline.February 2010

TransCanada filed an application with the NEB for approval to construct and operate the Horn River pipeline.March 2010

The North Central Corridor expansion of the Alberta System was completed.March 2010

The NEB approved TransCanada's application after a public hearing to construct and operate the Groundbirch pipeline project.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 Pipelines 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.December 2010

Groundbirch pipeline was completed and began transporting natural gas from the Montney shale gas formation into the Alberta System.January 2011

TransCanada received approval from the NEB to construct the Horn River pipeline.


2011 Annual information form    5

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Date

Description of developmentMarch 2011

TransCanada commenced construction of the $275 million Horn River project, with a targeted completion date of second quarter 2012. In addition, the Company executed an agreement to extend the Horn River pipeline by
approximately 100 kilometer ("km") (62 miles) at an estimated cost of $230 million. An application requesting approval to construct and operate this extension was filed with the NEB in October 2011. The total contracted volumes
for Horn River, including the extension, are expected to be approximately 900 MMcf/d by 2020.August 2011

The NEB approved construction of a 24 km (15 miles) extension of the Groundbirch pipeline and construction commenced in August, with an expected in service date of April 2012.October 2011

Commercial integration of the NGTL and ATCO Pipelines systems commenced. Under an agreement, the facilities of NGTL and ATCO Pipelines are commercially operated as a single transmission system and transportation service
is provided to customers by NGTL pursuant to NGTL's tariff and suite of rates and services. The agreement further identifies distinct geographic areas within Alberta for the construction of new facilities by each of NGTL and ATCO
Pipelines.October 2011

The NEB approved the construction of natural gas pipeline projects for the Alberta System with a capital cost of approximately $910 million. Further pipeline projects with a total capital cost of approximately
$810 million are awaiting NEB decision.November - December 2011

The regulatory decisions by which commercial integration of the NGTL and ATCO Pipelines systems were authorized are the subject of appeals to the Federal Court of Appeal. The timing of the hearing of the appeals is
uncertain, but TransCanada expects it to be before the end of 2012.December 2011

TransCanada filed for interim 2012 tolls on the Alberta System to be effective January 1, 2012. These tolls have been approved on an interim basis pending the outcome of the NEB's decision on the application filed
for the Restructuring Proposal.Mackenzie Gas ProjectDecember 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.March 2011

The NEB issued a Certificate of Public Convenience and Necessity for the Mackenzie Gas Project.Alaska Pipeline ProjectJune 2009

TransCanada reached an agreement with ExxonMobil Corporation to jointly advance the Alaska Pipeline Project. 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 in July 2010. The Alaska Pipeline Project team continued to work with shippers to
resolve conditional bids received as part of the project's open season in working toward a U.S. Federal Energy Regulatory Commission ("FERC") application deadline of October 2012 for the Alberta option that would extend from Prudhoe Bay to
points near Fairbanks and Delta Junction, and then to the Alaska/Canada border where the pipeline would connect with a new pipeline in Canada.January 2012

TransCanada commenced initial discussions with Alaska North Slope producers regarding an alternative pipeline route, the liquefied natural gas option, that would extend from Prudhoe Bay to liquefied natural gas facilities,
 to be built by third parties, located in south-central Alaska.BisonDecember 2010

Construction of Bison pipeline, a 487 km (303 miles) pipeline, was completed.January 2011

Bison pipeline was placed into commercial service.May 2011

TransCanada closed the sale of a 25 per cent interest in each of Gas Transmission Northwest LLC and Bison Pipeline LLC to TC PipeLines, LP for a total transaction value of $605 million, which
included U.S. $81 million or 25 percent of Gas Transmission Northwest LLC's debt outstanding.GTNMay 2011

TransCanada closed the sale of a 25 per cent interest in each of Gas Transmission Northwest LLC and Bison Pipeline LLC to TC PipeLines, LP for a total transaction value of $605 million, which
included U.S. $81 million or 25 percent of Gas Transmission Northwest LLC's debt outstanding.November 2011

The FERC approved a settlement agreement between GTN and its shippers for new transportation rates to be effective January 2012 through December 2015. This settlement also requires GTN to file for new rates that
are to be effective January 2016.Great LakesNovember 2009

The FERC initiated an investigation to determine whether rates on Great Lakes were just and reasonable. In response, Great Lakes Gas Transmission Limited Partnership filed a cost and revenue study with the FERC in
February 2010.July 2010

The FERC approved, without modification, the settlement stipulation agreement reached among Great Lakes Gas Transmission Limited Partnership, active participants and the FERC trial staff. As approved, the stipulation and
agreement applies to all current and future shippers on Great Lakes.


6    TransCanada Corporation

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Date

Description of developmentNorth BajaJuly 2009

TransCanada completed the sale of North Baja Pipeline, LLC to TC PipeLines, LP.GuadalajaraMay 2009

TransCanada announced that it was the successful bidder on a contract to build, own and operate the Guadalajara pipeline.June 2011

The Guadalajara pipeline was completed. TransCanada and the Comisión Federal de Electricidad, Mexico's federal government owned electrical company have agreed to add a US$60 million compressor station to the
pipeline that is expected to be operational early in 2013.


Further information about developments in the Natural Gas Pipelines business can be found in the MD&A under the headingsTransCanada's
Strategy,Natural Gas Pipelines  Highlights,Natural Gas
Pipelines  Financial AnalysisandNatural Gas Pipelines  Opportunities and
Developments.

Developments in the Oil Pipelines business

Date

Description of developmentKeystoneAugust 2009

TransCanada became sole owner of the Keystone project through the purchase of ConocoPhillips' remaining interest 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 Keystone U.S. Gulf Coast expansion ("Keystone XL").April 2010

The U.S. Department of State issued a Draft Environmental Impact Statement for Keystone XL.June 2010

Keystone commenced operating at a reduced maximum operating pressure as the first section of Keystone began delivering oil from Hardisty, Alberta to Wood River and Patoka in Illinois ("Wood River/Patoka").November 2010

The open seasons for the Bakken Marketlink and Cushing Marketlink projects, which commenced in September 2010, closed successfully.December 2010

The reduced maximum operating pressure restriction on the Canadian conversion section of the Wood River/Patoka section of Keystone was removed by the NEB following the completion of in-line inspections.Fourth Quarter 2010

Construction of the second section of Keystone extending the pipeline from Steele City, Nebraska to Cushing, Oklahoma (the "Cushing Extension") was completed, and line fill commenced in late 2010.January 2011

Required operational modifications were completed on the Canadian conversion section of Keystone. As a result, the system was capable of operating at the approved design pressure.February 2011

The commercial in service of the Cushing Extension commenced, and the Company also commenced recording earnings for the Wood River/Patoka section.May 2011

Revised tolls came into effect for the Wood River/Patoka section.Second Quarter 2011

The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration issued a corrective action order on Keystone as a result of two above-ground incidents at pump stations in North Dakota and
Kansas. TransCanada filed a re-start plan with the U.S. Pipeline and Hazardous Material Safety Administration which was approved in June 2011.August 2011

TransCanada received a Final Environmental Impact Statement regarding the Keystone XL U.S. Presidential Permit application.November 2011

The U.S Department of State announced that further analysis of route options for Keystone XL would need to be investigated, with a specific focus on the Sandhills area of Nebraska. The review could be completed as early
as the first quarter of 2013.December 2011

TransCanada announced that it received additional binding commitments in support of Keystone XL following the conclusion of the Keystone Houston Lateral open season, which commenced in August 2011.January 2012

The U.S. Department of State denied TransCanada's application requesting a Presidential Permit to construct Keystone XL. The Company plans to submit a revised Presidential Permit application for Keystone
XL.


Further information about developments in the Oil Pipelines business can be found in the MD&A under the headingsTransCanada's
Strategy,Oil Pipelines  Highlights,Oil
Pipelines  Financial AnalysisandOil Pipelines  Opportunities and
Developments.

2011 Annual information form    7

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Developments in the Energy business

Date

Description of developmentRavenswoodMay 2009

Ravenswood's 981 MW Unit 30 returned to service. Subsequent to closing the acquisition of Ravenswood in August 2008, TransCanada experienced a forced outage event related to the unit. TransCanada has filed
claims against the insurers to enforce its rights under the insurance policies and litigation proceedings are ongoing.Third and Fourth Quarters 2011

Since July 2011, spot prices for capacity sales in the New York Zone J market have been negatively impacted by the manner in which the New York Independent System Operator ("NYISO") has applied pricing
rules for a new power plant that recently began service in this market. TransCanada believes that this application of pricing rules by the NYISO is in direct contravention of a series of the FERC orders which direct how new entrant capacity is to be
treated for the purpose of determining capacity prices. TransCanada and other parties have filed formal complaints with the FERC that are currently pending. The outcome of the complaints and longer-term impact that this development may have on
Ravenswood is unknown. During third quarter 2011, the demand curve reset process was completed following the FERC's acceptance of the NYISO's September 22, 2011 compliance filing. This resulted in increased demand curve rates that apply going
forward to 2014. Until the above noted NYISO actions relative to new unit pricing are resolved, capacity prices are expected to remain volatile.BécancourJune 2011

Hydro-Québec Distribution ("Hydro-Québec") notified TransCanada it would exercise its option to extend the agreement to suspend all electricity generation from Bécancour throughout 2012. Under the
original agreement, Hydro-Québec has the option, to extend the suspension on an annual basis until such time as regional electricity demand levels recover. TransCanada continues to receive capacity payments under the agreement similar to those
that would have been received under the normal course of operation.Bruce PowerNovember 2011

Bruce Power commenced the approximately six month West Shift Plus outage as part of the life extension strategy for Unit 3. Subject to regulatory approval, Unit 3 is expected to return to service in second quarter
2012.February 2011

The Bruce Power Refurbishment Implementation Agreement (the "BPRIA") was amended to extend the suspension date for Bruce A contingent support payments from December 31, 2011 to June 1, 2012. Contingent
support payments received from the OPA by Bruce A are equal to the difference between the fixed prices under the BPRIA and spot market prices. As a result of the amendment, all output from Bruce A will be subject to spot prices effective June 1,
2012 until the restart of both Units 1 and 2 is complete. Bruce Power and the OPA had amended certain terms and conditions of the BPRIA in July 2009, which included: amendments to the Bruce B floor price mechanism, the removal of a
support payment cap for Bruce A, an amendment to the capital cost-sharing mechanism, and addition of a provision for deemed generation payments to Bruce Power at the contracted 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. Under the original BPRIA, which was signed in 2005, 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. Fuelling of both Unit 2 and Unit 1 has now been completed and the final phases of commissioning for Unit 2 are underway. Subject to
regulatory approval, Bruce Power expects to commence commercial operations of Unit 2 in first quarter 2012 and commercial operations of Unit 1 in third quarter 2012.Portlands EnergyApril 2009

The 550 megawatt ("MW") Portlands Energy power plant was fully commissioned.Oakville Generating StationSeptember 2009

The OPA advised TransCanada that it was awarded a 20 year Clean Energy Supply contract to build, own and operate a 900 MW generating station in Oakville, Ontario.October 2010

The Government of Ontario announced that it would not proceed with the Oakville generating station.August 2011

TransCanada, the Government of Ontario and the OPA reached a formal agreement to use arbitration to settle a dispute resulting from termination of the 20 year Clean Energy Supply contract with the OPA referred to
above.Cartier WindThird Quarter 2009

Construction activity began on the Cartier Wind's 212 MW Gros-Morne and 58 MW Montagne-Sèche wind farms.November 2011

The Montagne-Sèche project and phase one of the Gros-Morne wind farm were completed.CoolidgeAugust 2009

TransCanada began construction of the 575 MW Coolidge power generating station.May 2011

Coolidge power generating station was completed and placed in service.


8    TransCanada Corporation

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Date

Description of developmentKibby WindOctober 2009

The 22 turbine, 66 MW first phase of Kibby Wind was completed and placed in service.October 2010

The 22 turbine, 66 MW second phase of Kibby Wind was completed and placed in service.SundanceFebruary 2011

TransCanada received notice from TransAlta Corporation ("TransAlta") under the Sundance A power purchase arrangement that TransAlta 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. In December 2010, the Sundance 1 and 2 generating units were withdrawn from service and were
subject to a force majeure claim by TransAlta in January 2011. TransCanada has disputed both claims under the binding dispute resolution process provided in the power purchase arrangement and both matters will be heard through a single binding
arbitration process. The arbitration panel has scheduled a hearing in April 2012 for these claims.Halton HillsSeptember 2010

The 683 MW Halton Hills power plant was completed and placed in service.Ontario SolarDecember 2011

Subject to a number of conditions precedent, TransCanada agreed to purchase nine Ontario solar power projects from Canadian Solar Solutions Inc. with a combined capacity of 86 MW for approximately
$470 million.


Further information about developments in the Energy business can be found in the MD&A under the headingsTransCanada's
Strategy,Energy  Highlights,Energy  Financial Analysisand Energy  Opportunities and
Developments.

Business of TransCanada

We are 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 49 per cent of revenues and 48 per cent of TransCanada's total assets, Oil Pipelines accounted for approximately
9 per cent of revenues and 19 per cent of TransCanada's total assets and Energy accounted for approximately 42 per cent of revenues and
29 per cent of TransCanada's total assets. The following table shows TransCanada's revenues from operations by segment, classified geographically, for the years ended December 31,
2011 and 2010.

Revenues from operations(millions of dollars)


2011


2010Natural Gas PipelinesCanada - Domestic

$
2,187

$
2,125Canada - Export(1)


787


837United States and other


1,526


1,4114,500


4,373Oil PipelinesCanada - Domestic





Canada - Export(1)


300


United States and other


527


827


NILEnergy(2)Canada - Domestic


2,649


2,243Canada - Export(1)





1United States and other


1,163


1,4473,812


3,691Total revenues(3)

$
9,139

$
8,064


(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.


The following is a description of each of TransCanada's three main areas of operations.

Natural Gas Pipelines business

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.

2011 Annual information form    9

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



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



10    TransCanada Corporation

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2011 Annual information form    11

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



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 headingsNatural Gas Pipelines,Natural Gas Pipelines  Opportunities and
DevelopmentsandNatural Gas Pipelines  Financial Analysis.

Oil Pipelines business

The Company's Keystone pipeline system and other opportunities in TransCanada's Oil Pipelines business are described below.

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 sections commenced commercial operations in June 2010 and February 2011, respectively. In January 2012, the
U.S. Department of State denied TransCanada's application to construct Keystone XL, a 2,673 km (1,661 miles) extension and expansion of the pipeline to the U.S. Gulf Coast.
The Company intends to re-apply for a Presidential Permit for Keystone XL.

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
headingsOil Pipelines, Oil Pipelines  Opportunities and DevelopmentsandOil
Pipelines  Financial Analysis.

Regulation of the Natural Gas and Oil Pipelines businesses

Canada

Natural Gas PipelinesUnder the terms of theNational Energy Board Act(Canada), the Canadian Mainline, TQM, Foothills, and the Alberta System (collectively, the "Systems")
are regulated by the NEB. The NEB sets tolls that provide TransCanada the opportunity to recover costs of transporting natural gas, including the return of capital (depreciation) and 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, and any incentive earnings.

Oil PipelinesThe NEB regulates the terms and conditions of service, including rates, and the physical operation of the Canadian portion of the Keystone system. NEB approval is also required for facility additions.
The rates for

12    TransCanada Corporation

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transportation
service on the Keystone system are calculated in accordance with a methodology agreed to in transportation service agreements between Keystone and its shippers, and approved by
the NEB.

United States

Natural Gas PipelinesTransCanada's wholly owned and partially owned U.S. pipelines, including the ANR, Bison, GTN, Great Lakes, Iroquois, Portland, Northern Border, North Baja and Tuscarora systems, are considered
"natural gas companies" operating under the provisions of theNatural Gas Act of 1938and theNatural Gas Policy Act of
1978, and are subject to the jurisdiction of the FERC. TheNatural Gas Act of 1938grants 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.

Oil PipelinesThe FERC also regulates the terms and conditions of service, including transportation rates, on the U.S. portion of the Keystone system. Certain states in which Keystone has rights of way also
regulate construction and siting of Keystone.

Energy business

The Energy segment of our business includes the acquisition, development, construction, ownership and operation of electrical power
generation plants, the purchase and marketing of electricity, the provision of electricity account services to energy and industrial customers, and the development, construction, ownership and
operation of non-regulated natural gas storage in Alberta.

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:



2011 Annual information form    13

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



TransCanada
has interests in the following:



Further
information about the Company's energy holdings and significant developments and opportunities in relation to Energy can be found in the MD&A under the headingsEnergy,
Energy  Highlights, Energy  Financial Analysisand Energy  Opportunities and Developments.

14    TransCanada Corporation

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General

Employees

At Year End, TransCanada's principal operating subsidiary, TCPL, had approximately 4,300 full time active employees,
substantially all of whom were employed in Canada and the U.S., as set forth in the following table.

Calgary


1,955Western Canada (excluding Calgary)


451Houston


467U.S. Midwest


440U.S. Northeast


403Eastern Canada


253U.S. Southeast/Gulf Coast


246U.S. West Coast


79Mexico and South America


5Total


4,299


Social and environmental policies

Health, safety and environment ("HSE") are top priorities in all of TransCanada's operations and business activities. These areas are
guided by our HSE Commitment Statement, which outlines guiding principles for a safe and healthy environment for TransCanada's employees, contractors and the public, and for our commitment to protect
the environment. All employees are responsible for TransCanada's HSE performance. We are committed to being an industry leader in conducting our business so that it meets or exceeds all applicable
laws and regulations, and minimizes risk to the public, and the environment. We are committed to continually improving our HSE performance, and to promoting safety on and off the job, in the belief
that all occupational injuries and illnesses are preventable. We endeavour to do business with companies and contractors that share our perspective and expectation on HSE performance and influence
them to improve their collective performance. We are committed to respecting the diverse environments and cultures in which we operate and to support open communication with our stakeholders.

The
Health, Safety and Environment Committee of our Board of Directors (the "Board") monitors compliance with the Company's HSE corporate policy through regular reporting. TransCanada's
integrated HSE management system is modeled after the International Organization for Standardization standard for environmental management systems, ISO 14001; and the Occupational Health and
Safety Assessment Series (OHSAS 18001) for occupational health and safety. Our HSE management system conforms to external industry consensus standards and voluntary regulatory programs and complies
with applicable legislated requirements and various other internal management systems. Resources are focused on the areas of significant risk to the organization's HSE business activities. Management
is informed regularly of all important and/or significant HSE operational issues and initiatives through formal reporting and incident management processes. TransCanada's HSE management system and
performance are assessed by an independent outside firm every three years. The most recent assessment occurred in 2009 and did not identify any material issues. The HSE management system is subject to
ongoing internal and external review to ensure that it remains effective as circumstances change.

As
one of TransCanada's priorities, safety is an integral part of the way our employees work. In 2011, one of our objectives was to sustain health and safety performance year over year. Overall,
TransCanada's safety frequency rates in 2011 continued to be better than most industry benchmarks.

The
safety and integrity of our existing and newly-developed infrastructure is also a top priority. All new assets are designed, constructed and commissioned with full consideration given to safety
and integrity, and are brought in service only after all necessary requirements have been satisfied. We expect to spend approximately $322 million in 2012 for pipeline integrity on pipelines we
operate, an increase of approximately

2011 Annual information form    15

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$78 million
over 2011 primarily due to increased levels of in-line pipeline inspection on all systems. Under the approved regulatory models in Canada, non-capital
pipeline integrity expenditures on our 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 transportation contracts, pipeline integrity expenditures are recovered through the tolling mechanism and, as a result, these expenditures have no impact on TransCanada's
earnings. Our pipeline safety record in 2011 continued to be better than industry benchmarks. We experienced two pipeline breaks in 2011 on pipelines we operate. The first break occurred in a remote
part of Northern Ontario on the Canadian Mainline pipeline system. The second break occurred in a remote part of Wyoming on the Bison pipeline system. Spending associated with public safety on the
Energy assets is focused primarily on the Company's hydro dams and associated equipment and is slightly higher than previous years due to increased spending to repair damage from the high flow events
of 2011 caused by Hurricane Irene.

Environmental
controls including physical design, programs, procedures and processes are in place to effectively manage TransCanada's environmental risk factors. With respect to physical risks arising
from climate change, we have in place a set of procedures to manage our 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 are in place to protect the health and safety of
our employees and to limit the impact to the environment of any operational upsets caused by a natural disaster.

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 our financial strength and success. Governments in North America are developing long-term plans for limiting
greenhouse gas ("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.

Aboriginal, Native American and stakeholder engagement

We recognize that an enhanced level of engagement of a wide variety of stakeholders in our business activities can have a significant
impact on the Company's ability to obtain approvals for new assets and to maintain our social licenses to operate. TransCanada has a number of policies, guiding principles and practices in place to
help manage stakeholder engagement. TransCanada has adopted a code of business ethics which applies to our 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 our dealings with all stakeholders. The code may be
viewed on our website (www.transcanada.com).

Our
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 our
belief in engaging stakeholders from the earliest stages of our projects, through the project development process and into operations.

Environmental protection

TransCanada's facilities are subject to stringent federal, state, provincial, and local environmental statutes and regulations
governing environmental protection, including, but not limited to, air emissions and GHG emissions, water quality, wastewater discharges and waste management. Such laws and regulations generally
require facilities to obtain or comply with a wide variety of environmental registrations, licences, permits and other approvals and requirements. Failure to comply with these laws and regulations may
result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements and/or

16    TransCanada Corporation

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the
issuance of orders respecting future operations. We have ongoing inspection programs designed to keep all of our facilities in compliance with environmental requirements.

At
December 31, 2011, TransCanada recorded liabilities of approximately $69 million (2010  $84 million) for remediation obligations and
compliance costs associated with certain environmental regulations. We believe that the Company has considered all necessary contingencies and established appropriate reserves for environmental
liabilities; however, there is the risk that unforeseen matters may arise requiring us 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.

The
Company owns assets in four regions, Alberta, Québec, B.C., and the Northeastern U.S., where regulations exist to address industrial GHG emissions. We have procedures in place to
comply with these regulations. In Alberta, under theSpecified Gas Emitters Regulation, industrial facilities emitting GHG emissions over an intensity
threshold level are required to reduce the intensity of GHG emissions by 12 per cent below an average baseline. Our Alberta-based facilities are subject to this regulation, as are the
Sundance and Sheerness coal-fired power facilities with respect to which TransCanada has certain rights under power purchase arrangements. TransCanada has a program in place to manage the
compliance costs incurred by these assets as a result of the 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 GHG emissions related
costs of $13 million for 2011 (2010  $22 million), 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 2011, 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
carbon tax in B.C., which came into effect in mid-2008, applies to carbon dioxide ("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 2011 were approximately $3 million
(2010  $4 million). The cost per tonne of CO2 will be increased in July 2012 to $30.00 from $25.00.

States
in the northeastern U.S. 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 were 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 $4 million in 2011 (2010  $5 million). These costs were generally recovered through the power market and the net impact on TransCanada was
not significant.

Risk factors

Environmental risk factors

Environmental risks

Environmental risks from our operating facilities typically include: air emissions and GHG emissions; potential impacts on land, including land
reclamation or restoration following construction; the use, storage and release of hydrocarbons or other chemicals; the generation, handling and disposal of wastes and hazardous wastes; and water
impacts such as uncontrolled water discharge.

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 distribution due to
warmer temperatures have been experienced, however, very few kilometers of our pipeline systems are currently in

2011 Annual information form    17

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permafrost
regions. If we build new facilities in northern areas, the Company's facility designs will take into account the potential for changing permafrost distribution.

As
mentioned above, our 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:



Changing legislation and regulations

The impact of new or proposed federal, state, and/or provincial safety and environmental laws, regulations, guidelines and
enforcement in Canada and the U.S. on our business is not yet certain. We make assumptions about possible expenditures for 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 reassessment of current regulations under
theToxic Substances Control Act,governing the authorized use of polychlorinated biphenyls in certain equipment. Following a review of comments, the
EPA has indicated that the use authorization for pipelines will likely remain in place but that requirements to use the authorization may become more strict. These changes would likely result in
increased costs for our impacted pipelines. Proposed EPA rules are expected in 2012.

In
Canada, development of the major elements of an Air Quality Management System ("AQMS") continued in 2011 following endorsement of the AQMS in October 2010 by the Canadian Council of
Ministers of the Environment. Two key aspects of the AQMS are of particular interest to us: the Base Level Industry Emissions Standards, which assumes that all significant industrial sources of
emissions in Canada should be expected to meet, base-level of environmental performance; and air zone management, which is intended to address the sources of air pollution and the actions
that are required to ensure that a specified level of air quality is improved or maintained in a specified region. While our Canadian based facilities would likely be impacted by AQMS, the potential
financial impact of this initiative is currently unknown.

Regulation
of air pollutant emissions under the U.S.Clean Air Actand state regulations continue to evolve. A number of EPA initiatives could
lead to impacts ranging from requirements to install enhanced 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, we anticipate additional future costs related to
the monitoring and control of air emissions.

18    TransCanada Corporation

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In addition to those climate change policies already in place, there are also federal, regional, state, and provincial initiatives currently in development. While recent political and economic events
may significantly affect the scope and timing of new policies, we anticipate 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.

In
August 2011, the Canadian government published the first sector specific draft regulation that will impact industrial GHG emissions. This proposed regulation is focused on the
coal-fired generation of electricity and requires a natural gas performance standard for all coal-fired facilities reaching the end of their economic life. The draft regulation
is expected to come into effect in July 2015. This process is not expected to pose a significant risk or financial impact to our existing facilities and may present opportunities for new power
generation investment. Additional sectors, including the natural gas-fired generation of electricity and upstream oil and gas facility sectors, are expected to begin consultations with
Environment Canada.

The
Western Climate Initiative ("WCI") continues to work toward implementing a regional cap-and-trade program. California and Québec are the only WCI members
with cap-and-trade regulations. In December 2011, the Government of Québec adopted the "Regulation respecting the cap-and-trade
system for greenhouse gas emission allowances". The initial phase of the cap-and-trade system will begin January 1, 2013. The regulation will have a limited impact on
TransCanada's Bécancour power generation facility and natural gas pipeline assets. With respect to California, the Air Resources Board adopted a cap-and-trade
regulation in October 2011. The regulation is divided into two phases: the first, beginning in 2013, will include all major industrial sources and electricity utilities; the
second, starting in 2015, will cover distributors of transportation fuels, natural gas and other fuels. The regulation may impact the Company's importation of electricity into the state.

TransCanada
monitors climate change policy developments and, when warranted, participates in policy discussions in jurisdictions where we have operations. We are also continuing our programs to manage
GHG emissions from our facilities and to evaluate new processes and technologies that result in improved efficiencies and lower GHG emission rates. For example, in 2011 TransCanada participated in a
number of multi-stakeholder expert groups that were established to develop equipment standards in Canada. TransCanada participated both independently and through industry associations.

Other risk factors

A discussion of the Company's risk factors can be found in the MD&A under the headingsNatural 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  OpportunitiesandDevelopments, Energy  Business Risks,
Energy  OutlookandRisk 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 it 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 $0.29 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

2011 Annual information form    19

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amount
of $1.15 per share were declared and paid on the Series 1 Preferred Shares. For the period January 1, 2011 to December 31, 2011, 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 headingFirst preferred
sharesbelow.

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 11, 2010 to December 31, 2010,
dividends in the amount of $0.80 per share were declared and paid on the Series 3 Preferred Shares. For the period January 1, 2011 to December 31, 2011, dividends in the amount of
$1.00 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 headingFirst preferred
sharesbelow.

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 $0.65 per share were declared and dividends in the amount of $0.37 per share were paid, on the Series 5 Preferred Shares. For the period
January 1, 2011 to December 31, 2011, dividends in the amount of $1.10 per share were declared and 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 headingFirst preferred sharesbelow.

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

2011

2010

2009Dividends declared on common shares

$
1.68

$
1.60

$
1.52


Description of capital structure

Share capital

TransCanada's authorized share capital consists of an unlimited number of common shares, of which 703,861,065 were issued and
outstanding at Year End, and an unlimited number of first preferred shares and second preferred shares, issuable in series, of which 22,000,000 Series 1 Preferred Shares,
14,000,000 Series 3 Preferred Shares and 14,000,000 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

20    TransCanada Corporation

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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 per cent 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. Commencing with dividends declared in April 2011, common shares purchased with reinvested cash dividends were satisfied with shares
acquired on the open market at 100 per cent of the weighted average purchase price. Previously, common shares were 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. In February 2012, the Board approved an increase in the quarterly common share dividend payment by 5 per cent to $0.44 per share from $0.42 per share, for
the quarter ending March 31, 2012. 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 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.

2011 Annual information form    21

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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 sixty-six and two-thirds 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 headingDividends.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 and
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 headingDividends.The rights, privileges,
restrictions and conditions attaching to the Series 3 Preferred Shares are substantially identical to those attaching to the Series 1 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 and
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 headingDividends.The rights, privileges,
restrictions and conditions attaching to the Series 5 Preferred Shares are substantially identical to those attaching to the Series 1 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 and
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. Subject to the CBCA, the series provisions attaching to the Series 1, 2, 3, 4, 5 or 6 Preferred Shares may be amended with the written approval
of all the holders of such series of shares outstanding or by at least two-thirds of the votes cast at a meeting of the holders of such shares duly called for the purpose and at which a
quorum is present.

22    TransCanada Corporation

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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 & 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&PSenior unsecured debtDebentures

A

A3


A-Medium-term notes

A

A3


A-Junior subordinated notes

BBB (high)

Baa1


BBBDBRS

Moody's


S&PPreferred shares

Pfd-2 (low)

Baa2


P-2Commercial paper

R-1 (low)

-


A-2Trending/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
Company paid fees to each of DBRS, Moody's and S&P for the credit ratings rendered on each of the outstanding classes of securities noted above. No additional payments were made to DBRS, Moody's
and S&P in respect of any other services provided to the Company during the past two years.

The
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

2011 Annual information form    23

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for
the payment of interest and principal is substantial, but of lesser credit quality than that of AA rated securities. Long-term debt rated A may be vulnerable to future events but
qualifying negative factors are considered manageable. 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 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. As guarantor of a U.S. subsidiary's commercial
paper program, TCPL has been assigned a commercial paper rating of A-2 which is the second highest of nine rating categories for short-term debt obligations. A short
term debt rated A-2 is somewhat more susceptible to adverse effects of changes in economic conditions than higher rated categories; however, the capacity to meet all financial
commitments remains satisfactory. 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 11, 2010 and June 29, 2010, 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

24    TransCanada Corporation

---



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
TradedDecember 2011


44.74


42.03


44.53


38,155,545


43.95


40.55


43.67


10,540,577November 2011


42.90


39.25


42.88


40,551,335


42.54


38.62


41.80


22,065,841October 2011


44.10


39.81


42.37


41,926,225


44.38


37.58


43.04


15,887,005September 2011


43.23


40.27


42.54


33,171,287


43.79


39.08


40.49


16,346,869August 2011


42.36


37.00


42.36


41,333,472


43.20


37.29


43.15


26,402,340July 2011


42.39


39.42


40.14


32,882,839


44.08


40.66


41.95


8,871,558June 2011


43.72


41.07


42.35


33,597,026


45.09


41.76


43.84


8,832,316May 2011


43.48


40.75


43.39


27,895,419


44.97


42.10


44.83


7,444,917April 2011


40.71


38.95


40.71


24,366,705


43.02


40.37


42.94


7,523,263March 2011


39.64


37.73


39.31


36,681,641


40.76


37.88


40.53


12,204,704February 2011


39.19


36.53


39.04


37,966,180


40.32


36.76


40.21


9,750,606January 2011


38.40


36.10


36.55


32,309,382


38.61


36.12


36.54


8,313,201


Series 1 Preferred Shares

TSX (TRP.PR.A)Month

High
($)

Low
($)

Close
($)

Volume
TradedDecember 2011


26.50


25.85


26.21


154,033November 2011


26.38


25.66


26.02


215,475October 2011


26.05


25.71


25.97


305,469September 2011


26.32


25.78


25.85


221,164August 2011


26.28


25.65


25.85


156,599July 2011


26.20


25.81


26.07


226,612June 2011


26.24


25.68


25.94


278,119May 2011


26.25


25.65


25.66


1,207,022April 2011


26.00


25.70


25.80


172,341March 2011


26.00


25.40


25.75


282,270February 2011


26.36


25.40


25.64


479,357January 2011


26.25


25.75


26.21


601,031


Series 3 Preferred Shares

TSX (TRP.PR.B)Month

High
($)

Low
($)

Close
($)

Volume
TradedDecember 2011


25.89


24.94


25.75


165,577November 2011


25.45


24.97


25.16


359,674October 2011


25.39


24.96


25.25


350,993September 2011


25.38


25.00


25.12


221,672August 2011


25.67


24.81


25.01


278,636July 2011


25.92


25.15


25.67


501,178June 2011


25.54


24.93


25.20


343,637May 2011


25.44


24.85


24.99


326,765April 2011


25.39


24.93


25.20


328,708March 2011


25.20


24.42


24.96


389,964February 2011


25.35


24.36


24.79


336,606January 2011


25.48


24.70


25.02


499,120


2011 Annual information form    25

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Series 5 Preferred Shares

TSX (TRP.PR.C)Month

High
($)

Low
($)

Close
($)

Volume
TradedDecember 2011


26.67


25.58


25.80


175,643November 2011


25.98


25.45


25.84


388,764October 2011


25.60


25.00


25.49


696,761September 2011


26.44


25.27


25.46


281,423August 2011


26.00


25.45


25.77


308,562July 2011


26.10


25.50


25.88


199,978June 2011


26.10


25.33


25.56


170,757May 2011


25.90


25.45


25.80


450,511April 2011


25.73


25.27


25.52


154,113March 2011


25.89


25.19


25.73


724,705February 2011


25.76


25.12


25.39


378,470January 2011


26.15


25.28


25.49


541,030


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 13, 2012, the directors and officers of TransCanada as a group beneficially owned, or exercised control or
direction, directly or indirectly, over an aggregate of 551,756 common shares of TransCanada. This constitutes less than one per cent of TransCanada's common shares. The Company collects
this information from our directors and officers but otherwise we have no direct knowledge of individual holdings of TransCanada's securities.

Directors

The
following table sets forth the names of the 14 directors who serve on the Board, as of February 13, 2012, together with their jurisdictions of residence, all positions and offices
held by them with TransCanada and the Company's significant affiliates, their principal occupations or employment during the past five years and the year from which each director has continually
served as a director of TransCanada 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 sinceKevin E. Benson
Calgary, Alberta
Canada

President and Chief Executive Officer, Laidlaw International, Inc. (transportation services) from June 2003 to October 2007. Director, Calgary Airport Authority.


2005Derek H. Burney(1), O.C.
Ottawa, Ontario
Canada

Senior strategic advisor at Norton Rose Canada LLP (law firm). Chair (not a Director), International Advisory Board for Garda World Consulting and Investigation/Global Risks Group, 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.


2005Wendy 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


26    TransCanada Corporation

---



Name and
place of residence

Principal occupation during the five preceding years

Director sinceE. 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).


2005The Hon. Paule Gauthier,
P.C., O.C., O.Q., Q.C.
Québec, Québec
Canada

Senior Partner, Stein Monast L.L.P. (law firm). Director, Metro Inc., Royal Bank of Canada, Care Canada and the Fondation du Musée national des beaux-arts du Québec. Director, Institut
Québecois des Hautes Études Internationales, Laval University from 2002 until 2009 and RBC Dexia Investors Trust until October 2009.


2002Russell 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. Director,
Agrium Inc.


2010S. Barry Jackson
Calgary, Alberta
Canada

Chair of the Board, TransCanada since April 2005. Director, Nexen Inc. (oil and gas) and Director, WestJet Airlines Ltd. Director Cordero Energy Inc. from April 2005 to
September 2008.


2002Paul 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. Director, Exelon Corporation (energy),
and a trustee of Putnam Mutual Funds. 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.


2004John A. MacNaughton(2), C.M.
Toronto, Ontario
Canada

Chair of the Business Development Bank of Canada. Chair of the Independent Nominating Committee of the Canada Employment Insurance Financing Board since 2008. Member of the Prime Minister's Advisory Committee on the
Public Service. 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.


2006David P. O'Brien(4)
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.


2001Paula Rosput Reynolds
Seattle, Washington
U.S.

President and Chief Executive Officer of PreferWest, LLC (business advisory group) since October 2009. Director of Anadarko Petroleum Corporation, Delta Air Lines, Inc. and BAE Systems plc. Vice
Chairman and Chief Restructuring Officer of American International Group Inc. (insurance and financial services) from October 2008 to September 2009. President and Chief Executive Officer of Safeco Corporation (insurance) from 2006 to
2008.


2011W. Thomas Stephens(3)
Greenwood Village, Colorado
U.S.

Trustee, Putnam Mutual Funds. Chair and Chief Executive Officer of Boise Cascade, LLC (paper, forest products and timberland assets) from November 2004 to November 2008. Director, Boise Inc. from
February 2008 until April 2010.


2007
(3)D. Michael G. Stewart
Calgary, Alberta
Canada

Director, Canadian Energy Services & Technology Corp., Pengrowth Energy Corporation and C&C Energia Ltd. Director, Orleans Energy Ltd. from October 2008 to December 2010. Director,
Pengrowth Corporation (the administrator of Pengrowth Energy Trust) from October 2006 to December 2010. Director, Canadian Energy Services Inc. (the general partner of Canadian Energy Services L.P.) from
January 2006 to December 2009.


2006Richard E. Waugh
Toronto, Ontario
Canada

President and Chief Executive Officer and director of The Bank of Nova Scotia (Scotiabank) since March 2003. Director and President, International Monetary Conference. Vice-Chair, Board of the Institute of
International Finance.


2012


(1)Canwest
Global Communications Corp. ("Canwest") voluntarily entered into the Companies' Creditors Arrangement Act ("CCAA") and obtained an order from the
Ontario Superior Court of Justice (Commercial Division) to start proceedings on October 6, 2009. Although no cease trade orders were issued, Canwest shares were de-listed by the TSX
after the filing and started trading on the TSX Venture Exchange. Canwest emerged from CCAA protection, and Postmedia Network acquired its newspaper business on July 13, 2010 while Shaw
Communications Inc. acquired its broadcast media business on October 27, 2010. Mr. Burney ceased to be a director of Canwest on October 27, 2010.(2)Nortel
Networks Limited was 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 some of Nortel's 2005 financial statements. The order was revoked by the OSC on June 8, 2006, and the other
provincial securities regulators shortly after. On January 14, 2009, Nortel and some of its Canadian subsidiaries filed for creditor protection under CCAA.(3)Mr. Stephens
previously served on the Board from 2000 to 2005.(4)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.


2011 Annual information form    27

---





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 February 13, 2012, are identified below:

Director

Audit
Committee

Governance
Committee

Health, Safety
and Environment
Committee

Human Resources
CommitteeKevin E. Benson

Chair

üDerek H. Burney

ü

üWendy K. Dobson





ü

üE. Linn Draper

ü



ChairPaule Gauthier





ü

üS. Barry Jackson



ü



üPaul L. Joskow

ü

üJohn A. MacNaughton

ü

ChairDavid P. O'Brien



ü



üPaula Rosput Reynolds





ü

üW. Thomas Stephens





ü

ChairD. Michael G. Stewart

ü



üRichard E. Waugh



ü


The charters of the Audit Committee, Governance Committee, the Health, Safety and Environment Committee and the Human Resources Committee can be found on our
website (www.transcanada.com) underCorporate Governance  Board Committees.Information about the Audit Committee
can be found in this AIF under the headingAudit Committee.

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

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

28    TransCanada Corporation

---



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 yearsRussell 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 and Chief Financial Officer, Corporate Development,
since March 2003 and Chief Financial Officer, since August 1999.Wendy L. Hanrahan(1)

Executive Vice-President, Corporate Services

Prior to May 2011, Vice-President, Human Resources since January 2005.Gregory A. Lohnes

President, Natural Gas Pipelines

Prior to July 2010, Executive Vice-President and Chief Financial Officer since June 2006.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.Sean McMaster

Executive Vice-President, General Counsel and Chief Compliance Officer, and Executive Vice-President, Stakeholder Relations

Prior to February 2012, Executive Vice-President, Corporate and General Counsel and Chief Compliance Officer. Prior to January 2007, Executive Vice-President and General Counsel and Chief Compliance Officer.
Prior to October 2006, General Counsel and Chief Compliance Officer.Alexander J. Pourbaix

President, Energy and Oil Pipelines

President, Energy from July 2006 to July 2010 and Executive Vice-President, Corporate Development from July 2009 to July 2010.Donald M. Wishart

Executive Vice-President, Operations and Major Projects

Prior to July 2009, Executive Vice-President, Operations and Engineering since March 2003.


(1)Ms. Hanrahan
has held the position of Executive Vice-President, Corporate Services since May 1, 2011, upon the retirement of
Ms. Sarah Raiss who had held the position since January 2002.


2011 Annual information form    29

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Corporate officers

Name

Present position held

Principal occupation during the five preceding yearsSean 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 December 2009, Director, Joint Venture Management, Keystone
Pipeline Project of TCPL. Prior to December 2008, Vice-President and Treasurer of TC PipeLines GP, Inc.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 since June 2006.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.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

Vice-President and Controller since June 2006.


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 our tariff, deny transportation service to a creditworthy shipper. Further, due to
the specialized nature of the industry, TransCanada believes that it is important for our 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.

30    TransCanada Corporation

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Corporate governance

Our Board and management are committed to the highest standards of ethical conduct and corporate governance.

TransCanada
is a public company listed on the TSX and the NYSE, and we recognize and respect rules and regulations in both Canada and the U.S.

Our
corporate governance practices comply with the Canadian governance guidelines, which include the governance rules of the Canadian Securities Administrators ("CSA"):



We
also comply with the governance listing standards of the NYSE and the governance rules of the SEC that apply to foreign private issuers.

Our
governance practices comply with the NYSE standards for U.S. companies in all significant respects, except as summarized on our website (www.transcanada.com). As a
non-U.S. company, we are not required to comply with most of the governance listing standards of the NYSE. As a foreign private issuer, however, we must disclose how our governance
practices differ from those followed by U.S. companies that are subject to the NYSE standards.

We
benchmark our policies and procedures against major North American companies to assess our standards and we adopt best practices as appropriate. Some of our best practices are derived from the NYSE
rules and comply with applicable rules adopted by the SEC to meet the requirements of theSarbanes-Oxley Act of 2002and the Dodd-Frank Wall Street Reform and Consumer
Protection Act.

Further
information about TransCanada's corporate governance can be found on our website (www.transcanada.com) under the headingCorporate Governanceand in theGovernancesection of TransCanada's Management Information Circular dated February 13, 2012.

Audit committee

The Audit Committee is responsible for assisting the Board in overseeing the integrity of our financial statements and our compliance
with legal and regulatory requirements. It is also responsible for overseeing and monitoring the internal accounting and reporting process and the process, performance and independence of our internal
and external auditors. The Charter of the Audit Committee can be found in Schedule B of this AIF and on our website (www.transcanada.com) under theCorporate
Governance  Board Committeespage.

Relevant education and experience of members

The members of the Audit Committee as of February 13, 2012 are 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 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.

2011 Annual information form    31

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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
Norton Rose Canada 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, and has participated in Financial Reporting Standards Training offered by KPMG.

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. Mr. Stewart held a number of senior executive positions with
Westcoast Energy Inc. including Executive Vice-President, Business Development. He has been active in the Canadian energy industry for over 38 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

32    TransCanada Corporation

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Committee
Chair is required, and the Audit Committee is to be informed of the engagement at the next scheduled Audit Committee meeting. For all engagements of $100,000 or more,
pre-approval of the Audit Committee is required. In all cases, regardless of the dollar amount involved, where there is a potential for conflict of interest involving the external auditor
to arise on an engagement, the Audit Committee Chair must pre-approve the assignment.

To
date, 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 2011 and 2010 fiscal years.

($ millions)

2011

2010Audit fees    audit of the annual consolidated financial statements
    services related to statutory and regulatory filings or engagements
    reviewing interim consolidated financial statements and information contained in various prospectuses and other offering documents

$
6.9

$
6.5Audit-related fees    services related to the audit of the financial statements of certain TransCanada pension plans


0.2


0.2Tax fees    Canadian and international tax planning and tax compliance matters, including the review of income tax returns and other tax filings


0.4


1.0All other fees    services related to environmental compliance in 2011 and advice and training related to International Financial Reporting Standards in 2010


0.1


0.2Total fees

$
7.6

$
7.9


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.

The
Company believes that TransAlta's claims with respect to Sundance A do not meet the test of force majeure or destruction as specified in the power purchase arrangement and has therefore recorded
revenues and costs throughout 2011 under the power purchase arrangement as though this event was
an interruption of supply. While the outcome of any arbitration process is not certain, TransCanada believes the matter will be resolved in its favour.

Further
information about the Sundance arbitration can be found in this AIF under the headingDevelopments in the Energy Businessand in the MD&A under
the headingEnergy  Opportunities and Developments.

2011 Annual information form    33

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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, Toronto, and Montréal.

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

34    TransCanada Corporation

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Glossary

AIF

Annual Information Form of TransCanada Corporation dated February 13, 2012AQMS

Air Quality Management SystemAlaska Pipeline

A proposed natural gas pipeline extending from Prudhoe Bay, Alaska to either Alberta or Valdez, AlaskaAlberta System

A natural gas transmission system in Alberta and B.C.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, Indiana and Ohio, and regulated underground natural gas storage facilities in MichiganB.C.

British ColumbiaBPRIA

Bruce Power Refurbishment Implementation AgreementBcf

Billion cubic feetBécancour

A natural gas-fired cogeneration plant near Trois-Rivières, QuébecBison

A natural gas pipeline extending from the Powder River Basin in Wyoming to Northern Border in North DakotaBoard

TransCanada's Board of DirectorsBruce 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)Canadian Mainline

A natural gas transmission system extending from the Alberta/Saskatchewan border east into QuébecCanwest

Canwest Global Communications Corp.Cartier Wind

Five wind farms in Gaspé, Québec, four plus the first phase of the fifth which are operational and phase two of the
fifth under constructionCBCA

Canada Business Corporations ActCCAA

Companies' Creditors Arrangement ActCO2

Carbon dioxideCoolidge

A simple-cycle, natural gas-fired peaking power generation station in Coolidge, ArizonaCSA

Canadian Securities AdministratorsCushing Extension

A crude oil pipeline extending from Steele City, Nebraska to Cushing, OklahomaDBRS

DBRS LimitedEnergy

As defined in this AIF under the headingGeneral development of the businessEPA

Environmental Protection Agency (U.S.)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. borderGHG

Greenhouse gasGreat 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.GTN

A natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border, traversing Idaho,
Washington and Oregon


2011 Annual information form    35

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Guadalajara

A natural gas pipeline in Mexico extending from Manzanillo, Colima to Guadalajara, JaliscoHalton Hills

A natural gas-fired, combined-cycle power plant in Halton Hills, OntarioHSE

Health, safety and environmentHydro-Québec

Hydro-Québec DistributionIroquois

A natural gas transmission system that connects with the Canadian Mainline near Waddington, New York, and delivers natural
gas to the northeastern U.S.Keystone

A crude oil pipeline system which extends from Hardisty, Alberta to the U.S. markets and includes Wood River/Patoka and the
Cushing ExtensionKeystone XL

Keystone XL includes the construction of a new crude oil pipeline from Cushing, Oklahoma to the U.S. Gulf Coast, the expansion of
existing facilities at Hardisty, Alberta and the construction of a new crude oil pipeline from Hardisty to Steele City, NebraskaKibby Wind

A wind farm located in Kibby and Skinner townships in northwestern Franklin County, Mainekm

Kilometer(s)Mackenzie Gas Project

A proposed natural gas pipeline extending from a point near Inuvik, Northwest Territories to the northern border of
AlbertaMD&A

TransCanada's Management's Discussion and Analysis dated February 13, 2012MMcf/d

Million cubic feet per dayMoody's

Moody's Investors Service, Inc.MW

Megawatt(s)Natural Gas Pipelines

As defined in this AIF under the headingGeneral development of the businessNEB

National Energy BoardNorth Baja

A natural gas transmission system extending from Arizona to the Baja California, Mexico/California borderNorthern Border

A natural gas transmission system extending from a point near Monchy, Saskatchewan to the U.S. MidwestNGTL

Nova Gas Transmission Ltd.Nortel

Nortel Networks Limited and Nortel Networks Corporation, collectivelyNYISO

New York Independent System OperatorNYSE

New York Stock ExchangeOcean State Power

A natural gas-fired, combined-cycle plant in Burrillville, Rhode IslandOil Pipelines

As defined in this AIF under the headingGeneral development of the businessOPA

Ontario Power AuthorityOSC

Ontario Securities CommissionPortland

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, OntarioRavenswood

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 YorkRestructuring Proposal

Canadian Mainline 2012 Tolls Application and Restructuring ProposalRGGI

Regional Greenhouse Gas InitiativeS&P

Standard & Poor'sSEC

U.S. Securities and Exchange CommissionSeries 1 Preferred Shares

TransCanada's cumulative, redeemable, first preferred shares, series 1Series 2 Preferred Shares

TransCanada's cumulative, redeemable, first preferred shares, series 2


36    TransCanada Corporation

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Series 3 Preferred Shares

TransCanada's cumulative, redeemable, first preferred shares, series 3Series 4 Preferred Shares

TransCanada's cumulative, redeemable, first preferred shares, series 4Series 5 Preferred Shares

TransCanada's cumulative, redeemable, first preferred shares, series 5Series 6 Preferred Shares

TransCanada's cumulative, redeemable, first preferred shares, series 6Sheerness

A coal-fired power generating facility near Hanna, AlbertaSOPs

TransCanada's stock-based compensation plansSR Plan

TransCanada's Shareholder Rights Plansubsidiary

As defined in this AIF under the headingPresentation of informationSundance

Two coal-fired power generating facilities near Wabamun, Alberta (Sundance A and Sundance B, collectively)Systems

As defined in this AIF under the headingRegulation of the Natural Gas and Oil Pipelines
businessesTCPL

TransCanada PipeLines LimitedTQM

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 PortlandTransCanada or the Company

TransCanada CorporationTransAlta

TransAlta CorporationTSX

Toronto Stock ExchangeTuscarora

A natural gas transmission system extending from Malin, Oregon to Wadsworth, NevadaU.S. or US

United StatesU.S. GAAP

U.S. generally accepted accounting principlesWCI

Western Climate InitiativeWood River/Patoka

A crude oil pipeline extending from Hardisty, Alberta to U.S. Markets at Wood River and Patoka in IllinoisYear End

December 31, 2011


2011 Annual information form    37

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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

FactorKilometres (km)

Miles

0.62Millimetres

Inches

0.04Gigajoules

Million British thermal units

0.95Cubic metres*

Cubic feet

35.3Kilopascals

Pounds per square inch

0.15Degrees Celsius

Degrees Fahrenheit

to convert to Fahrenheit multiply by 1.8,
then add 32 degrees; to convert to Celsius
subtract 32 degrees, then divide by 1.8


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


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Schedule B      Charter of the Audit Committee

1.     Purpose



2.     Roles and Responsibilities







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2    TransCanada Corporation

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2011 Annual information form    3

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4    TransCanada Corporation

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3.     Composition of Audit Committee



4.     Appointment of Audit Committee Members



5.     Vacancies



2011 Annual information form    5

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6.     Audit Committee Chair



7.     Absence of Audit Committee Chair



8.     Secretary of Audit Committee



9.     Meetings



10.  Quorum



11.  Notice of Meetings



12.  Attendance of Company Officers and Employees at Meeting



6    TransCanada Corporation

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13.  Procedure, Records and Reporting



14.  Review of Charter and Evaluation of Audit Committee



15.  Outside Experts and Advisors



16.  Reliance



2011 Annual information form    7

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DeliVering
  CritiCal energy infrastruCture 2011 | annual rePOrt transCanada Corporation
  2011 annual rePOrt


15 12 3 13 11
  12 1 1 21 22 2 3 16 4 16 18 2 5 8 10 7 6 11 17 18 14 13 15 4 5 19 10 8 9 4 9
  7 17 20 14 6 19 19 Natural Gas Pipelines Alberta System Canadian Mainline
  Great Lakes (69%) ANR GTN (83.3%) Tuscarora (33.3%) North Baja (33.3%)
  Foothills Northern Border (16.7%) Bison (83.3%) TQM (50%) Portland (61.7%)
  Iroquois (44.5%) Tamazunchale Guadalajara Alaska Pipeline Project (proposed)
  Mackenzie Gas Project (proposed by producers) Oil Pipeline Keystone Keystone
  XL (in development) Regulated Natural Gas Storage ANR Natural Gas Storage All
  assets wholly owned except as noted 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17
  18 19 20 PiPelines Natural Gas Pipeline Natural Gas Pipeline (Under
  Construction) Natural Gas Pipeline (Proposed) Oil Pipeline Oil Pipeline (In
  Development) Power Generation Facility Natural Gas Storage Facility


Natural Gas
  Power Generation Bear Creek MacKay River Redwater Carseland Cancarb Portlands
  Energy (50%) Halton Hills Bécancour Grandview Ocean State Power Ravenswood
  Coolidge 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%) 4 of 5 stages complete
  Kibby Wind Hydro Power Generation TC Hydro Unregulated Natural Gas Storage
  Edson CrossAlta (60%) 21 22 1 2 3 10 13 7 8 9 11 14 12 15 16 17 18 4 5 6 19
  energy


Its been said
  the results you achieve will be in direct proportion to the effort you apply.
  Through the efforts of TransCanadas 4,400 employees, much was achieved in
  2011, right across North America. The companys capital program is nearly 50
  per cent complete, with $10 billion in assets becoming operational since the
  second quarter of 2010. These assets are doing what they were designed to do:
  produce predictable, sustainable earnings and cash flow growth for our
  shareholders, while delivering energy safely and reliably to customers across
  North America. TransCanada has $49 billion in blue-chip energy infrastructure
  assets and we have a presence in seven Canadian provinces, 33 U.S. States and
  Mexico. We operate one of North Americas largest natural gas pipeline
  networks  68,500 kilometres (42,500 miles)  tapping into virtually every
  major gas supply basin on the continent. We deliver 20 per cent of the
  natural gas consumed in North America each and every day. TransCanada is the
  third-largest natural gas storage provider on the continent with 380 billion
  cubic feet of capacity. We are Canadas largest private sector power
  generator. Our company has 19 power plants in Canada and the U.S. that
  produce 10,800 megawatts of electricity. We can produce enough power to meet
  the needs of nearly 11 million homes. In the summer of 2010, we broadened our
  asset base to include a very significant entrance into the oil transportation
  business with the start of commercial operations on our Keystone pipeline
  system, delivering a reliable source of crude oil to U.S. refineries. The
  system expanded in 2011 with completion of the Cushing Extension. All are
  long-life assets that are critical to the needs of millions of people who
  rely on us to deliver their energy safely and reliably every day. We remain
  focused on doing the right thing and doing things right as we have done for
  decades to ensure we maintain the trust of the communities where we work. It
  is important we remain grounded in our values of integrity, responsibility,
  innovation and collaboration, as they will continue to be our guide to
  navigate the path forward. The safety of the public, our employees and our
  contractors has been a core value at TransCanada for 60 years. We strive to
  eliminate all incidents that could impact people, the environment or our
  corporate assets through continuous improvement of our health, safety and
  environmental performance. . DeliVering CritiCal energy infrastruCture


A Strong
  FoundAtion iS in PlAce As TransCanada continues to progress its capital
  program, the specific projects that came into service in 2011 include: the
  Keystone Pipeline System Cushing Extension, the Bison and Guadalajara natural
  gas pipelines, extensions and expansions of the Alberta System, the Coolidge
  Generating Station in Arizona and additional phases of the Cartier Wind
  project. These new operating assets are critical North American
  infrastructure and have become an important part of our growing asset base.
  In addition, we continue to focus on enhancing the value of existing assets
  by maximizing revenue and minimizing costs. This means increasing throughput
  on our pipelines, maximizing the availability and output of our power plants
  and minimizing the cost of our operations. These are simple concepts we put into
  practice every day. Incremental earnings from these new assets and improved
  results from our core businesses contributed to a significant year-over-year
  increase in our earnings. For the year ending December 31, 2011, we reported
  comparable earnings of $2.23 per share, which is a 13 per cent increase over
  the $1.97 per share we reported in 2010. Funds generated from operations were
  $3.7 billion, which is a 10 per cent increase over last year, a clear
  indication our strategy is working. . transcanadas capital program is
  delivering results


oil PiPelineS
  Keystone safely delivered over 160 million barrels of oil by the end of 2011


The Keystone
  pipeline system, which began transporting oil to the U.S. Midwest in the
  summer of 2010, achieved a key milestone early in 2011 with the start of
  deliveries to refineries in Cushing, Oklahoma. Along with this
  accomplishment, TransCanada successfully signed contracts for thousands of
  additional barrels from the Bakken fields in Montana and North Dakota and oil
  from Cushing, along with oil flowing from Western Canada through the proposed
  Houston lateral pipeline. These commitments involve an investment of
  approximately US$800 million and will increase the capacity of Keystone XL to
  830,000 barrels per day (bbl/d) and total capacity to approximately 1.4
  million bbl/d. The entire Keystone system has secured long-term, firm
  contracts in excess of 1.1 million bbl/d. Keystone will serve as a growth
  platform to transport more barrels to market. By 2020, oil production in the
  Western Canada Sedimentary Basin is expected to increase by 1.5 million bbl/d
  to more than four million bbl/d. By 2025, total supply is expected to grow by
  another million barrels per day. TransCanada has taken advantage of this
  opportunity as the Keystone system has contracted the lions share of this
  growth over the next four to five years. Keystone XL has the potential to
  move approximately one third of total Canadian exports to the U.S., 10 per
  cent of total U.S. imports and almost 250,000 bbl/d of domestic U.S.-produced
  oil. The regulatory approval process for Keystone XL continued to advance in
  2011 with the release of a Final Environmental Impact Statement in August. It
  concluded the pipeline would have minimal impact on the environment. The over
  three-year review of Keystone XL has become the most detailed and
  comprehensive environmental review ever undertaken for a cross-border
  pipeline. The U.S. Department of State suspended the finalization of the
  review for Keystone XL in November 2011, stating that alternative routes
  needed to be defined that avoided the Nebraska Sandhills. On January 18,
  2012, the State Department denied a Presidential Permit for Keystone XL.
  Facing a 60-day legislative-imposed decision deadline, the Department said it
  did not have sufficient time to obtain the information necessary to assess
  whether the project, in its current state, was in the national interest of
  the United States. TransCanada is working collaboratively with the State of
  Nebraska and Nebraskas Department of Environmental Quality to define a new
  route through the State. Our commitment to the project remains and the
  company will re-apply for a Presidential Permit in 2012. We expect the 10,000
  pages of data and analysis compiled since 2008 would be used in any future
  regulatory review, potentially speeding up final approval. We are focused on
  Keystone XL beginning to ship oil in early 2015. The company continues to
  strongly believe that Keystone XL is in the national interest of the United
  States, as it would allow Americans to move closer toward achieving North
  American energy security while creating thousands of much-needed jobs. .


nAturAl gAS
  PiPelineS North American demand for natural gas is expected to grow by about
  20 billion cubic feet per day (Bcf/d) over the next 15 years largely due to
  an increased demand for power. TransCanada expects both conventional and
  unconventional natural gas will be needed to meet the increase in demand and
  to offset an expected 20 per cent annual decline in existing production. We
  are well positioned to connect all existing sources of supply in North
  America, as well as new sources, to growing markets across the continent. Our
  pipeline network connects into virtually every major natural gas supply basin
  and provides our customers with unparalleled access to premium markets. This
  vast network became even larger early in 2011 with the US$630 million Bison
  pipeline beginning operations. The 487-kilometre (303-mile) natural gas
  pipeline is TransCanadas first line to access gas produced in the U.S. Rocky
  Mountain region. Bison connects to the Northern Border pipeline system and
  provides options to producers in Wyomings Powder River Basin and to
  consumers in the U.S. Midwest. Bison has an initial capacity of 407 million cubic
  feet per day (MMcf/d) and is easily expandable. Construction of the Alberta
  Systems $275 million Horn River natural gas pipeline project began in March
  2011 and is expected to begin shipping gas in the second quarter of 2012.
  TransCanada plans to extend this pipeline by 100 kilometres (62 miles) at a
  cost of $230 million. The extension adds additional initial contractual
  commitments of 100 MMcf/d expected to begin in 2014, with volumes increasing
  to 300 MMcf/d by 2020. The currently contracted volumes for Horn River,
  including the extension, are expected to total 900 MMcf/d by 2020.
  Construction of a $60 million, 24-kilometre (15-mile) extension of the
  Groundbirch pipeline began in August 2011 and is expected to be completed in
  April 2012. Contracts are in place for 250 MMcf/d of natural gas. TransCanada
  continues to develop new natural gas pipeline infrastructure in British
  Columbia and Alberta. Several Our natural gas pipeline network reaches
  virtually every north American supply basin


applications
  have been filed with the National Energy Board (NEB) requesting approval for
  expansions of the Alberta System to accommodate requests to bring additional
  natural gas to market. The company has approvals for $910 million in new
  projects, with $810 million worth of pipeline infrastructure awaiting an NEB
  decision. Ongoing business with Western Canadian producers has resulted in
  contracts from both the Montney and Horn River shale gas formations for 3.4
  Bcf/d from northwestern Alberta and northeastern B.C. by 2014. TransCanadas
  continental reach continued to expand in the summer of 2011 with the
  completion of Mexicos US$360 million Guadalajara pipeline. The entire
  capacity of the 310-kilometre (193-mile) natural gas pipeline is contracted
  with Mexicos state-owned electric company Comisión Federal de Electricidad.
  The Guadalajara project connects to a regasification facility near
  Manzanillo. It has the capacity to transport 500 MMcf/d of natural gas to a
  nearby power plant, along with the ability to deliver 320 MMcf/d to the
  Pemex-owned national pipeline system near Guadalajara. TransCanada continued
  its work in 2011 toward the development of a longer-term plan to ensure there
  is a competitive toll structure for the Canadian Mainline. That work
  culminated in the filing in September of a comprehensive proposal to
  restructure services and tolling on the Mainline. The proposal responded to
  significant changes that have occurred over the last few years in natural gas
  supply, demand and transportation in North America with the advent of U.S.
  shale gas growth. The filing would achieve significantly reduced tolls for
  2012 and 2013 compared to existing levels and is expected to enhance the
  overall competitiveness of Western Canadian gas and the Canadian Mainline. The
  Mainline remains a critical component of the North American gas delivery
  system. Total deliveries averaged 5.2 Bcf/d for 2011, making it the largest
  gas transportation system on the continent. .


energy
  transcanadas energy portfolio is well positioned to prosper in a
  carbon-constrained world


Between 2010
  and 2013, TransCanada will add 2,600 megawatts (MW) of capacity to our energy
  portfolio by investing $5 billion in numerous projects that are expected to
  generate sustainable earnings and cash flow. In May 2011, we added 575 MW of
  capacity with the start of operations at our Coolidge Generating Station in
  Arizona. The US$500 million facility was completed on time and on budget. The
  Arizona-based Salt River Project utility signed a 20-year power purchase
  arrangement (PPA) to buy all of the power produced at the Coolidge facility.
  In Canada, construction continues on the five-stage, 590-MW Cartier Wind
  project in Québec. The 101-MW first phase of the Gros-Morne and 58-MW
  Montagne-Sèche wind farm projects began producing power in November 2011. The
  111-MW 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, which
  is 62 per cent owned by TransCanada. All of the power produced by Cartier
  Wind is sold under a 20-year PPA to Hydro-Québec. The refurbishment of Units
  1 and 2 at the Bruce Power nuclear facility in Ontario continues to progress
  and the two units are now being prepared to begin delivering power to
  Ontarios electrical grid. Unit 2 is expected to begin operations in the
  first quarter of 2012, while Unit 1 is on target to start producing power in
  the third quarter. 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 worlds largest nuclear facility, providing more than 6,200 MW or about
  25 per cent of Ontarios power. This emissions-free power is sold under
  long-term PPAs with the Ontario Power Authority. 2011 ended with the announcement
  that TransCanada is entering the solar power business. The company agreed to
  purchase nine Ontario solar projects with a combined capacity of 86 MW. All
  nine projects in the $470 million deal have 20-year PPAs with the Ontario
  Power Authority. Each of the projects will be purchased after they begin
  producing power and meet certain milestones. TransCanadas energy portfolio
  is well positioned to prosper in an increasingly carbon-constrained world as
  our diverse and growing fuel mix includes 52 per cent natural gas, 23 per
  cent nuclear, 15 per cent coal, five per cent wind and five per cent hydro. .


At TransCanada,
  our reputation matters. We recognize that excellence in stakeholder
  engagement helps deliver value and ensures we do so in a socially and
  environmentally responsible manner. Our four core values of integrity,
  collaboration, responsibility and innovation are at the heart of our
  commitment to stakeholder engagement. These values guide us in our
  interactions with our stakeholders. TransCanada generally defines
  stakeholders as those people or groups who significantly affect, or who may
  be affected by, our business activities. We strive to engage stakeholders
  early and often from project development through to operations and
  decommissioning. Engaging with stakeholders means listening, providing
  accurate information and responding to stakeholder interests in a prompt and
  consistent manner. Our company will be an integral part of hundreds of
  communities across the continent for many years to come. We want to be
  considered a good neighbour from the start of a project until the day we
  reclaim the local environment. When planning a new project, we strive to
  involve those affected as soon as possible. TransCanadas stakeholders are a
  diverse group, including landowners, regulatory officials, Aboriginal
  communities and Native American Tribes, local governments, emergency response
  agencies, and our industry peers. We use many tools to lay out our intentions
  to these stakeholders, gather their comments and seek solutions. We bring our
  respect and a clear sense of our long-term corporate responsibility to these
  important discussions. Typically, this approach works very well. Our vision
  is to be a North American community infrastructure leader by helping build
  healthy, safe and vibrant communities where we live and work. We do this by
  forging meaningful partnerships in the non-profit and voluntary sector, which
  serve as community assets in empowering individuals and building strong
  communities. . Building relAtionShiPS We want to be considered a good
  neighbour from the start of a project until the day we reclaim the local
  environment


By early 2015,
  we anticipate completing the remaining elements of our current capital
  program: Keystone XL, the Bruce re-start, the Cartier Wind project, the
  Canadian Solar power initiative and expansions and extensions to the Alberta
  System. As a result, we expect to generate $6.5 billion of EBITDA (earnings
  before interest, taxes, depreciation and amortization) by 2015  45 per cent
  from our natural gas transmission business, 30 per cent from energy and 25
  per cent from oil pipelines. This is expected to translate into growth in
  funds from operations to $4.5 billion annually. TransCanada has three very
  attractive and growing businesses in which to reinvest its annual cash flow:
  natural gas pipelines and storage, oil pipelines and power generation and
  transmission. Reinvestment will be done in a disciplined fashion and in a way
  that allows us to live within our means in order to deliver predictable and
  stable long-term earnings and cash flow growth. We are well on our way to
  realizing our vision of becoming the leading energy infrastructure company in
  North America. . MAintAining our FinAnciAl Strength & FlexiBility Funds from
  operations are expected to grow to $4.5 billion by 2015


2011 FinAnciAl
  highlightS Net Income Attributable to Common Shares | $1.5 billion or $2.18
  per share Comparable Earnings (1) | $1.6 billion or $2.23 per share
  Comparable Earnings before Interest, Taxes, Depreciation and Amortization (1)
  | $4.8 billion Funds Generated from Operations (1) | $3.7 billion Capital
  Expenditures | $3.3 billion Common Share Dividends Declared | $1.68 per share
  3,663 07 08 09 10 11 07 08 09 10 11 07 08 09 10 11 1,527 07 08 09 10 11 07 08
  09 10 11 07 08 09 10 11 07 08 09 10 11 07 08 09 10 11 07 08 09 10 11 (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 2011
  Annual Report. 07 08 2.23 09 10 11 1,565 4,806 3,274 2.18 1.68 702 44.53
  1,227 1,374 1,223 1,440 1,361 1,325 1,100 1,279 3,941 4,107 4,125 3,919 3,331
  3,080 2,621 3,021 5,036 6,319 5,874 6,363 1.78 2.11 2.31 2.53 1.97 2.03 2.08
  2.25 1.60 1.52 1.36 1.44 691 652 530 570 37.99 36.19 40.54 33.17 Comparable
  Earnings(1) (millions of dollars) Net Income Attributable to Common Shares
  (millions of dollars) Comparable EBITDA(1) (millions of dollars) Funds Generated
  from Operations(1) (millions of dollars) Capital Expenditures and
  Acquisitions (millions of dollars) Comparable Earnings per Share(1) (dollars)
  Net Income per Share  Basic (dollars) Dividends Declared per Share (dollars)
  Common Shares Outstanding  Average (millions of shares) Market Price  Close
  Toronto Stock Exchange (dollars)




|Financial
Highlights |  | 
|-------------------- |  | 

| | Year ended December 31
(millions of dollars)     |  | 2011   |  | 2010   |   | 2009   |   | 2008   |  | 2007  
| | ------------------------------------------------ |  | ------ |  | ------ | - | ------ | - | ------ |  | ------
| |                                                 
| | Income                                           |  |        |  |        |   |        |   |        |  |       
| | Net income attributable to common shares         |  | 1,527  |  | 1,227  |   | 1,374  |   | 1,440  |  | 1,223 
| |                                                 
| | Cash Flow                                        |  |        |  |        |   |        |   |        |  |       
| | Funds generated from operations                  |  | 3,663  |  | 3,331  |   | 3,080  |   | 3,021  |  | 2,621 
| | Decrease/(increase) in operating working capital |  | 310    |  | (249   | ) | (90    | ) | 135    |  | 63    
| |                                                 
| | Net cash provided by operations                  |  | 3,973  |  | 3,082  |   | 2,990  |   | 3,156  |  | 2,684 
| |                                                 
| | Capital expenditures and acquisitions            |  | 3,274  |  | 5,036  |   | 6,319  |   | 6,363  |  | 5,874 
| | Balance Sheet                                    |  |        |  |        |   |        |   |        |  |       
| | Total assets                                     |  | 48,995 |  | 46,794 |   | 43,841 |   | 39,414 |  | 30,330
| | Long-term debt                                   |  | 17,632 |  | 17,028 |   | 16,186 |   | 15,368 |  | 12,377
| | Junior subordinated notes                        |  | 1,009  |  | 985    |   | 1,036  |   | 1,213  |  | 975   
| | Preferred shares                                 |  | 1,224  |  | 1,224  |   | 539    |   |       |  |      
| | Common shareholders' equity                      |  | 16,100 |  | 15,503 |   | 15,220 |   | 12,898 |  | 9,785 
| | Common Share Statistics
Year ended December 31   |  | 2011   |  | 2010   |   | 2009   |   | 2008   |  | 2007  
| |                                                 
| | Net income per common share  basic              |  | $2.18  |  | $1.78  |   | $2.11  |   | $2.53  |  | $2.31 
| |  diluted                                        |  | $2.17  |  | $1.77  |   | $2.11  |   | $2.52  |  | $2.30 
| | Dividends declared per common share              |  | $1.68  |  | $1.60  |   | $1.52  |   | $1.44  |  | $1.36 
| | Common shares outstanding (millions)             |  |        |  |        |   |        |   |        |  |       
| | Average for the year                             |  | 701.6  |  | 690.5  |   | 651.8  |   | 569.6  |  | 529.9 
| | End of year                                      |  | 703.9  |  | 696.2  |   | 684.4  |   | 616.5  |  | 539.8 

TRANSCANADA
CORPORATION1

---





|Chairman's
Message |  | 2011 was a strong year at TransCanada. We continue to experience the financial benefits of bringing $10 billion of assets into service since the spring of 2010. That progress will continue through
2012, with the completion of other major projects such as the re-start of two reactors at the Bruce nuclear facility.
Looking forward, we expect to invest an additional $12 billion in projects by the end of 2014 or early 2015. This will cap one of the largest capital programs in Canadian corporate history. TransCanada is widely recognized as a leader in the
safe and reliable operation of North American energy infrastructure. It is known as a company that delivers on its promises and takes its responsibility toward all stakeholders seriously.
|------------------ |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|----- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|PHOTO |  | Notwithstanding that reputation, in 2011 the company became known by many for something more  the Keystone XL pipeline. Project opponents have used the pipeline as a lightning rod for a debate on society's use of fossil fuels, and
specifically, Alberta's oil sands production. Seeing Keystone XL attacked in the media has been trying for our Board and for all TransCanada employees who take pride in the work they accomplish each and every day. The company has taken every
opportunity to discuss the merits of the project in a factual, professional manner.

Experts forecast oil will be needed for decades and Keystone XL offers Americans an
opportunity to receive a stable, secure supply of oil from domestic U.S. and Canadian production. This project makes sense, it has our full support and we remain confident it will ultimately
be approved.

Our Board continues to be pleased with the transition of leadership at TransCanada from Hal
Kvisle to Russ Girling. Russ's focus has remained on the strategies that he helped develop and have made the company successful in the past. He and the executive team have more than met the challenges
the past year has presented and we expect that sets the stage for a great future.

Interestingly, our Board will also see noticeable transition between now and 2014. Six of our
current directors will reach retirement age and leave the company over that period. The first two such individuals are Wendy Dobson and David O'Brien. Along with my fellow Board members, I would like
to thank them for their many years of dedicated service to the company and our shareholders.

The overall scope of this renewal is unprecedented in TransCanada's history and I believe we
will attract strong, new talent to provide the guidance and leadership necessary to move the company forward. After an extensive search, the Governance Committee nominated Paula Rosput Reynolds and
Richard Waugh to be appointed to the Board.

I am confident Ms. Reynolds and Mr. Waugh, along with TransCanada's
4,400 employees, will continue to rise to the challenges ahead and build future successes for the company, to the benefit of our shareholders, partners and stakeholders.

On behalf of the Board of Directors;

SIG

S. Barry Jackson

2CHAIRMAN'S
MESSAGE

---





|Letter
to Shareholders |  | Building and operating safe and reliable energy infrastructure  it is what we do and we do it well. Millions of people across North America rely on the energy we deliver every day, to heat
their homes, cook their food and fuel their vehicles. We have done this successfully and responsibly for six decades. Our $49 billion of blue chip assets are essential to North Americans and we are well positioned to continue to meet the
continent's growing energy needs for decades to come.
|---------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|----- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|PHOTO |  | In 2011, TransCanada continued to successfully advance many of its strategic initiatives. While we experienced some disappointments, it is clear our strategy is working and we are seeing very tangible results of our
discipline and focus. Our Company delivered a record $4.8 billion of EBITDA(1) (earnings before interest, taxes, depreciation and amortization) in 2011 versus $3.9 billion in 2010. This represents a year-over-year increase of
$865 million. This growth in EBITDA(1) translated into comparable net income of $1.6 billion or $2.23 per share, a 13 per cent increase over 2010 earnings of $1.97 per share.

As a result of visible growth in cash flow and earnings, our Board of Directors again increased our annual dividend on our common shares in February 2012
by eight cents, an increase of five per cent. Since 2000, our dividend has risen steadily from 80 cents per share to $1.76 per share today, an average annual increase of
seven per cent. We understand the value our shareholders place on a strong and growing dividend. Going forward, our goal is to continue to increase dividends in conjunction with sustainable
growth in cash flow and earnings.

I would like to share with you some of the highlights of 2011, some of our challenges and the
bright future we are building for your company. Our base businesses all continued to perform well in 2011 delivering predictable and steady contributions. We captured significant new shale gas supply
in Western Canada, Marcellus in the eastern United States (U.S.) and gas from south central U.S. Our power business performed exceptionally well, primarily in the West, where we were well positioned
to take advantage of tightening reserve margins and rising prices against a backdrop of robust growth in demand.

In February 2011, our Keystone pipeline system began oil deliveries to Cushing,
Oklahoma. Since the start-up of first deliveries to Patoka and Wood River, Illinois in July 2010, Keystone has safely transported over 170 million barrels of Canadian oil to
U.S. markets. TransCanada began recording EBITDA(1) from Keystone in February 2011 and over the 11-month period it contributed nearly $600 million.

(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 2011 Annual Report.

We continued to successfully advance our large capital program in 2011. Over the past
18 months, we have brought into operation $10 billion of new projects. These were largely completed on time, within budget and with minimal work-related injury. The projects include the
first two phases of Keystone, North Central Corridor, Groundbirch, Halton Hills, Coolidge, Kibby, additional phases of Cartier, Bison and Guadalajara.

Doing all of this safely and without injury is an imperative. The safety of our employees,
contractors and the public is our first priority. In this same time period, our employees and contractors worked 25 million hours and we experienced a 20 per cent decline in our
injury frequency rates, which continue to be among the lowest in our industry. While we are proud of this accomplishment, we know that we must continually

LETTER TO
SHAREHOLDERS3

---



improve
our processes and procedures to ensure every employee and contractor goes home safe  every day  period.

We experienced some start-up issues on both the Keystone and Bison pipelines in 2011. Our
teams responded well, confirming the effectiveness of our emergency response capabilities, which worked as planned, and the capacity of the company to ensure public safety, protect the environment,
repair facilities and return to service safely  delivering the energy people need. This proven capability is truly a competitive advantage in a business that is
increasingly in the public eye with ever rising standards of conduct. We embrace the challenge of continually improving our performance.

The Canadian Mainline remains a critical component of the North American natural gas pipeline
network. That being said, the Mainline is being used differently as a result of the significant changes that have occurred in natural gas supply, demand and transportation in North America. In order
to address those changes, we filed a comprehensive proposal with our regulator in 2011 to significantly reduce tolls and restructure services in a way that will enhance the competitiveness of the
Mainline and the Western Canada Sedimentary Basin.

On Keystone XL, we remain focused on gaining approval for the US$7 billion project and
proceeding with construction. A Final Environmental Impact Statement (FEIS) was issued in August 2011 that concluded the pipeline would have minimal impact on the environment.

On January 18, 2012, the State Department denied a Presidential Permit for Keystone
XL. The decision was not based on the merits of the pipeline but rather that legislation introduced by Congress in December 2011, effectively to accelerate approval, did not allow for
sufficient time to
complete the required review. The State Department indicated that TransCanada can re-apply for a permit.

We are obviously very disappointed with the decision; however, TransCanada remains fully
committed to the construction of Keystone XL. Plans are underway on a number of fronts to largely maintain the construction schedule. We will re-apply for a Presidential Permit and expect,
given the already completed environmental work and supportive FEIS, a new application would be processed in an expedited manner to allow for an in-service date of late
2014/early 2015.

Shipper support for the project remains strong. In 2011, we signed long-term
shipping contracts on Keystone XL to transport U.S.-produced oil to market from the Bakken formation in Montana and North Dakota and from Cushing, Oklahoma. In addition, we signed sufficient long-term
contracts to support a new lateral pipeline to the large refining hub in Houston, Texas. These projects amount to a US$800 million incremental investment and increase the capacity of Keystone
XL to 830,000 barrels per day. Today, the vast majority of Keystone's overall capacity is reserved with long-term, firm contracts  clear
evidence of the market need for the pipeline.

In 2011, we made great progress on the Bruce Power refurbishment project with refuelling of
both units and beginning the commissioning phase. Our current forecast is for Unit 2 to be fully operational in first quarter 2012 and Unit 1 fully operational in third quarter 2012. When back
in service, these two units will deliver 1,500 MW of emissionless energy for the residents of Ontario for decades to come and produce very attractive and stable returns for our shareholders.

We took our first step into solar generation in 2011, with the $470 million
acquisition of nine projects. This is a fast growing segment of the power market and I would expect several new opportunities to present themselves in the coming years.

4LETTER TO
SHAREHOLDERS

---



As we bring an additional $12 billion of contracted assets into service over the next
three years, we are positioned to deliver substantial growth in cash flow, earnings and dividends through 2015. Over the longer term, there will be significant opportunities to reinvest in our core
businesses of natural gas pipelines and storage, oil pipelines and power infrastructure.

The International Energy Agency predicts investment in energy infrastructure of over $6
trillion will be needed in North America between 2010 and 2035. More specifically, an investment of about $3 trillion in power, $2 trillion in natural gas and $1.5 trillion in oil
is required. That infrastructure is needed to fuel a growing economy and to replace aging assets with new and safe oil and gas pipelines and cleaner, more efficient power plants.

Today, we have a $50 billion portfolio of energy infrastructure projects being
evaluated by a very capable business development team. They are focused on meeting the need to move shale and conventional gas within the continent and from frontier regions; attach growing crude oil
production to key refining centres; and develop new power generation as the North American market revitalizes its aging infrastructure and evolves to a less carbon-intensive mix. These opportunities
mesh extremely well with TransCanada's strategy, growth aspirations, existing presence and deep organizational capabilities.

While we don't expect to capture all of these opportunities, I am confident that these
projects, combined with appropriate acquisitions, will provide us with the opportunity to continue to reinvest our substantial discretionary cash flow and grow the company for decades to come.

We will continue to face challenges  that is nothing
new. Our 4,400 very highly skilled employees are experts in turning challenge into opportunity. I am extremely proud of their achievements in 2011 and the pride and care they take in operating
this company  they are the reason for our success. I recognize that being in the media spotlight placed an additional burden on all of our employees this year
and again I am proud of their value-driven, professional management of all issues that came their way. I thank them for their efforts this year and congratulate them on an outstanding job.

Going forward, I am confident in our strategy, our people and our assets. We will realize our
vision of being the leading North American energy infrastructure company. In the process, we will continue to grow cash flow, earnings and dividends and build long-term sustainable value
for our shareholders. I thank you for your continued support.

SIG

Russell K. GirlingPresident and Chief Executive Officer

LETTER TO
SHAREHOLDERS5

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TABLE OF CONTENTS

|                                              
|----------------------------------------------
|TRANSCANADA OVERVIEW                          
|TRANSCANADA'S STRATEGY                        
|                                              
|CONSOLIDATED FINANCIAL REVIEW                 
|                                              
|                                              
|                                              
|                                              
|                                              
|FORWARD-LOOKING INFORMATION                   
|NON-GAAP MEASURES                             
|OUTLOOK                                       
|                                              
|NATURAL GAS PIPELINES                         
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|OIL PIPELINES                                 
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|ENERGY                                        
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|                                              
|CORPORATE                                     
|OTHER INCOME STATEMENT ITEMS                  
|                                              
|LIQUIDITY AND CAPITAL RESOURCES               
|                                              
|                                              
|                                              
|                                              
|CONTRACTUAL OBLIGATIONS                       
|                                              
|RISK MANAGEMENT AND FINANCIAL INSTRUMENTS     
|                                              
|                                              
|                                              
|CONTROLS AND PROCEDURES                       
|CRITICAL ACCOUNTING POLICIES AND ESTIMATES    
|ACCOUNTING CHANGES                            
|SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
|FOURTH QUARTER 2011 HIGHLIGHTS                
|SHARE INFORMATION                             
|OTHER INFORMATION                             
|GLOSSARY OF TERMS                             

6MANAGEMENT'S DISCUSSION AND ANALYSIS

---





This Management's Discussion and Analysis (MD&A) dated February 13, 2012 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, 2011 which are prepared in accordance with
Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook (CGAAP). This MD&A covers TransCanada's financial
position and operations as at and for the year ended December 31, 2011. "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 2011
Annual Report.

TRANSCANADA OVERVIEW

With more than 60 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.

Today,
TransCanada is:

In
pursuing its vision to be the leading energy infrastructure company in North America, TransCanada continually strives to execute a large portfolio of attractive growth
projects. Each of these new projects are large scale, long life assets supported by strong business fundamentals and long-term contracts that provide attractive and sustainable returns to
shareholders over a long-term time horizon.

With
assets of approximately $49 billion and a substantial growth portfolio, TransCanada believes it is well positioned to build on its track record of strong and
sustainable earnings, cash flow and dividends. Since the spring of 2010, TransCanada has brought $10 billion of growth projects in service and is positioned to complete another
$12 billion of new projects by the end of 2014.

TransCanada's 2011 Key Developments

The Company advanced its significant entry into the oil pipelines transmission business:

MANAGEMENT'S DISCUSSION AND ANALYSIS7

---





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:

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

The
following are other key developments in Energy in 2012.

8MANAGEMENT'S DISCUSSION AND ANALYSIS

---



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, a master 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 57,000 km (35,500 miles) of wholly owned natural gas pipelines, and more than
11,500 km (7,000 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 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 include regulated natural gas storage facilities in Michigan with a total capacity of 250 Bcf.

TransCanada
is also pursuing additional natural gas pipeline projects to diversify both the supply and market sides of this business and add incremental value to existing
assets. Key areas of focus include greenfield development opportunities that connect TransCanada's natural gas pipelines to emerging Canadian and U.S. shale gas and other supplies and that play
a critical role in satisfying increased natural gas demand in North America especially for power generation. TransCanada continues to advance 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

The Company's Keystone crude oil pipeline system currently operates on the Wood River/Patoka and the Cushing Extension sections and has a nominal design capacity of
591,000 barrels per day (bbl/d). 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, combined with growing demand for secure, reliable sources of energy, TransCanada has identified additional opportunities to develop new oil pipeline capacity.

The
Company plans to expand and extend the existing system through Keystone XL which includes the construction of a new crude oil pipeline from Cushing, Oklahoma to
the U.S. Gulf Coast, the addition of operational storage facilities at Hardisty, Alberta and the construction of a new crude oil pipeline from Hardisty, Alberta to Steele City, Nebraska. The
expanded oil pipeline system is collectively referred to as Keystone. The completion of Keystone XL is expected to increase total system capacity to approximately
1.4 million bbl/d.

Energy

TransCanada's Energy segment 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, wind and solar assets. TransCanada's power business is primarily located in Canada in Alberta, Ontario and Québec, in the northeastern U.S. mainly in the
New England states and New York, and in Arizona. The assets are largely underpinned by long-term tolling contracts or represent low-cost baseload generation and
essential capacity.

MANAGEMENT'S DISCUSSION AND ANALYSIS9

---



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.

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 the Natural Gas Pipelines segment,
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:

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

Commercially develop and physically execute new asset investment programs

Cultivate a focused portfolio of high-quality development options

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 existing assets and commercial positions. The Company's pipeline
assets include large-scale natural gas and crude oil pipelines that connect long-life supply basins with stable and growing markets, generating predictable and sustainable cash flows and
earnings. In Energy, highly efficient, large-scale power generation facilities supply power 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, hydro-power, and solar generating facilities demonstrate the Company's commitment to
clean, sustainable energy. Long-life infrastructure assets and long-term commercial arrangements are expected to 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 influence the quality of projects,
notably the current $12 billion capital program. These projects are expected to 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 set-up and delivery. It also requires expert regulatory, legal and financing support, as well
as outstanding operational set-up. TransCanada's model for managing construction risks and maximizing capital productivity helps ensure disciplined attention to quality, cost and schedule
that produces superior service for its customers and quality returns to shareholders. Many of these functional capabilities also create the basis for successful acquisition and integration of new
energy and pipeline facilities, an important dimension of the 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 and Northern Canada, as well as 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 in
Montana and North Dakota, to preferred North American markets. The Company will continue to assess energy infrastructure acquisition opportunities that complement its existing pipeline network and
provide access to new supply and market regions. In Energy, 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 reputable and creditworthy counterparties. Selected opportunities will be advanced to full development and construction when market conditions
are appropriate and project risks are manageable.

10MANAGEMENT'S DISCUSSION AND ANALYSIS

---



Maximize TransCanada's competitive strengths

TransCanada continues to build competitive strength in areas that directly drive long-term shareholder value. At the core of the Company's competitive advantage are
powerful capabilities in strategy development, implementation, and continuous improvement. The Company relies on its scale, presence, operating capabilities, leadership and teams to compete
effectively and deliver outstanding value to customers. A disciplined approach to capital investment combined with access to sizeable amounts of competitive-cost capital allows the Company
to create significant 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. TransCanada values its reputation for consistent financial performance and long-term financial stability. The Company clearly
communicates its financial performance to equity and debt investors, providing insight into both value upside and business risks. We work to sustain the trust and support of our long-term
investors and to attract new investors who see long-term value in our disciplined approach to the energy infrastructure business. The Company continues to identify and build on all aspects
of competitive strength.

MANAGEMENT'S DISCUSSION AND ANALYSIS11

---





CONSOLIDATED FINANCIAL REVIEW

---

SELECTED THREE-YEAR CONSOLIDATED FINANCIAL DATA

|(millions of dollars except per share amounts)   |                                 | 2011   |       | 2010   |       | 2009   |      
|------------------------------------------------ | ------------------------------- | ------ | ----- | ------ | ----- | ------ | -----
|                                                 |                                
|Income Statement                                 |                                 |        |       |        |       |        |      
|Revenues                                         |                                 | 9,139  |       | 8,064  |       | 8,181  |      
|Comparable EBITDA(1)                             |                                 | 4,806  |       | 3,941  |       | 4,107  |      
|Net Income Attributable to Common Shares         |                                 | 1,527  |       | 1,227  |       | 1,374  |      
|Comparable Earnings(1)                           |                                 | 1,565  |       | 1,361  |       | 1,325  |      
|Per Share Data                                   |                                 |        |       |        |       |        |      
|Net Income per Common Share                      |                                 |        |       |        |       |        |      
|                                                 | Basic                           |        | $2.18 |        | $1.78 |        | $2.11
|                                                 | Diluted                         |        | $2.17 |        | $1.77 |        | $2.11
|Comparable Earnings per Common Share(1)          |                                 | $2.23  |       | $1.97  |       | $2.03  |      
|Dividends Declared                               |                                 |        |       |        |       |        |      
|                                                 | Per Common Share                |        | $1.68 |        | $1.60 |        | $1.52
|                                                 | Per Series 1 Preferred Share(2) |        | $1.15 |        | $1.15 |        | $0.29
|                                                 | Per Series 3 Preferred Share(2) |        | $1.00 |        | $0.80 |        |     
|                                                 | Per Series 5 Preferred Share(2) |        | $1.10 |        | $0.65 |        |     
|Cash Flows                                       |                                 |        |       |        |       |        |      
|Funds Generated from Operations(1)               |                                 | 3,663  |       | 3,331  |       | 3,080  |      
|Decrease/(Increase) in Operating Working Capital |                                 | 310    |       | (249   | )     | (90    | )    
|                                                 |                                
|Net Cash Provided by Operations                  |                                 | 3,973  |       | 3,082  |       | 2,990  |      
|                                                 |                                
|Capital Expenditures                             |                                 | 3,274  |       | 5,036  |       | 5,417  |      
|Acquisitions, Net of Cash Acquired               |                                 |       |       |       |       | 902    |      
|Balance Sheet                                    |                                 |        |       |        |       |        |      
|Total Assets                                     |                                 | 48,995 |       | 46,794 |       | 43,841 |      
|Total Long-Term Liabilities                      |                                 | 24,326 |       | 23,220 |       | 21,959 |      
|                                                 |                                

12MANAGEMENT'S DISCUSSION AND ANALYSIS

---



HIGHLIGHTS

---

Earnings

Cash Flow

Balance Sheet

Dividends

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 ANALYSIS13

---





---

Reconciliation of Non-GAAP Measures

|Year ended December 31, 2011(millions of dollars)    |                               | Natural Gas
Pipelines |   | Oil Pipelines |   | Energy |   | Corporate |   | Total  |    
|---------------------------------------------------- | ----------------------------- | --------------------- | - | ------------- | - | ------ | - | --------- | - | ------ | ---
|                                                     |                              
|Comparable EBITDA                                    |                               | 2,967                 |   | 587           |   | 1,338  |   | (86       | ) | 4,806  |    
|Depreciation and amortization                        |                               | (986                  | ) | (130          | ) | (398   | ) | (14       | ) | (1,528 | )  
|                                                     |                              
|Comparable EBIT                                      |                               | 1,981                 |   | 457           |   | 940    |   | (100      | ) | 3,278  |    
|                                                     |                               |                       |  
|Other Income Statement Items                         |                               |                       |   |               |   |        |   |           |   |        |    
|Comparable interest expense                          |                               |                       |   |               |   |        |   |           |   | (939   | )  
|Interest expense of joint ventures                   |                               |                       |   |               |   |        |   |           |   | (55    | )  
|Comparable interest income and other                 |                               |                       |   |               |   |        |   | 60        |  
|Comparable income taxes                              |                               |                       |   |               |   |        |   |           |   | (595   | )  
|Net income attributable to non-controlling interests |                               |                       |   |               |   |        |   |           |   | (129   | )  
|Preferred share dividends                            |                               |                       |   |               |   |        |   |           |   | (55    | )  
|                                                     |                              
|Comparable Earnings                                  |                               |                       |   |               |   |        |   |           |   | 1,565  |    
|Specific items (net of tax):                         |                               |                       |   |               |   |        |   |           |   |        |    
|                                                     | Risk management activities(1) |                       |   |               |   |        |   |           |   |        | (38
|                                                     |                              
|Net Income Attributable to Common Shares             |                               |                       |   |               |   |        |   |           |   | 1,527  |    
|                                                     |                              

|
|

|Year ended December 31, 2011(millions of dollars except per share amounts) |                               |  |  |  |  | 2011 | 
|-------------------------------------------------------------------------- | ----------------------------- |  |  |  |  | ---- | 
|                                                                           |                              
|Comparable Interest Expense                                                |                               |  |  |  |  |      | 
|Specific item:                                                             |                               |  |  |  |  |      | 
|                                                                           | Risk management activities(1) |  |  |  |  |      | 
|                                                                           |                              
|Interest Expense                                                           |                               |  |  |  |  |      | 
|                                                                           |                              
|Comparable Interest Income and Other                                       |                               |  |  |  |  |      | 
|Specific item:                                                             |                               |  |  |  |  |      | 
|                                                                           | Risk management activities(1) |  |  |  |  |      | 
|                                                                           |                              
|Interest Income and Other                                                  |                               |  |  |  |  |      | 
|                                                                           |                              
|Comparable Income Taxes                                                    |                               |  |  |  |  |      | 
|Specific item:                                                             |                               |  |  |  |  |      | 
|                                                                           | Risk management activities(1) |  |  |  |  |      | 
|                                                                           |                              
|Income Taxes Expense                                                       |                               |  |  |  |  |      | 
|                                                                           |                              
|Comparable Earnings per Common Share                                       |                               |  |  |  |  |      | 
|Specific item (net of tax):                                                |                               |  |  |  |  |      | 
|                                                                           | Risk management activities(1) |  |  |  |  |      | 
|                                                                           |                              
|Net Income per Common Share                                                |                               |  |  |  |  |      | 
|                                                                           |                              

14MANAGEMENT'S DISCUSSION AND ANALYSIS

---



---

Reconciliation of Non-GAAP Measures

|Year ended December 31, 2010 (millions of dollars)   |                               | Natural Gas
Pipelines |   | Oil Pipelines |  | Energy |   | Corporate |   | Total  |     
|---------------------------------------------------- | ----------------------------- | --------------------- | - | ------------- |  | ------ | - | --------- | - | ------ | ----
|                                                     |                              
|Comparable EBITDA                                    |                               | 2,915                 |   |              |  | 1,125  |   | (99       | ) | 3,941  |     
|Depreciation and amortization                        |                               | (977                  | ) |              |  | (377   | ) |          |   | (1,354 | )   
|                                                     |                              
|Comparable EBIT                                      |                               | 1,938                 |   |              |  | 748    |   | (99       | ) | 2,587  |     
|                                                     |                               |                       |  
|Other Income Statement Items                         |                               |                       |   |               |  |        |   |           |   |        |     
|Comparable interest expense                          |                               |                       |   |               |  |        |   |           |   | (701   | )   
|Interest expense of joint ventures                   |                               |                       |   |               |  |        |   |           |   | (59    | )   
|Comparable interest income and other                 |                               |                       |   |               |  |        |   | 94        |  
|Comparable income taxes                              |                               |                       |   |               |  |        |   |           |   | (400   | )   
|Net income attributable to non-controlling interests |                               |                       |   |               |  |        |   |           |   | (115   | )   
|Preferred share dividends                            |                               |                       |   |               |  |        |   |           |   | (45    | )   
|                                                     |                              
|Comparable Earnings                                  |                               |                       |   |               |  |        |   |           |   | 1,361  |     
|Specific items (net of tax):                         |                               |                       |   |               |  |        |   |           |   |        |     
|                                                     | Valuation provision for MGP   |                       |   |               |  |        |   |           |   |        | (127
|                                                     | Risk management activities(1) |                       |   |               |  |        |   |           |   |        | (7  
|                                                     |                              
|Net Income Attributable to Common Shares             |                               |                       |   |               |  |        |   | 1,227     |  
|                                                     |                              

|
|

|Year ended December 31, 2010(millions of dollars except per share amounts) |                               |  |  |  |  | 2010 | 
|-------------------------------------------------------------------------- | ----------------------------- |  |  |  |  | ---- | 
|                                                                           |                              
|Comparable Income Taxes                                                    |                               |  |  |  |  |      | 
|Specific items:                                                            |                               |  |  |  |  |      | 
|                                                                           | Valuation provision for MGP   |  |  |  |  |      | 
|                                                                           | Risk management activities(1) |  |  |  |  |      | 
|                                                                           |                              
|Income Taxes Expense                                                       |                               |  |  |  |  |      | 
|                                                                           |                              
|Comparable Earnings per Common Share                                       |                               |  |  |  |  |      | 
|Specific items:                                                            |                               |  |  |  |  |      | 
|                                                                           | Valuation provision for MGP   |  |  |  |  |      | 
|                                                                           | Risk management activities(1) |  |  |  |  |      | 
|                                                                           |                              
|Net Income per Common Share                                                |                               |  |  |  |  |      | 
|                                                                           |                              

MANAGEMENT'S DISCUSSION AND ANALYSIS15

---





---

Reconciliation of Non-GAAP Measures

|Year ended December 31, 2009 (millions of dollars)   |                                                         | Natural Gas
Pipelines |   | Oil Pipelines |  | Energy |   | Corporate |   | Total  |   
|---------------------------------------------------- | ------------------------------------------------------- | --------------------- | - | ------------- |  | ------ | - | --------- | - | ------ | --
|                                                     |                                                        
|Comparable EBITDA                                    |                                                         | 3,093                 |   |              |  | 1,131  |   | (117      | ) | 4,107  |   
|Depreciation and amortization                        |                                                         | (1,030                | ) |              |  | (347   | ) |          |   | (1,377 | ) 
|                                                     |                                                        
|Comparable EBIT                                      |                                                         | 2,063                 |   |              |  | 784    |   | (117      | ) | 2,730  |   
|                                                     |                                                         |                       |  
|Other Income Statement Items                         |                                                         |                       |   |               |  |        |   |           |   |        |   
|Comparable interest expense                          |                                                         |                       |   |               |  |        |   |           |   | (954   | ) 
|Interest expense of joint ventures                   |                                                         |                       |   |               |  |        |   |           |   | (64    | ) 
|Comparable interest income and other                 |                                                         |                       |   |               |  |        |   |           |   | 121    |   
|Comparable income taxes                              |                                                         |                       |   |               |  |        |   |           |   | (406   | ) 
|Net income attributable to non-controlling interests |                                                         |                       |   |               |  |        |   |           |   | (96    | ) 
|Preferred share dividends                            |                                                         |                       |   |               |  |        |   |           |   | (6     | ) 
|                                                     |                                                        
|Comparable Earnings                                  |                                                         |                       |   |               |  |        |   |           |   | 1,325  |   
|Specific items (net of tax):                         |                                                         |                       |   |               |  |        |   |           |   |        |   
|                                                     | Dilution gain from reduced interest in TC PipeLines, LP |                       |   |               |  |        |   |           |   |        | 18
|                                                     | Risk management activities(1)                           |                       |   |               |  |        |   |           |   |        | 1 
|                                                     | Income tax adjustments                                  |                       |   |               |  |        |   |           |   |        | 30
|                                                     |                                                        
|Net Income Attributable to Common Shares             |                                                         |                       |   |               |  |        |   |           |   | 1,374  |   
|                                                     |                                                        

|Year ended December 31, 2009(millions of dollars except per share amounts) |                                                         |  |  |  |  |  |  | 2009  | 
|-------------------------------------------------------------------------- | ------------------------------------------------------- |  |  |  |  |  |  | ----- | 
|                                                                           |                                                        
|Comparable Income Taxes                                                    |                                                         |  |  |  |  |  |  |       | 
|Specific items:                                                            |                                                         |  |  |  |  |  |  |       | 
|                                                                           | Dilution gain from reduced interest in TC PipeLines, LP |  |  |  |  |  |  |       | 
|                                                                           | Income tax adjustments                                  |  |  |  |  |  |  |       | 
|                                                                           |                                                        
|Income Taxes Expense                                                       |                                                         |  |  |  |  |  |  |       | 
|                                                                           |                                                        
|Comparable Earnings per Common Share                                       |                                                         |  |  |  |  |  |  | $2.03 | 
|Specific items:                                                            |                                                         |  |  |  |  |  |  |       | 
|                                                                           | Dilution gain from reduced interest in TC PipeLines, LP |  |  |  |  |  |  |       | 
|                                                                           | Risk management activities(1)                           |  |  |  |  |  |  |       | 
|                                                                           | Income tax adjustments                                  |  |  |  |  |  |  |       | 
|                                                                           |                                                        
|Net Income per Common Share                                                |                                                         |  |  |  |  |  |  |       | 
|                                                                           |                                                        

| | (1) For the year ended(millions of dollars) |                                                           | 2011 |     | 2010 |     | 2009
| | ------------------------------------------- | --------------------------------------------------------- | ---- | --- | ---- | --- | ----
|
| | Risk Management Activities Gains/(Losses):  |                                                           |      |     |      |     |     
| |                                             | U.S. Power derivatives                                    |      | (48 | )    | 2   |     
| |                                             | Canadian Power derivatives                                |      | (3  | )    |    |     
| |                                             | Natural Gas Storage proprietary inventory and derivatives |      | (6  | )    | (10 | )   
| |                                             | Interest rate derivatives                                 |      | 2   |      |    |     
| |                                             | Foreign exchange derivatives                              |      | (5  | )    |    |     
| |                                             | Income taxes attributable to risk management activities   |      | 22  |      | 1   |     
|
| | Risk Management Activities                  |                                                           | (38  | )   | (7   | )   | 1   
|

16MANAGEMENT'S DISCUSSION AND ANALYSIS

---



RESULTS OF OPERATIONS

TransCanada had Net Income Attributable to Common Shares of $1,527 million or $2.18 per share in 2011 compared to $1,227 million or $1.78 per share and
$1,374 million or $2.11 per share in 2010 and 2009, respectively.

Comparable
Earnings in 2011, 2010 and 2009 were $1,565 million or $2.23 per share, $1,361 million or $1.97 per share and $1,325 million or $2.03 per
share, respectively. Comparable Earnings in 2011 excluded $38 million of net unrealized after-tax losses ($60 million pre-tax) resulting from changes in the fair
value of certain risk management activities.

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 Mackenzie Gas Project (MGP) and $7 million of net unrealized after-tax losses ($8 million pre-tax) resulting from changes in the fair
value of certain risk management activities.

Comparable
Earnings in 2009 excluded $30 million of favourable income tax adjustments arising from a reduction in the Province of Ontario's corporate income tax
rates, an $18 million after-tax ($29 million pre-tax) dilution gain resulting from TransCanada's reduced interest in TC PipeLines, LP following a public
offering of TC PipeLines, LP common units in fourth quarter 2009 and a $1 million net unrealized after-tax gain ($1 million pre-tax) resulting from changes
in the fair value of certain risk management activities.

Comparable
Earnings increased $204 million or $0.26 per share in 2011 compared to 2010 and included the following:



Comparable
Earnings increased $36 million and decreased $0.06 per share in 2010 compared to 2009. The increase in Comparable Earnings was primarily due to increased
capitalized interest relating to Keystone and other capital projects. This increase was partially offset by decreased EBIT from Natural Gas Pipelines and Energy as discussed later. The decrease in
Comparable Earnings on a per share basis reflected the issuance of 58.4 million common shares in second quarter 2009 and common shares issued in 2010 and 2009 under the Company's DRP.

On
a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. operations is significantly offset by other
U.S. dollar-denominated items as set out in the following table. The resultant pre-tax net exposure is managed using derivatives, further reducing the Company's exposure to changes
in Canadian-U.S. foreign exchange rates. The

MANAGEMENT'S DISCUSSION AND ANALYSIS17

---



average
exchange rate to convert a U.S. dollar to a Canadian dollar for the year ended December 31, 2011 was 0.99 (2010 1.03;
2009  1.14).

---

Summary of Significant U.S. Dollar-Denominated Amounts

|Year ended December 31(millions of dollars)        |  | 2011 |   | 2010 |   | 2009 |  
|-------------------------------------------------- |  | ---- | - | ---- | - | ---- | -
|                                                   | 
|U.S. Natural Gas Pipelines Comparable EBIT(1)      |  | 786  |   | 710  |   | 682  |  
|U.S. Oil Pipelines Comparable EBIT(1)              |  | 301  |   |     |   |     |  
|U.S. Power Comparable EBIT(1)                      |  | 164  |   | 187  |   | 78   |  
|Interest on U.S. dollar-denominated long-term debt |  | (734 | ) | (680 | ) | (645 | )
|Capitalized interest on U.S. capital expenditures  |  | 116  |   | 290  |   | 123  |  
|U.S. non-controlling interests and other           |  | (192 | ) | (164 | ) | (132 | )
|                                                   | 
|                                                   |  | 441  |   | 343  |   | 106  |  
|                                                   | 

FORWARD-LOOKING INFORMATION

This MD&A contains 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", "intend", "target", "plan" 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 plans and financial outlook. Forward-looking statements in this document may include, but are not limited to, statements regarding:



These
forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and as such are not
guarantees of future performance. By their nature, forward-looking statements are subject to various assumptions, risks and uncertainties which could cause TransCanada's actual results and
achievements to differ materially from the anticipated results or expectations expressed or implied in such statements.

Key
assumptions on which TransCanada's forward-looking statements are based include, but are not limited to, assumptions about:



18MANAGEMENT'S DISCUSSION AND ANALYSIS

---





The
risks and uncertainties that could cause actual results or events to differ materially from current expectations include, but are not limited to:



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 against placing undue reliance on 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 publicly update or revise any forward-looking information in
this MD&A or otherwise, whether as a result of new information, future events or otherwise, except as required by law.

NON-GAAP MEASURES

TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, EBITDA, Comparable EBITDA, EBIT, Comparable EBIT, Comparable Interest Expense and Comparable
Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this MD&A. These measures do not have any standardized meaning as prescribed by CGAAP. They are, therefore,
considered to be non-GAAP measures and may not be comparable to similar

MANAGEMENT'S DISCUSSION AND ANALYSIS19

---



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, net income attributable to 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, net income attributable to non-controlling interests and preferred share dividends.

Comparable
Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other and Comparable Income Taxes comprise Net Income
Applicable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other and Income Taxes, respectively, and are adjusted for specific items that are significant but are not reflective
of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in
calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities,
income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.

The
Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing derivatives. The risk management
activities which TransCanada excludes from Comparable Earnings provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their
fair values are recorded in Net Income each year. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to
be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of
Comparable Earnings.

The
Reconciliation of Non-GAAP Measures table in this MD&A presents a reconciliation of these non-GAAP measures to Net Income Attributable to Common
Shares. Comparable
Earnings per Common 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 its core strengths in its pipelines and energy businesses in North America. In 2012 and beyond, TransCanada expects
that 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 current
$12 billion capital expenditure program, which includes Keystone XL and the Bruce Power restarts, 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.

TransCanada
expects a positive impact on its 2012 earnings from assets that were placed in service in 2011 such as the Guadalajara natural gas pipeline, the Coolidge power
facility and two Cartier Wind farm projects, from Keystone's Wood River/Patoka and Cushing Extension sections that began recording earnings in 2011, and from assets that are

20MANAGEMENT'S DISCUSSION AND ANALYSIS

---



expected
to be placed in service in 2012, such as Bruce Power Units 1 and 2. TransCanada expects that as these assets are placed in service, its consolidated earnings for the year will be somewhat
offset by a corresponding reduction in capitalized interest.

Natural
Gas Pipelines' EBIT in 2012 will be affected by decisions made by applicable regulatory authorities, and the timing thereof, including the Canadian Mainline 2012
Tolls Application and Restructuring Proposal (Restructuring Proposal), as well as the establishment and expiry of long-term contracts, other variances in throughput volume, and rate
settlements on its U.S. pipelines. Absent an NEB decision in 2012 with respect to Canadian Mainline 2012 tolls, EBIT from the Canadian Mainline will reflect the last approved rate of return on
common equity (ROE) of 8.08 per cent on deemed common equity of 40 per cent, and will exclude incentive earnings that have enhanced Canadian Mainline's earnings in
recent years.

Oil
Pipelines EBIT in 2012 is expected to be higher than in 2011, primarily due to the impact of a full year of earnings being recorded on the Wood River/Patoka and Cushing
Extension sections of Keystone compared to eleven months in 2011.

Energy's
EBIT in 2012 is expected to be positively affected by assets that were placed in service during 2011 and assets that are expected to be placed in service in 2012.
Energy's EBIT in 2012 could also be affected by the uncertainty and ultimate resolution of the capacity pricing issues in New York and outcome of the Sundance A PPA arbitration. 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 fluctuations in commodity prices.

TransCanada's
earnings from its Natural Gas Pipelines, Oil Pipelines and Energy businesses in the U.S. 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 will be partially offset by corresponding 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 2012 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 ANALYSIS21

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GRAPHIC

NATURAL GAS PIPELINES

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

CANADIAN MAINLINEThe 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 SYSTEMThe Alberta System is a 24,373 km (15,145 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.

ANRANR is a 16,656 km (10,350 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.

22MANAGEMENT'S DISCUSSION AND ANALYSIS

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GTNOwned 75 per cent by TransCanada and 25 per cent by TC PipeLines, LP, 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. TransCanada operates GTN and effectively owns 83.3 per cent of the system through the combination of its direct ownership interest and its
33.3 per cent interest in TC PipeLines, LP.

FOOTHILLSFoothills 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.

BISONOwned 75 per cent by TransCanada and 25 per cent by TC PipeLines, LP, 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. TransCanada
operates Bison and effectively owns 83.3 per cent of the system through the combination of its direct ownership interest and its 33.3 per cent interest in TC
PipeLines, LP.

GUADALAJARAGuadalajara is a 310 km (193 miles) natural gas pipeline from Manzanillo to Guadalajara in Mexico.

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

NORTH BAJAOwned 100 per cent by TC 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 33.3 per cent of the system through its 33.3 per cent interest in TC PipeLines, LP.

TUSCARORAOwned 100 per cent by TC 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
33.3 per cent of the system through its 33.3 per cent interest in TC PipeLines, LP.

NORTHERN BORDEROwned 50 per cent by TC PipeLines, LP, Northern Border is a 2,265 km (1,407 miles) natural
gas transmission system serving the U.S. Midwest. TransCanada operates Northern Border and effectively owns 16.7 per cent of the system through its 33.3 per cent
interest in TC PipeLines, LP.

GREAT LAKESOwned 53.6 per cent by TransCanada and 46.4 per cent by TC 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 69.0 per cent of the system through the combination of its direct ownership interest and its 33.3 per cent interest in TC PipeLines, LP.

IROQUOISOwned 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.

TQMOwned 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.

PORTLANDOwned 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.

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

MANAGEMENT'S DISCUSSION AND ANALYSIS23

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GAS PACIFICO/INNERGYOwned 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.

ALASKA PIPELINE PROJECTThe Alaska Pipeline Project is a proposed natural gas pipeline and a proposed treatment plant. The pipeline would
extend 2,737 km (1,700 miles) from the treatment plant at Prudhoe Bay, Alaska to Alberta. TransCanada also commenced initial discussions with Alaska North Slope producers regarding an
alternative pipeline route, the LNG option, that would extend from Prudhoe Bay to LNG facilities, to be built by third parties, located in south-central Alaska. TransCanada has entered into an
agreement with ExxonMobil to jointly advance these projects.

MACKENZIE GAS PROJECTThe 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.

NATURAL GAS PIPELINES  HIGHLIGHTS

24MANAGEMENT'S DISCUSSION AND ANALYSIS

---



---

NATURAL GAS PIPELINES  RESULTS

|Year ended December 31(millions of dollars)                                  |                                                             | 2011  |   | 2010  |      | 2009   |   
|---------------------------------------------------------------------------- | ----------------------------------------------------------- | ----- | - | ----- | ---- | ------ | --
|                                                                             |                                                            
|Canadian Natural Gas Pipelines                                               |                                                             |       |   |       |      |        |   
|Canadian Mainline                                                            |                                                             | 1,058 |   | 1,054 |      | 1,133  |   
|Alberta System                                                               |                                                             | 742   |   | 742   |      | 728    |   
|Foothills                                                                    |                                                             | 127   |   | 135   |      | 132    |   
|Other (TQM, Ventures LP)                                                     |                                                             | 50    |   | 50    |      | 59     |   
|                                                                             |                                                            
|Canadian Natural Gas Pipelines Comparable EBITDA(1)                          |                                                             | 1,977 |   | 1,981 |      | 2,052  |   
|Depreciation and amortization                                                |                                                             | (722  | ) | (715  | )    | (714   | ) 
|                                                                             |                                                            
|Canadian Natural Gas Pipelines Comparable EBIT(1)                            |                                                             | 1,255 |   | 1,266 |      | 1,338  |   
|                                                                             |                                                            
|U.S. Natural Gas Pipelines(in U.S. dollars)                                  |                                                             |       |   |       |      |        |   
|ANR                                                                          |                                                             | 312   |   | 314   |      | 300    |   
|GTN(2)                                                                       |                                                             | 131   |   | 171   |      | 170    |   
|Great Lakes(3)                                                               |                                                             | 101   |   | 109   |      | 120    |   
|TC PipeLines, LP(2)4)(5)                                                     |                                                             | 101   |   | 99    |      | 90     |   
|Iroquois                                                                     |                                                             | 67    |   | 67    |      | 68     |   
|Bison(5)                                                                     |                                                             | 49    |   |      |      |       |   
|Portland(6)                                                                  |                                                             | 22    |   | 22    |      | 22     |   
|International (Tamazunchale, Guadalajara, TransGas, Gas Pacifico/INNERGY)(7) |                                                             | 77    |   | 42    |      | 52     |   
|General, administrative and support costs(8)                                 |                                                             | (9    | ) | (31   | )    | (17    | ) 
|Non-controlling interests(9)                                                 |                                                             | 202   |   | 173   |      | 153    |   
|                                                                             |                                                            
|U.S. Natural Gas Pipelines Comparable EBITDA(1)                              |                                                             | 1,053 |   | 966   |      | 958    |   
|Depreciation and amortization                                                |                                                             | (267  | ) | (256  | )    | (276   | ) 
|                                                                             |                                                            
|U.S. Natural Gas Pipelines Comparable EBIT(1)                                |                                                             | 786   |   | 710   |      | 682    |   
|Foreign exchange                                                             |                                                             | (8    | ) | 24    |      | 105    |   
|                                                                             |                                                            
|U.S. Natural Gas Pipelines Comparable EBIT(1) (in Canadian dollars)          |                                                             | 778   |   | 734   |      | 787    |   
|                                                                             |                                                            
|Natural Gas Pipelines Business Development Comparable EBITDA and EBIT(1)     |                                                             | (52   | ) | (62   | )    | (62    | ) 
|                                                                             |                                                            
|Natural Gas Pipelines Comparable EBIT(1)                                     |                                                             | 1,981 |   | 1,938 |      | 2,063  |   
|                                                                             |                                                            
|Summary:                                                                     |                                                             |       |   |       |      |        |   
|Natural Gas Pipelines Comparable EBITDA(1)                                   |                                                             | 2,967 |   | 2,915 |      | 3,093  |   
|Depreciation and amortization                                                |                                                             | (986  | ) | (977  | )    | (1,030 | ) 
|                                                                             |                                                            
|Natural Gas Pipelines Comparable EBIT(1)                                     |                                                             | 1,981 |   | 1,938 |      | 2,063  |   
|Specific items:                                                              |                                                             |       |   |       |      |        |   
|                                                                             | Valuation provision for MGP(10)                             |       |  |       | (146 | )      |  
|                                                                             | Dilution gain from reduced interest in TC PipeLines, LP(11) |       |  |       |     |        | 29
|                                                                             |                                                            
|Natural Gas Pipelines EBIT(1)                                                |                                                             | 1,981 |   | 1,792 |      | 2,092  |   
|                                                                             |                                                            

MANAGEMENT'S DISCUSSION AND ANALYSIS25

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Natural Gas Pipelines' Comparable EBIT was $1,981 million in 2011 compared to $1,938 million in 2010. 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 was $2,063 million excluding the $29 million
dilution gain resulting from TransCanada's reduced interest in TC PipeLines, LP, which occurred as a result of the public issuance of common units by TC PipeLines, LP in
November 2009.

---

Wholly Owned Canadian Natural Gas Pipelines Net Income

|Year ended December 31(millions of dollars) |  | 2011 |  | 2010 |  | 2009
|------------------------------------------- |  | ---- |  | ---- |  | ----
|                                           
|Canadian Mainline                           |  | 246  |  | 267  |  | 273 
|Alberta System                              |  | 200  |  | 198  |  | 168 
|Foothills                                   |  | 22   |  | 27   |  | 23  

NATURAL GAS PIPELINES  FINANCIAL ANALYSIS

Canadian MainlineThe Canadian Mainline is regulated by the NEB under theNational 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 ROE, the level of deemed common equity, potential incentive earnings and changes in the level of
depreciation, financial charges and income taxes which are recovered in revenue on a flow-through basis.

The
Canadian Mainline operated under a five-year tolls settlement from 2007 through 2011. The cost of capital reflected 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 operating, maintenance and administration (OM&A) costs
for each of the five years. All other cost elements of the revenue requirement were treated on a flow-through basis. The settlement also allowed for performance-based incentive
arrangements that the Company believes were mutually beneficial to TransCanada and its customers.

26MANAGEMENT'S DISCUSSION AND ANALYSIS

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The
Canadian Mainline's net income of $246 million in 2011 was $21 million lower compared to 2010 as a result of a lower ROE of 8.08 per cent in
2011 compared to 8.52 per cent in 2010 and a lower average investment base, partially offset by higher incentive earnings. Net income in 2010 was $6 million lower compared to
2009. This decrease was primarily due to lower OM&A incentive earnings 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.

The
Canadian Mainline's Comparable EBITDA was $1,058 million in 2011 compared to $1,054 million and $1,133 million in 2010 and 2009, respectively.
EBITDA variances reflect the net income variances discussed above as well as variances in depreciation, financial charges and income taxes recovered in revenue on a flow-through basis.

Capital
Expenditures for the Canadian Mainline were $65 million in 2011 compared with $50 million and $61 million in 2010 and 2009, respectively.

GRAPHIC

Alberta SystemThe 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 the 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 which are 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. 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. All other cost elements of the revenue requirement are
treated on a flow-through basis. In 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
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 $200 million in 2011 was $2 million higher compared to 2010. The increase is primarily due to higher earnings as a result of
a growing average investment base. Net income in 2010 was $30 million higher than in 2009. This increase reflected an ROE of 9.70 per cent on 40 per cent deemed
common equity in 2010 compared to the earnings achieved under the settlement in place in 2009 and a higher average investment base, partially offset by lower incentive earnings. The increase in
average investment base from 2009 to 2011 reflects capital expenditures to expand capacity in response to growing customer demand for service.

MANAGEMENT'S DISCUSSION AND ANALYSIS27

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The
Alberta System's Comparable EBITDA of $742 million in 2011 was consistent with 2010. Comparable EBITDA in 2010 was $14 million higher than 2009. EBITDA
variances from the Alberta System reflect the net income variances discussed above as well as variances in depreciation, financial charges and income taxes recovered in revenue on a
flow-through basis.

GRAPHIC

FoothillsThe Foothills System's net income of $22 million in 2011 was $5 million lower compared
to 2010. The decrease was primarily due to lower earnings from a lower average investment base and lower OM&A incentive earnings. Net income in 2010 was $4 million higher than 2009, 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 were based on
the NEB ROE formula of 8.57 per cent on deemed common equity of 36 per cent.

The
Foothills System's Comparable EBITDA of $127 million in 2011 was $8 million lower compared to 2010. Comparable EBITDA in 2010 was $3 million higher
than 2009. EBITDA variances from the Foothills System reflect the net income variances discussed above as well as variances in depreciation, financial charges and income taxes recovered in revenue on
a flow-through basis.

Other Canadian Natural Gas PipelinesComparable EBITDA from Other Canadian Natural Gas Pipelines of
$50 million in 2011 was consistent with 2010 and was $9 million lower than 2009 primarily due to an adjustment in 2009 as a result of the NEB's decision with respect to TQM cost of
capital for 2007 and 2008.

ANRANR's natural gas transportation and storage services are provided for under tariffs regulated by the FERC.
These tariffs include maximum and minimum rates for services and allow 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 that was effective beginning in 1997. ANR Pipeline
Company is not required to conduct a review of currently effective rates with the FERC at any time in the future but is not prohibited from filing for new rates if necessary. ANR Storage Company,
which is a FERC regulated entity that owns and operates certain storage fields in Michigan, has rates that were established pursuant to a settlement approved by the FERC that were effective beginning
in 1990. ANR Storage Company is currently subject to a review, initiated by the FERC in late 2011, of its existing rates.

ANR's
EBITDA is affected by the contracting and pricing of its existing transportation and storage capacity, expansion projects, delivered volumes and incidental commodity
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 2011 was US$312 million, a decrease of US$2 million compared to 2010. The decrease was primarily due to higher OM&A costs partially
offset by higher transportation revenues, a settlement with a counterparty and incidental commodity sales. Comparable EBITDA in 2010 of US$314 million increased US$14 million compared to
2009, primarily due to lower OM&A costs, partially offset by lower contracted firm long-haul transportation sales and storage revenues.

GTNGTN is regulated by the FERC and is operated in accordance with tariffs that establish maximum and minimum
rates for various services. GTN is permitted to discount or negotiate rates on a non-discriminatory basis. In 2011, GTN

28MANAGEMENT'S DISCUSSION AND ANALYSIS

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negotiated
a settlement for new rates with its customers in lieu of filing a rate case. The FERC approved the settlement agreement in November 2011 for new rates effective January 1,
2012. The settlement includes a four-year moratorium during which GTN and the settling parties are prohibited from taking certain actions, including making any filings to adjust rates
prior to December 31, 2015. The settlement also requires GTN to file for new rates that are to be effective January 1, 2016.

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 from TransCanada's direct investment was US$131 million in 2011, a decrease of US$40 million compared to 2010. The decrease was
primarily due to TransCanada's May 2011 sale of a 25 per cent interest in GTN to TC PipeLines, LP and decreased revenue. Comparable EBITDA in 2010 increased
US$1 million compared to 2009, primarily due to lower OM&A costs and incremental proceeds accrued in 2010 relating to bankruptcy distributions from Calpine, partially offset by the impact of
selling North Baja to TC PipeLines, LP in July 2009 and the write-off of costs in 2010 related to an unsuccessful information systems project.

Other U.S. Natural Gas PipelinesComparable EBITDA from the remainder of the U.S. Natural Gas
Pipelines was US$610 million in 2011 compared to $481 million in 2010. The increase was primarily due to the start of commercial operations of Bison and Guadalajara pipelines in
January 2011 and June 2011, respectively, as well as the 25 per cent sale of TransCanada's ownership interest in GTN to TC PipeLines, LP in May 2011. Other
contributing factors were lower general, administrative and support costs in 2011, partially offset by lower Great Lakes revenues in 2011. Comparable EBITDA in 2010 decreased US$7 million from
2009, primarily due to lower Great Lakes revenues.

Business DevelopmentNatural Gas Pipelines' Business Development Comparable EBITDA loss from business
development expenses was $52 million in 2011 compared to $62 million in 2010. This improvement of $10 million was primarily due to lower business development costs associated with
the Alaska Pipeline Project as a result of increased reimbursement by the State of Alaska to 90 per cent from 50 per cent effective July 31, 2010. Comparable EBITDA
loss of $62 million in 2010 was consistent with 2009.

Depreciation and AmortizationDepreciation and Amortization for Natural Gas Pipelines was $986 million in
2011, an increase of $9 million from 2010. The increase was primarily due to the start-up of Bison and Guadalajara partially offset by lower depreciation for Great Lakes as a result
of the lower depreciation rate in Great Lakes' 2010 rate settlement. Depreciation and Amortization decreased $53 million in 2010 from 2009 primarily due to a weaker U.S. dollar in 2010
and lower depreciation for Great Lakes as a result of its 2010 rate settlement.

NATURAL GAS PIPELINES  OPPORTUNITIES AND DEVELOPMENTS

IntroductionOpportunities for North American natural gas pipeline infrastructure are
impacted by the developments in the natural gas exploration and production sector. Rapidly increasing supply of hydrocarbons from shale and other tight or low permeability resource plays, particularly
in the past five years, are transforming the domestic natural gas market. These resource plays are being further developed due to the recent wide-spread application of horizontal drilling
together with multi-stage hydraulic fracturing (fracking) that is reshaping the natural gas industry. For example, North America has evolved from having numerous projects and proposals in various
stages of development for liquefied natural gas (LNG) import facilities as recently as five years ago to the current situation where both the Canadian and U.S. regulators have issued and are
considering additional LNG export licenses due to the significant increase in North American natural gas supply.

The
abundance of supply resulting in relatively low natural gas prices across North America is supportive of increased reliance on natural gas to meet growing energy
demands. A shift to increased natural gas fired power generation is also emerging in the U.S. and Canada. Numerous proposals for development of LNG export facilities from North America is another
example of the evolution of the natural gas industry. Persistently high oil prices, particularly relative

MANAGEMENT'S DISCUSSION AND ANALYSIS29

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to
North America natural gas prices, have resulted in increased deployment of capital for the exploration and production of liquid-rich hydrocarbon basins, which also tend to produce
associated natural gas. A recent announcement by the Mexican government to change its procurement strategy away from LNG imports to infrastructure improvements that facilitate increased access to
natural gas supply from the U.S. is further evidence of the increased confidence in the availability of supply at stable prices across North America.

The
evolution of the natural gas market is also driving changes to traditional flow patterns across the continental pipeline grid resulting in reassessment of the use and
repurposing of existing assets. TransCanada's portfolio of North American natural gas pipeline infrastructure is well positioned to capture investment opportunities from growing natural gas supply as
well as opportunities to connect new markets while satisfying increasing demand for natural gas within existing markets.

The
following are significant initiatives by TransCanada to capture opportunities in the evolving natural gas industry in North America:

Canadian MainlineIn September 2011, TransCanada filed the Restructuring Proposal, a comprehensive
application with the NEB to change the business structure and the terms and conditions of service for the Canadian Mainline. The application included the following components:

In
October 2011, TransCanada filed supplementary information on cost of service and the proposed tolls for 2012 and 2013. These applied-for tolls result
in a 2012 toll of $1.29 per gigajoule for transportation from Nova Inventory Transfer to the Dawn, Ontario delivery point, which is 38 per cent lower than the comparable toll charged
in 2011.

The
Restructuring Proposal was developed by TransCanada as an innovative and balanced response to recent and dramatic changes in the business environment of natural gas
supply, demand and transportation in North America. The application is intended to enhance the long-term economic viability and sustainability of the Canadian Mainline and the WCSB. A
decision regarding the Restructuring Proposal is expected in late 2012 or early 2013.

TransCanada
re-filed an application with the NEB in November 2011 that included supplemental information for approval to construct $130 million of
new pipeline infrastructure on the Canadian Mainline, to receive Marcellus shale basin gas at the Niagara Falls receipt point for further transportation to Eastern markets. Subject to regulatory
approval to construct the facilities, deliveries from Niagara Falls are expected to begin at a rate of 230 MMcf/d in November 2012 and then increase to 350 MMcf/d by
November 2013, which may require a subsequent application for additional facilities.

Alberta SystemThe Alberta System's Horn River natural gas pipeline project was approved by the NEB in
January 2011 and commenced construction in March 2011, with a targeted completion date of second quarter 2012 and an estimated capital cost of $275 million. In addition, the
Company executed an agreement to extend the Horn River pipeline by approximately 100 km (62 miles) at an estimated cost of $230 million. As a result of the extension, additional
contractual commitments of 100 MMcf/d are expected to commence in 2014 with volumes increasing to 300 MMcf/d by 2020. An application requesting approval to construct and operate this
extension was filed with the NEB in October 2011. The total contracted volumes for Horn River, including the extension, are expected to be approximately 900 MMcf/d by 2020.

30MANAGEMENT'S DISCUSSION AND ANALYSIS

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In
June 2011, the NEB approved the construction and operation of a 24 km (15 miles) extension of the Groundbirch natural gas pipeline. Construction
commenced in August 2011 with an expected in-service date of April 1, 2012 and an estimated cost of approximately $60 million. The project is required to serve
250 MMcf/d of new transportation contracts.

TransCanada
continues to advance pipeline development projects in B.C. and Alberta to transport new natural gas supply. The Company has filed applications with the NEB
requesting approval for expansions of the Alberta System to accommodate requests for additional natural gas transmission service throughout the northwest and northeast portions of the WCSB.
TransCanada has incremental firm commitments to transport approximately 3.4 billion cubic feet per day (Bcf/d) from western Alberta and northeast B.C. by 2014. Further requests for
additional volumes on the Alberta System from the northwest portion of the WCSB have been received. In 2011, including the projects discussed above, the NEB has approved natural gas pipeline projects
with capital costs of approximately $910 million. Further pipeline projects with a total capital cost of approximately $810 million are awaiting NEB decision. In addition, infrastructure
to connect WCSB supply to markets continues to be pursued particularly to support further development of Alberta oil sands production and to supply proposed LNG export facilities on the
Pacific Coast.

The
Alberta System filed an application in October 2011 with the NEB to implement a new business model to restructure the commercial terms applied to existing natural
gas liquids entering the Alberta System. The Natural Gas Liquids Extraction Model (NEXT) implementation date is proposed to be effective November 1, 2013. NEXT is designed to address the
inequities caused by the current extraction convention, and improve the competitiveness of the Alberta System and the WCSB.

Commercial
integration of the Alberta System and ATCO Pipelines system commenced in October 2011. Under the Agreement, the combined facilities of the two systems are
commercially operated as a single transmission system and transportation service is provided to customers by NOVA Gas Transmission Ltd. (NGTL) pursuant to NGTL's Tariff and suite
of rates and services. This agreement further identifies distinct geographic areas within Alberta for the construction of new facilities by each of NGTL and ATCO Pipelines. The final stage in this
integration project is the swapping of certain pipeline assets of equal value. An application to the NEB for approval of the asset swaps is anticipated in the first quarter 2012.

Canadian Mainline, Alberta System and Foothills 2012 TollsTransCanada filed for and received approval to
implement interim 2012 tolls on the Canadian Mainline effective January 1, 2012, at the same level as the currently approved 2011 final tolls. In addition, TransCanada filed for interim 2012
tolls on the Alberta System and annual tolls for Foothills to be effective January 1, 2012. These tolls have also been approved on an interim basis pending the outcome of the NEB's decision on
the Restructuring Proposal.

U.S. PipelinesIn May 2011, TransCanada closed the sale of a 25 per cent interest in
each of GTN and Bison to TC PipeLines, LP for an aggregate purchase price of US$605 million, which included US$81 million or 25 per cent of GTN's debt plus customary
closing adjustments.

GTNGTN executed a settlement agreement with its shippers for new transportation rates to be effective
January 2012 through December 2015. The settlement agreement was filed in August 2011 and approved by the FERC in November 2011.

Northern BorderNorthern Border operates pursuant to maximum long-term mileage-based rates and
seasonal short-term transportation rates approved by the FERC in a January 2007 rate case settlement. A moratorium on the filing of future rate cases under National Gas Act
Sections 4 or 5 expired on January 1, 2010. Northern Border is required to file a rate case on or before December 31, 2012.

TuscaroraTuscarora Gas Transmission filed a settlement agreement with the FERC in December 2011 that
concluded a review of Tuscarora's currently effective rates. The agreement, subject to the FERC approval, will lower shippers' reservation and transportation charges, and preclude another rate case
until 2014.

MANAGEMENT'S DISCUSSION AND ANALYSIS31

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ANRIn September 2011, ANR Pipeline Company filed an application with the FERC to sell its offshore Gulf
of Mexico assets and certain related onshore facilities to its wholly-owned subsidiary, TC Offshore LLC. At the same time, TC Offshore LLC requested authorization from the FERC to
acquire, own and operate those facilities under the FERC's regulations. These filings are currently pending before the FERC and a decision is expected in second or third quarter 2012.

Alaska Pipeline ProjectThe Alaska Pipeline Project team continues to work with shippers to resolve conditional
bids received as part of the project's open season and is working toward the FERC application deadline of October 2012 for the Alberta option that would extend from Prudhoe Bay to points near
Fairbanks and Delta Junction, and then to the Alaska-Canada border, where the pipeline would connect with a new pipeline in Canada. The pipeline in Canada would extend from the Alaska-Canada border to
link up with pipeline systems near Boundary Lake, Alberta, providing the capability of transporting natural gas into the continental U.S. TransCanada has commenced initial discussions with
Alaska North Slope producers regarding an alternative pipeline route, the LNG option, that would require a pipeline from Prudhoe Bay to LNG facilities, to be built by third parties, located in south-
central Alaska. TransCanada has entered into an agreement with Exxon Mobil Corporation (ExxonMobil) to jointly advance the project.

The Mackenzie Gas ProjectThe MGP received its Certificate of Public Convenience and Necessity in
March 2011, marking the end of the Federal regulatory process. The proponents of the 1,196 km, 30 inch pipeline, with an initial capacity of 1.2 Bcf/d, continue to seek the
Canadian government's support for an acceptable fiscal framework which would allow the project to progress.

MexicoThe Guadalajara Pipeline in Mexico began commercial operations in June 2011. The
US$360 million, 310 km (193 miles) project has capacity to transport 500 MMcf/d of natural gas to a power plant and 320 MMcf/d to the Pemex-owned national pipeline
system near Guadalajara. The pipeline is secured under 25-year contracts with the Comisión Federal de Electricidad (CFE), Mexico's federal government owned electrical power
company. In 2011, natural gas shipments were limited to support testing and commissioning efforts at the power plant. TransCanada and the CFE have agreed to add a US$60 million compressor
station to the pipeline that is expected to be operational in early 2013.

NATURAL GAS PIPELINES  BUSINESS RISKS

Natural Gas Supply, Markets and CompetitionTransCanada 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 certain 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, as well as in the WCSB. After declining over the past four years, WCSB production showed signs of recovery in 2011. 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 supply choices for customers. This change has contributed to a
trend of continued reduction in long-haul, long-term firm contracted capacity and a shift to shorter-distance, short-term firm and interruptible contracts on many
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. 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. The Alberta System, however, faces competition for connection to supply, particularly in northeast B.C., where the largest new source of natural gas has access to two
existing pipeline companies with infrastructure in the area.

The
Canadian Mainline, with its primary source of supply being the WCSB, also seeks opportunities to increase market share in Canadian domestic markets. However, TransCanada
expects to continue to face competition for both the eastern domestic markets and in particular, the northeastern U.S export markets. Consumers in the northeastern U.S. generally have access to
natural gas through numerous delivery and supply options. Eastern markets that

32MANAGEMENT'S DISCUSSION AND ANALYSIS

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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 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 per unit 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 sale of pipeline transportation capacity in the U.S. Gulf Coast region is highly competitive given the extensive natural gas pipeline network in this
region. ANR must also compete for supply from interconnects with pipelines originating within the growing U.S. midcontinent shale gas formations and the U.S. Rockies production regions.
Lower natural gas prices could result in reduced drilling activity and slow the rate of supply growth that has been fuelling investments in pipeline
infrastructure additions in the U.S. midcontinent which could limit the number of incremental pipeline investment opportunities in the future.

ANR
competes for market share with other natural gas pipelines and storage operators in its primary markets in the U.S. Midwest. As transportation capacity has become
more abundant due to major pipeline additions over the past few years, lower natural gas prices that result in less available supply could negatively affect the value of pipeline capacity. The value
of ANR's natural gas 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 out of the U.S. Rockies
basin to the California border that went in service in July 2011.

Great
Lakes and Northern Border are subject to annual contract renewals and can experience demand changes related to seasonal market conditions. To the extent the capacity
on these pipelines is contracted, utilization does not impact revenue significantly. Both pipelines compete for natural gas transportation customers with pipelines that transport gas exiting the WCSB.
An increase in competition in the key markets served by TransCanada's pipeline systems could arise from new ventures or expanded operations from existing competitors. For Great Lakes, the combination
of growing supply from the Rockies, Mid-Continent and Marcellus shale developments reaching Dawn, Ontario through both new and available pipeline capacity, as well as reduced demand due to
the economic environment, has the potential to maintain competitive pressures on WCSB supply into the Midwest. For example, if the transport of natural gas from those other supply basins to Dawn
becomes more economical on competitive pipeline routes, then those supplies could reach the eastern zone of Great Lakes' market area and displace Great Lakes' long-haul volumes.

Demand for Pipeline CapacityDemand for pipeline capacity is created by supply and market competition,
variations in economic activity, weather variability, natural gas pipeline and storage competition and pricing of alternative fuels. Demand and supply in new locations often creates opportunities for
new infrastructure, but it may also change flow patterns and potentially impact utilization of existing assets. For example, the proposed LNG export facilities on the west coast of B.C. have the
potential to reduce demand for capacity on pipelines that transport WCSB supply to other markets. TransCanada's pipelines may be challenged to sell available transportation capacity as transportation
contracts expire on its existing pipeline assets, as they have, for example, on the Great Lakes system in fourth quarter 2011. TransCanada expects its U.S. natural gas pipelines to become more
exposed to the potential for revenue variability due to rapidly evolving supply dynamics, competition and trends toward shorter term contracting by shippers.

MANAGEMENT'S DISCUSSION AND ANALYSIS33

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Demand
for a pipeline's capacity is ultimately the key driver that enables the transportation services to be sold. There are four key factors that influence demand for
pipeline capacity. They are the price of gas that influences the amount of supply, basin on basin competition that influences where the supply will be developed, technology that influences the cost
and pace of development of the resource play, and price basis differentials that drive what markets the supply will flow to. The risks associated with each of these four factors are considered below.

Gas Price

The price of natural gas is a key driver for development and exploration of the resource. The current low gas prices in North America may slow drilling activities that in turn
diminishes production levels, particularly in dry gas fields where the extra revenue generated from the entrained liquids is not available.

Basin on Basin Competition

Large producers often diversify their portfolios by developing several basins, but this is influenced by actual costs to develop the resource as well as economic access to
markets and cost of the necessary pipeline infrastructure. Therefore, basin on basin competition impacts the extent and timing of a resource play development that in turn drives changing dynamics for
demand of pipeline capacity.

Technology

The increased supply of natural gas in North America is primarily due to the application of technology to shale and tight gas plays that include both horizontal drilling and
fracking. There is growing regulatory and public scrutiny over the impacts of fracking. Changes to the practices of fracking through changes in regulations could impact the costs and pace of
development of natural gas plays.

Basis Differentials

In the period 2008 to 2011, there was more capacity added to the continental pipeline network than in any prior period in the history of the industry. Gas supply basins that
were once constrained such as the U.S. Rockies and East Texas now have an overabundance of export capacity. As well, the recent focus on the development of shale gas basins has led to declines
in conventional supply basins and unutilized capacity on many pipelines. These factors have led to contraction of regional basis differentials, the differences in market prices paid for natural gas
between different gas receipt and delivery points, which has led to changes in the way many pipeline systems are being used. As a result, many pipeline companies are moving to restructure their
business models, rate designs and services to adapt to the changing flow dynamics.

Regulatory RiskRegulatory decisions continue to have an impact on the financial returns from existing
investments in TransCanada's natural gas pipelines and are expected to have a similar impact on financial returns from future investments. TransCanada manages this risk through rate applications and
negotiated settlements, where possible.

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

Pipeline Abandonment Cost RiskThrough the Land Matters Consultation Initiative (LMCI), the NEB is addressing
several significant issues relating to future pipeline abandonment costs for Canadian regulated pipelines. During the LMCI process, the NEB provided several key guiding principles including the
position that abandonment costs are a legitimate cost of providing pipeline service and are recoverable, upon NEB approval, from users of the system. Based on the NEB's direction, the earliest that
collection of funds for future pipeline abandonment costs through cost-of-service tolls on Canadian regulated pipelines could begin would be 2015.

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

34MANAGEMENT'S DISCUSSION AND ANALYSIS

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NATURAL GAS PIPELINES  OUTLOOK

The WCSB remains an important supply basin for TransCanada's pipeline infrastructure, however, the Company's portfolio of pipelines across North America has broadened its
supply source to include many other prolific and emerging supply areas.

TransCanada
expects there will be excess natural gas pipeline capacity from the WCSB to markets outside Western Canada for the foreseeable future as a result of capacity
expansions on natural gas pipelines over the past 15 years, competition from other pipelines and supply basins, and significant growth in natural gas consumption within Alberta driven primarily
by oil sands development and electricity generation requirements.

The
WCSB has an ultimate remaining conventional resource estimate of 126 trillion cubic feet. In addition, the ultimate potential of the basin has been vastly
improved due to the advent of economic access to shale gas and tight gas. Over its history, the WCSB's ultimate potential has primarily reflected the economic productivity of the conventional resource
base. The recent additions of unconventional resources together with the increasing economic viability of low quality conventional resources as a result of new drilling and completion technology, has
in TransCanada's view, more than doubled the technically accessible resource base of the WCSB.

WCSB
production is expected to increase slightly in 2012. Despite reduced overall drilling levels across the WCSB, the dramatic increases in initial productivity resulting
from horizontally drilled wells, in combination with a renewed focus on associated natural gas liquids, has significantly offset the anticipated negative supply impact associated with reduced levels
of conventionally drilled vertical wells. Drilling activity has increased in northwestern Alberta and northeastern B.C. as producers develop projects to access deeper multi-zone gas plays,
shales and tight sands utilizing horizontally-drilled wells in combination with fracking 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 supply regions is currently approximately 1.5 Bcf/d.

The
outlook for demand driven infrastructure for WCSB supply within Western Canada remains positive with continued growth expected in Alberta oil sands development and coal
conversion to natural gas for power generation. In addition, in the second half of this decade, there is also potential for additional new markets in the Asia-Pacific region for WCSB gas,
connecting to new LNG terminals which are proposed along the west coast of B.C. to export Canadian gas.

Demand
for WCSB-sourced natural gas in Eastern Canada and the U.S. Northeast decreased in 2011, 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.

In
the U.S., TransCanada expects that unconventional production will continue to grow from established shale gas plays in eastern Texas, northwestern Louisiana, Arkansas,
southwestern Oklahoma and the Appalachian region. The Marcellus shale basin continues to grow and with new pipeline infrastructure coming on-stream, is changing the dynamics for gas flows
into and out of the U.S. Northeast. In addition, development of the Utica shale basin (predominantly in Ohio) is in its infancy. This basin has significant potential to become another major
natural gas supply source. Production focus has shifted in the near term toward more oil and liquids-rich hydrocarbon production, which is expected to increase associated natural gas
supply in Texas, North Dakota and other areas. Supply from coalbed methane and tight gas sands in the U.S. Rockies is also expected to grow. The resulting anticipated growth in
U.S. supply should provide additional opportunities for TransCanada's U.S. pipelines. U.S. demand growth is expected to be driven primarily by increased use of natural gas for
power generation and industrial growth, as well as LNG exports in the second half of the decade.

TransCanada
continues to seek opportunities in Mexico to further develop natural gas infrastructure opportunities. TransCanada will leverage the experience and expertise
gained on its Guadalajara and Tamazunchale pipelines and

MANAGEMENT'S DISCUSSION AND ANALYSIS35

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intends
to participate in the $10 billion program recently announced by the Mexican government to expand its natural gas transmission infrastructure.

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.

EarningsCanadian Natural Gas Pipelines' earnings are affected by changes in investment base, ROE, capital
structure and terms of toll settlements or other toll proposals as approved by the NEB, with the most significant variables being ROE, capital structure and investment base. Absent an NEB decision in
2012 with respect to Canadian Mainline 2012 tolls, earnings from the Canadian Mainline will be lower than in 2011 as results will reflect the last approved ROE of 8.08 per cent on deemed
common equity of 40 per cent, and will exclude incentive earnings that have enhanced Canadian Mainline's earnings in recent years. The Company expects continued growth of the Alberta
System investment base as new supply in northeastern B.C. and western Alberta 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, the result of
which 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
ability to recontract unsold capacity on TransCanada's U.S. pipelines and to sell 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 these markets. 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 ExpendituresTotal capital spending for natural gas pipelines was $0.9 billion in 2011. Capital
spending for the Company's wholly owned pipelines is expected to be approximately $1.0 billion in 2012.

36MANAGEMENT'S DISCUSSION AND ANALYSIS

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---

NATURAL GAS THROUGHPUT VOLUMES

|(Bcf)                |  | 2011  |  | 2010  |  | 2009 
|-------------------- |  | ----- |  | ----- |  | -----
|                    
|Canadian Mainline(1) |  | 1,887 |  | 1,666 |  | 2,030
|Alberta System(2)    |  | 3,517 |  | 3,447 |  | 3,538
|ANR                  |  | 1,706 |  | 1,589 |  | 1,575
|Foothills            |  | 1,289 |  | 1,446 |  | 1,205
|Northern Border      |  | 971   |  | 902   |  | 706  
|Great Lakes          |  | 830   |  | 804   |  | 727  
|GTN                  |  | 679   |  | 802   |  | 797  
|Iroquois             |  | 317   |  | 343   |  | 355  
|TQM                  |  | 154   |  | 151   |  | 164  
|Ventures LP          |  | 150   |  | 144   |  | 145  
|Bison(3)             |  | 105   |  |      |  |     
|North Baja           |  | 92    |  | 60    |  | 96   
|Tamazunchale         |  | 57    |  | 52    |  | 54   
|Gas Pacifico         |  | 46    |  | 51    |  | 62   
|Portland             |  | 36    |  | 36    |  | 37   
|Tuscarora            |  | 33    |  | 35    |  | 34   
|TransGas             |  | 26    |  | 30    |  | 28   

MANAGEMENT'S DISCUSSION AND ANALYSIS37

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GRAPHIC

OIL PIPELINES

KEYSTONE

Keystone is a 3,467 km (2,154 miles) wholly owned and operated 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 Company plans to expand and extend the oil pipeline system to the U.S. Gulf Coast (Keystone XL) which includes the
construction of a new crude oil pipeline from Cushing, Oklahoma to the U.S. Gulf Coast, the addition of operational storage facilities at Hardisty, Alberta and the construction of a new crude
oil pipeline from Hardisty, Alberta to Steele City, Nebraska. The expanded oil pipeline system is collectively referred to as Keystone. The completion of Keystone XL is expected to
increase total system capacity to approximately 1.4 million bbl/d.

38MANAGEMENT'S DISCUSSION AND ANALYSIS

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OIL PIPELINES  HIGHLIGHTS

---

OIL PIPELINES  RESULTS

|Year ended December 31(1)(millions of dollars)              |  | 2011 |  
|----------------------------------------------------------- |  | ---- | -
|                                                            | 
|Canadian Oil Pipelines Comparable EBITDA(2)                 |  | 210  |  
|Depreciation and amortization                               |  | (49  | )
|                                                            | 
|Canadian Oil Pipelines Comparable EBIT(2)                   |  | 161  |  
|                                                            | 
|U.S. Oil Pipelines Comparable EBITDA(2) (in U.S. dollars)   |  | 383  |  
|Depreciation and amortization                               |  | (82  | )
|                                                            | 
|U.S. Oil Pipelines Comparable EBIT(2)                       |  | 301  |  
|Foreign exchange                                            |  | (3   | )
|                                                            | 
|U.S. Oil Pipelines Comparable EBIT(2) (in Canadian dollars) |  | 298  |  
|                                                            | 
|Oil Pipelines Business Development                          |  |      |  
|Comparable EBITDA and EBIT(2)                               |  | (2   | )
|                                                            | 
|Oil Pipelines Comparable EBIT(2)                            |  | 457  |  
|                                                            | 
|Summary:                                                    |  |      |  
|Oil Pipelines Comparable EBITDA(2)                          |  | 587  |  
|Depreciation and amortization                               |  | (130 | )
|                                                            | 
|Oil Pipelines Comparable EBIT(2)                            |  | 457  |  
|                                                            | 

OIL PIPELINES  FINANCIAL ANALYSIS

Keystone is a 3,467 km (2,154 miles) wholly owned and operated 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 Company plans to expand and extend the existing system through Keystone XL which includes the construction of a new
crude oil pipeline from Cushing, Oklahoma to the U.S. Gulf Coast, the addition of operational storage facilities at Hardisty, Alberta and the construction of a new crude oil pipeline from
Hardisty, Alberta to Steele City, Nebraska. The expanded oil pipeline system is collectively referred to as Keystone. The completion of Keystone XL is expected to increase total system capacity to
approximately 1.4 million bbl/d.

MANAGEMENT'S DISCUSSION AND ANALYSIS39

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The
Marketlink projects would transport crude oil sourced from U.S. basins to refining markets in the Cushing, Oklahoma region and the U.S. Gulf Coast on
facilities that form part of Keystone XL. The proposed Bakken Marketlink project would transport U.S. crude oil from Baker, Montana to Cushing and the proposed Cushing Marketlink project
would transport crude oil from Cushing to Port Arthur and Houston, Texas.

Oil
Pipelines Comparable EBIT for the year ended 2011 was $457 million. EBITDA from Keystone is primarily generated from payments received under long-term
commercial arrangements for committed capacity that are not dependent on actual throughput. Uncontracted capacity is offered to the market on a spot basis and, when capacity is available, provides
opportunities to generate incremental EBITDA. In February 2011, the Company began recording EBITDA for the Wood River/Patoka and Cushing Extension sections.

Although
the Wood River/Patoka section commenced commercial operations in June 2010, cash flows other than general, administrative and support costs were capitalized
until February 2011. As a condition of the NEB's approval to begin operations, the Wood River/Patoka section operated 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
allowing the system to operate at its design pressure and throughput capacity.

---

Operating Statistics

|Year ended December 31(1)                  |         | 2011
|------------------------------------------ | ------- | ----
|                                          
|Delivery volumes (thousands of barrels)(2) |         |     
|                                           | Total   |     
|                                           | Average |     
|                                          

OIL PIPELINES  OPPORTUNITIES AND DEVELOPMENTS

Wood River/Patoka and Cushing ExtensionIn late January 2011, work was completed to allow the Wood
River/Patoka section of the system to operate at its design pressure following the NEB's decision to remove the MOP restriction in December 2010. In February 2011, the Cushing Extension
commenced commercial operations, extending the pipeline system to Cushing, Oklahoma and increasing nominal design capacity to 591,000 bbl/d.

In
May 2011, revised fixed tolls came into effect for the Wood River/Patoka section of the system that reflected the final project costs for this section.

In
June 2011, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a corrective action order on Keystone
as a result of two above-ground incidents in second quarter 2011 at pump stations in North Dakota and Kansas, both of which involved the release of crude oil. Following the incidents, TransCanada took
immediate action to contain the crude oil releases and repair the facilities. The corrective action order required TransCanada to develop and submit a written restart plan which included steps to
facilitate the proper clean up, investigation, and system improvements and modifications. The restart plan was approved by PHMSA in June 2011. In July and August 2011, work was performed
on the Keystone system to improve system reliability. The work was completed as planned and resulted in reduced pipeline capacity during those two months, however, it did not have a significant impact
on EBIT.

In
2010, three entities, each of which had entered into Transportation Service Agreements for the Cushing Extension, had filed separate Statements of Claim against certain
of TransCanada's Keystone subsidiaries in the Alberta Court of

40MANAGEMENT'S DISCUSSION AND ANALYSIS

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Queen's
Bench, seeking declaratory relief, or alternatively, damages in varying amounts. All of the claims have been discontinued on a without-cost and without-liability basis.

Keystone XLThe regulatory approval process for the U.S. portion of Keystone XL continued throughout 2011
and early 2012. Following an extensive environmental review process, the DOS, the lead agency for U.S. federal regulatory approvals, released its FEIS in August 2011. The FEIS found that
the project would have no significant impact on the environment and that the proposed route would have the least environmental impact of the alternatives considered.

Following
the issuance of the FEIS, the DOS initiated a 90-day National Interest Determination (NID) process. During the NID process, concern about the
pipeline's impact on the Sandhills region of Nebraska was raised and on November 10, 2011, the DOS determined it necessary to identify and assess alternative routes that would avoid the
Sandhills region in Nebraska in order to move forward with a decision on the Presidential Permit. The DOS indicated that the additional environmental review process including a public comment
period on a supplement to the FEIS could be completed as early as first quarter 2013. In December 2011, theTemporary Payroll Tax Cut Continuation
Actwas approved by the U.S. Senate and the U.S. House of Representatives and signed into law by U.S. President Obama on December 23, 2011. The
legislation required a final decision on the Keystone XL Presidential Permit by February 21, 2012.

On
January 18, 2012, the DOS denied the Presidential Permit for Keystone XL, based on the DOS's position that it did not have sufficient time to receive and review
additional information necessary to assess alternative routes that would avoid the Sandhills region of Nebraska. The DOS noted that its decision did not preclude TransCanada from submitting a
subsequent Presidential Permit application for Keystone XL.

TransCanada
is continuing to work with the State of Nebraska to determine the preferred route that avoids the Sandhills region in Nebraska. The Company will submit a revised
Presidential Permit application to the DOS. Assuming regulatory approval is received by first quarter 2013, TransCanada believes it could have Keystone XL in service by early 2015. The Company
continues to monitor political developments in the U.S. and the potential impact they may have on commencing construction of Keystone XL.

In
December 2011, TransCanada announced that it had secured additional commercial support for Keystone XL following the successful conclusion of a binding open season
offering long-term firm service for crude oil transportation from Hardisty, Alberta to Houston, Texas (Houston Lateral) increasing total long-term contracts on Keystone XL to in
excess of 1.1 million bbl/d for an average term of approximately 18 years. The approximate US$600 million Houston Lateral project would involve the expansion of capacity through
additional pump units increasing the capacity of Keystone XL to 830,000 bbl/d and the construction of an approximately 80 km (50 miles) pipeline extension from the proposed
Keystone XL system. The Houston Lateral is expected to more than double the U.S. Gulf Coast refining market capacity directly accessible from the Keystone pipeline system to over four million
bbl/d and is expected to be in service by early 2015, subject to regulatory approvals.

The
capital cost of Keystone XL, including the Houston Lateral, is estimated to be approximately US$7.6 billion, with US$2.4 billion having been invested at
December 31, 2011. Of the amount invested to date, approximately 60 per cent of the total represents purchased equipment and materials. The remaining capital cost amount is
expected to be invested between now and the in-service date of the expansion, which is expected by early 2015. Capital costs related to the construction of Keystone XL are subject to
capital cost risk and reward sharing mechanisms with Keystone's long-term committed shippers.

Marketlink ProjectsThe 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. In 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 Keystone XL. The capital cost of the incremental
facilities is expected to be approximately US$140 million and, pending regulatory approvals, commercial in service is anticipated in early 2015.

In
fourth quarter 2011, TransCanada secured additional contractual support for the Cushing Marketlink project, which would transport crude oil from Cushing, Oklahoma to Port
Arthur and Houston, Texas. The approximate US$50 million Cushing Marketlink project would use a portion of the Keystone XL facilities including the Houston Lateral. Pending

MANAGEMENT'S DISCUSSION AND ANALYSIS41

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regulatory
approvals, Cushing Marketlink is expected to begin shipping crude oil to Port Arthur and Houston in early 2015.

OIL PIPELINES  BUSINESS RISKS

Crude Oil Supply, Markets and CompetitionAlberta produces the majority of the crude oil in the WCSB and is the
primary source of crude oil supply for Keystone. In 2011, the WCSB produced an estimated 2.7 million bbl/d, consisting of 1.1 million bbl/d of conventional crude oil and condensate, and
1.6 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 new shale oil production
including the Bakken and Cardium formations and 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 2011, the Canadian Association of Petroleum Producers (CAPP) forecasted WCSB crude oil supply would increase to 3.5 million bbl/d by 2015 and to
4.5 million bbl/d by 2020, indicating future growth in Alberta crude oil production. CAPP estimated spending in the oil sands totalled $19 billion in 2011 and is expected to increase
from that level in 2012.

Keystone
has contracted a significant portion of its capacity under long-term commercial arrangements. 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 2011, the Williston Basin
achieved production rates of nearly 530,000 bbl/d. TransCanada expects production levels will reach approximately 840,000 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 more than 1.0 million bbl/d and has been growing 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 pipeline system are primarily refiners in the U.S. Midwest, midcontinent and Gulf Coast regions.
TransCanada competes with pipelines that deliver WCSB, Williston Basin and Permian Basin crude oil to these refiners through interconnections with other pipelines. Keystone also competes with
U.S. domestically-produced crude oil and imported crude oil for refining markets in the U.S. Midwest, Midcontinent and Gulf Coast regions.

Regulatory RiskRegulations and decisions issued by Canadian and U.S. regulatory bodies, including the
NEB, FERC, EPA, Army Corps of Engineers, various state regulators, U.S. Department of Transportation, PHMSA and DOS, may have a significant impact on the approval, construction, operational 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.

Pipeline Abandonment Cost RiskKeystone's Canadian facilities are subject to the NEB's LMCI process previously
discussed in the Natural Gas Pipelines  Business Risks section in this MD&A. Future pipeline abandonment costs for Keystone's Canadian facilities are expected to
be recovered in transportation tolls.

Throughput RiskTransCanada has secured long-term transportation contracts for most of Keystone's
capacity. Payments received for this committed capacity are not dependent on actual throughput. Uncontracted capacity is offered to the market on a spot basis. Uncontracted throughput is dependent
primarily on crude oil production levels, market competition for crude oil, refinery activity and variations in economic activity.

42MANAGEMENT'S DISCUSSION AND ANALYSIS

---



Plant AvailabilityOptimizing 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. Unexpected plant outages will impact throughput capacity and may result in reduced contracted capacity payments and lower uncontracted
transportation sales revenue.

Execution and Capital Cost RiskCapital 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 on Keystone XL would be adjusted by a factor equal to 75 per cent of the percentage change in capital costs. 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 North American 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 2012 and 2013. Alberta oil sands production is forecast to increase to 2.3 million bbl/d by 2016 from 1.6 million bbl/d in 2011 and total
Western Canada crude oil supply is projected to grow over the same period to 3.7 million bbl/d from 2.7 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 international markets and markets in the U.S., that are currently served by
foreign imports. TransCanada will continue to pursue additional opportunities to transport crude oil from Alberta to new 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, and the U.S. Gulf Coast. TransCanada is competing with several other proposals to build pipeline capacity to transport crude oil supply from this region to
U.S. refining centres. 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 pipeline capacity to transport oil supply 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. refining centres.

EarningsOil Pipelines earnings in 2012 are expected to be higher than in 2011, primarily due to the impact of a
full year of earnings being recorded for the Wood River/Patoka and Cushing Extension sections of Keystone compared to eleven months in 2011. Earnings are primarily generated by contractual
arrangements for committed capacity that are not dependent on actual throughput. Uncontracted capacity offered to the market on a spot basis provides additional earnings opportunities. TransCanada
expects earnings from its crude oil pipelines to increase as the proposed Keystone XL and Marketlink projects begin delivering crude oil. Once fully completed, TransCanada expects to record annual
EBITDA of approximately US$1.7 billion, based on contracted volumes in place and assuming a full year of commercial operations servicing both the U.S. Midwest and Gulf
Coast markets.

Capital ExpendituresTotal capital spending for Oil Pipelines in 2011 was $1.2 billion. Capital spending
for Oil Pipelines in 2012 is expected to be approximately $0.9 billion, primarily due to contractual commitments associated with Keystone XL and expansion of Keystone's Hardisty, Alberta
facilities.

MANAGEMENT'S DISCUSSION AND ANALYSIS43

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GRAPHIC

ENERGY

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

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

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

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

44MANAGEMENT'S DISCUSSION AND ANALYSIS

---



SUNDANCE A&BTransCanada 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 a 50 per cent interest in ASTC Power Partnership, which has a PPA that expires in
2020, in place for 100 per cent of the production from the 706 MW Sundance B power facility. The Sundance facilities are located in south-central Alberta.

SHEERNESSTransCanada 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.

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

CANCARBA 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 POWERBruce 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 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 HILLSA 683 MW natural gas-fired, combined-cycle power plant in Halton Hills, Ontario.

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

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

CARTIER WINDThe 590 MW Cartier Wind farm consists of five wind power projects located in Québec and is
62 per cent owned by TransCanada. Baie-des-Sables, Anse-à -Valleau, Carleton, Montagne-Sèche and phase one of
Gros-Morne wind farms are in service and have a total generating capacity of 479 MW. Construction continues on the 111 MW second phase of the Gros-Morne wind farm
which is expected to be operational in December 2012.

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

KIBBY WINDA 132 MW wind farm located in Kibby and Skinner Townships in Maine.

TC HYDROTC 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.

OCEAN STATE POWERA 560 MW natural gas-fired, combined-cycle facility located in Burrillville, Rhode Island.

RAVENSWOODA 2,480 MW multiple-unit generating facility located in Queens, New York, employing dual
fuel-capable steam turbine, combined-cycle and combustion turbine technology.

COOLIDGEA 575 MW simple-cycle, natural gas-fired peaking power facility in Coolidge, Arizona, which was placed in
service in second quarter 2011.

EDSONAn 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.

CROSSALTAA 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 and, through an agreement
made effective July 1, 2011, is now the operator of the facility.

MANAGEMENT'S DISCUSSION AND ANALYSIS45

---





ENERGY  HIGHLIGHTS

46MANAGEMENT'S DISCUSSION AND ANALYSIS

---



---

POWER PLANTS  NOMINAL GENERATING CAPACITY AND FUEL TYPE

|                                  |                   | MW                  |       | Fuel Type
|--------------------------------- | ----------------- | ------------------- | ----- | ---------
|                                 
|Canadian Power                    |                   |                     |       |          
|Western Power                     |                   |                     |       |          
|                                  |                   | Sheerness           |       | 756      
|                                  |                   | Coolidge            |       | 575      
|                                  |                   | Sundance A          |       | 560      
|                                  |                   | Sundance B(1)       |       | 353      
|                                  |                   | MacKay River        |       | 165      
|                                  |                   | Carseland           |       | 80       
|                                  |                   | Bear Creek          |       | 80       
|                                  |                   | Redwater            |       | 40       
|                                  |                   | Cancarb             |       | 27       
|                                 
|                                  |                   | 2,636               |       |          
|                                 
|                                  | Eastern Power     |                     |       |          
|                                  |                   | Halton Hills        |       | 683      
|                                  |                   | Bécancour           |       | 550      
|                                  |                   | Cartier Wind(2)     |       | 365      
|                                  |                   | Portlands Energy(3) |       | 275      
|                                  |                   | Grandview           |       | 90       
|                                 
|                                  |                   | 1,963               |       |          
|                                 
|                                  | Bruce(4)          |                     | 2,480 |          
|                                 
|                                  |                   | 7,079               |       |          
|                                 
|U.S. Power                        |                   |                     |       |          
|                                  | Ravenswood        |                     | 2,480 |          
|                                  | TC Hydro          |                     | 583   |          
|                                  | Ocean State Power |                     | 560   |          
|                                  | Kibby Wind        |                     | 132   |          
|                                 
|                                  |                   | 3,755               |       |          
|                                 
|Total Nominal Generating Capacity |                   | 10,834              |       |          
|                                 

GRAPHIC

MANAGEMENT'S DISCUSSION AND ANALYSIS47

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---

ENERGY  RESULTS

|Year ended December 31(millions of dollars)               |  | 2011  |   | 2010  |   | 2009  |  
|--------------------------------------------------------- |  | ----- | - | ----- | - | ----- | -
|                                                          | 
|Canadian Power                                            |  |       |   |       |   |       |  
|Western Power(1)                                          |  | 489   |   | 220   |   | 279   |  
|Eastern Power(2)                                          |  | 314   |   | 231   |   | 220   |  
|Bruce Power                                               |  | 252   |   | 298   |   | 352   |  
|General, administrative and support costs                 |  | (43   | ) | (38   | ) | (39   | )
|                                                          | 
|Canadian Power Comparable EBITDA(3)                       |  | 1,012 |   | 711   |   | 812   |  
|Depreciation and amortization                             |  | (276  | ) | (242  | ) | (227  | )
|                                                          | 
|Canadian Power Comparable EBIT(3)                         |  | 736   |   | 469   |   | 585   |  
|                                                          | 
|U.S. Power(in U.S. dollars)                               |  |       |   |       |   |       |  
|Northeast Power(4)                                        |  | 314   |   | 335   |   | 210   |  
|General, administrative and support costs                 |  | (41   | ) | (32   | ) | (40   | )
|                                                          | 
|U.S. Power Comparable EBITDA(3)                           |  | 273   |   | 303   |   | 170   |  
|Depreciation and amortization                             |  | (109  | ) | (116  | ) | (92   | )
|                                                          | 
|U.S. Power Comparable EBIT(3)                             |  | 164   |   | 187   |   | 78    |  
|Foreign exchange                                          |  | (4    | ) | 7     |   | 8     |  
|                                                          | 
|U.S. Power Comparable EBIT(3) (in Canadian dollars)       |  | 160   |   | 194   |   | 86    |  
|                                                          | 
|Natural Gas Storage                                       |  |       |   |       |   |       |  
|Alberta Storage                                           |  | 89    |   | 140   |   | 173   |  
|General, administrative and support costs                 |  | (6    | ) | (8    | ) | (9    | )
|                                                          | 
|Natural Gas Storage Comparable EBITDA(3)                  |  | 83    |   | 132   |   | 164   |  
|Depreciation and amortization                             |  | (14   | ) | (15   | ) | (14   | )
|                                                          | 
|Natural Gas Storage Comparable EBIT(3)                    |  | 69    |   | 117   |   | 150   |  
|                                                          | 
|Energy Business Development Comparable EBITDA and EBIT(3) |  | (25   | ) | (32   | ) | (37   | )
|                                                          | 
|Energy Comparable EBIT(3)                                 |  | 940   |   | 748   |   | 784   |  
|                                                          | 
|Summary:                                                  |  |       |   |       |   |       |  
|Energy Comparable EBITDA(3)                               |  | 1,338 |   | 1,125 |   | 1,131 |  
|Depreciation and amortization                             |  | (398  | ) | (377  | ) | (347  | )
|                                                          | 
|Energy Comparable EBIT(3)                                 |  | 940   |   | 748   |   | 784   |  
|                                                          | 

48MANAGEMENT'S DISCUSSION AND ANALYSIS

---



ENERGY  FINANCIAL ANALYSIS

|GRAPHIC |  | Energy's Comparable EBIT was $940 million in 2011 compared to $748 million in 2010 and $784 million in 2009.
|------- |  | ------------------------------------------------------------------------------------------------------------

Western PowerAs at December 31, 2011, 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 PPAs, five natural gas-fired cogeneration facilities
and a simple-cycle, natural gas peaking facility 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 power plants with capacity ranging from 27 MW to
165 MW. 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. As described further in the Energy  Opportunities and Developments section of this MD&A, no volumes were delivered under the
Sundance A PPA in 2011. 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 in Alberta 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 in Alberta, as at December 31, 2011, Western Power had entered into fixed-price power sales contracts to sell
approximately 8,400 gigawatt hours (GWh) in 2012 and 6,200 GWh in 2013.

Western
U.S. power assets consist of the 575 MW Coolidge Generating Station which was placed in service in May 2011. Coolidge power output is fully
contracted under a 20 year PPA with the Salt River Project, a local Arizona utility.

Eastern PowerEastern 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, the in-service Cartier Wind farms, Portlands Energy
and Grandview.

Halton
Hills was placed in service in September 2010 and is fully contracted under a 20-year Clean Energy Supply contract with the OPA.

Bécancour's
entire power output is supplied to Hydro-Québec under a 20-year power purchase contract expiring in 2026. Steam
produced 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

MANAGEMENT'S DISCUSSION AND ANALYSIS49

---



into
with Hydro-Québec. Under the agreement, while energy production and payments are suspended, TransCanada continues to receive capacity payments similar to those that would have been
received under the normal course of operation.

The
Montagne-Sèche and phase one of Gros-Morne Cartier Wind farms were placed in service November 2011, bringing the total generating
capacity of the in-service Cartier Wind farms to 479 MW. 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 is fully contracted 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. Eastern Power sales volumes were 100 per cent sold under contract in 2011 and
are expected to be fully contracted going forward.

---

Western and Eastern Canadian Power Comparable EBIT(1)(2)(3)

|Year ended December 31(millions of dollars) |                  | 2011  |       | 2010  |      | 2009  |     
|------------------------------------------- | ---------------- | ----- | ----- | ----- | ---- | ----- | ----
|                                            |                 
|Revenues                                    |                  |       |       |       |      |       |     
|                                            | Western power(2) |       | 1,081 |       | 714  |       | 788 
|                                            | Eastern power(3) |       | 475   |       | 330  |       | 281 
|                                            | Other(4)         |       | 70    |       | 84   |       | 86  
|                                            |                 
|                                            |                  | 1,626 |       | 1,128 |      | 1,155 |     
|                                            |                 
|Commodity purchases resold                  |                  |       |       |       |      |       |     
|                                            | Western power    |       | (538  | )     | (431 | )     | (451
|                                            | Other(4)(5)      |       | (9    | )     | (26  | )     | (26 
|                                            |                 
|                                            |                  | (547  | )     | (457  | )    | (477  | )   
|                                            |                 
|Plant operating costs and other             |                  | (276  | )     | (220  | )    | (179  | )   
|General, administrative and support costs   |                  | (43   | )     | (38   | )    | (39   | )   
|                                            |                 
|Comparable EBITDA(1)                        |                  | 760   |       | 413   |      | 460   |     
|Depreciation and amortization               |                  | (163  | )     | (140  | )    | (138  | )   
|                                            |                 
|Comparable EBIT(1)                          |                  | 597   |       | 273   |      | 322   |     
|                                            |                 

50MANAGEMENT'S DISCUSSION AND ANALYSIS

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---

Western and Eastern Canadian Power Operating Statistics

|Year ended December 31 |            | 2011                                 |  | 2010   |  | 2009  
|---------------------- | ---------- | ------------------------------------ |  | ------ |  | ------
|                      
|Sales Volumes (GWh)    |            |                                      |  |        |  |       
|Supply                 |            |                                      |  |        |  |       
|                       | Generation |                                      |  |        |  |       
|                       |            | Western Power(1)                     |  | 2,606  |  | 2,373 
|                       |            | Eastern Power(2)                     |  | 3,714  |  | 2,359 
|                       | Purchased  |                                      |  |        |  |       
|                       |            | Sundance A & B and Sheerness PPAs(3) |  | 7,909  |  | 10,785
|                       |            | Other purchases                      |  | 1,112  |  | 429   
|                      
|                       |            | 15,341                               |  | 15,946 |  | 15,016
|                      
|Sales                  |            |                                      |  |        |  |       
|                       | Contracted |                                      |  |        |  |       
|                       |            | Western Power                        |  | 9,245  |  | 10,211
|                       |            | Eastern Power                        |  | 3,714  |  | 2,375 
|                       | Spot       |                                      |  |        |  |       
|                       |            | Western Power                        |  | 2,382  |  | 3,360 
|                      
|                       |            | 15,341                               |  | 15,946 |  | 15,016
|                      
|Plant Availability(4)  |            |                                      |  |        |  |       
|Western Power(1)(5)    |            | 97%                                  |  | 95%    |  | 93%   
|Eastern Power(2)(6)    |            | 93%                                  |  | 94%    |  | 97%   
|                      

Western Power's Comparable EBITDA of $489 million and Power Revenues of $1,081 million in 2011 increased
$269 million and $367 million, respectively, compared to 2010 primarily due to higher overall realized power prices in Alberta and incremental earnings from Coolidge, which went in
service under a 20-year PPA in May 2011. Plant outages and higher demand resulted in average spot market power prices in Alberta increasing 51 per cent to $77 per
megawatt hour (MWh) in 2011 compared to $51 per MWh in 2010. Approximately 20 per cent of Western Power's sales volumes were sold in the spot market in 2011 compared to
25 per cent in 2010.

Western
Power's Comparable EBITDA in 2011 included $156 million of accrued earnings from the Sundance A PPA, the revenues and costs of which have been recorded as
though the outages of Sundance A Units 1 and 2 are interruptions of supply in accordance with the terms of the PPA. Refer to the Opportunities and Developments section in this MD&A for further
discussion on the dispute regarding the Sundance A outage.

Eastern
Power's Comparable EBITDA of $314 million and Power Revenues of $475 million in 2011 increased $83 million and $145 million,
respectively, compared to 2010. These increases were primarily due to the full year impact of incremental earnings from Halton Hills, which was placed in service in September 2010.

MANAGEMENT'S DISCUSSION AND ANALYSIS51

---



Western
Power's commodity purchases resold of $538 million increased $107 million compared to 2010 due to increased direct sales to customers, higher PPA costs
per MWh and higher volumes at Sheerness.

Plant
Operating Costs and Other, which includes natural gas fuel consumed in power generation, of $276 million in 2011 increased $56 million from 2010
primarily due to incremental fuel consumed at Halton Hills.

Depreciation
and amortization of $163 million increased $23 million in 2011 compared to 2010 primarily due to incremental depreciation from Halton Hills
and Coolidge.

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. 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 in service September 2010 and April 2009, respectively,
partially offset by lower contracted revenue from the Bécancour facility.

Plant
Operating Costs and Other of $220 million in 2010 increased $41 million from 2009 primarily due to incremental fuel consumed at Portlands Energy and
Halton Hills.

Bruce PowerBruce 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 being refurbished. The two units being refurbished are expected to resume commercial operations in first and
third quarter 2012. Bruce B has four operating reactors with a combined capacity of 3,200 MW. As at December 31, 2011, 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 (2010 and
2009  48.8 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 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.

52MANAGEMENT'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

|(TransCanada's proportionate share)
Year ended December 31(millions of dollars unless otherwise indicated) | 2011                          |       | 2010   |       | 2009   |      
|---------------------------------------------------------------------------------------------------------- | ----------------------------- | ----- | ------ | ----- | ------ | -----
|                                                                                                           |                              
|Revenues(1)                                                                                                | 817                           |       | 862    |       | 883    |      
|Operating expenses                                                                                         | (565                          | )     | (564   | )     | (531   | )    
|                                                                                                           |                              
|Comparable EBITDA(2)                                                                                       | 252                           |       | 298    |       | 352    |      
|                                                                                                           |                              
|Bruce A Comparable EBITDA(2)                                                                               | 98                            |       | 91     |       | 48     |      
|Bruce B Comparable EBITDA(2)                                                                               | 154                           |       | 207    |       | 304    |      
|                                                                                                           |                              
|Comparable EBITDA(2)                                                                                       | 252                           |       | 298    |       | 352    |      
|Depreciation and amortization                                                                              | (113                          | )     | (102   | )     | (89    | )    
|                                                                                                           |                              
|Comparable EBIT(2)                                                                                         | 139                           |       | 196    |       | 263    |      
|                                                                                                           |                              
|Bruce Power  Other Information                                                                            |                               |       |        |       |        |      
|Plant availability(3)                                                                                      |                               |       |        |       |        |      
|                                                                                                           | Bruce A                       | 90%   |        | 81%   |        | 78%  
|                                                                                                           | Bruce B                       | 88%   |        | 91%   |        | 91%  
|                                                                                                           | Combined Bruce Power          | 89%   |        | 88%   |        | 87%  
|Planned outage days                                                                                        |                               |       |        |       |        |      
|                                                                                                           | Bruce A                       | 60    |        | 60    |        | 56   
|                                                                                                           | Bruce B                       | 135   |        | 70    |        | 45   
|Unplanned outage days                                                                                      |                               |       |        |       |        |      
|                                                                                                           | Bruce A                       | 16    |        | 64    |        | 82   
|                                                                                                           | Bruce B                       | 24    |        | 34    |        | 47   
|Sales volumes (GWh)                                                                                        |                               |       |        |       |        |      
|                                                                                                           | Bruce A                       | 5,475 |        | 5,026 |        | 4,894
|                                                                                                           | Bruce B                       | 7,859 |        | 8,184 |        | 7,767
|                                                                                                           |                              
|                                                                                                           | 13,334                        |       | 13,210 |       | 12,661 |      
|                                                                                                           |                              
|Results per MWh                                                                                            |                               |       |        |       |        |      
|                                                                                                           | Bruce A power revenues        | $66   |        | $65   |        | $64  
|                                                                                                           | Bruce B power revenues(4)     | $54   |        | $58   |        | $64  
|                                                                                                           | Combined Bruce Power revenues | $57   |        | $60   |        | $64  
|                                                                                                           |                              

TransCanada's proportionate share of Bruce Power's Comparable EBITDA decreased $46 million to $252 million in 2011
compared to 2010, primarily due to lower results at Bruce B. Comparable EBITDA in
2010 also included the net positive 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS53

---





TransCanada's proportionate share of Bruce A's Comparable EBITDA increased $7 million to $98 million in 2011 compared to 2010 primarily due to higher volumes
as a result of a decrease in unplanned outage days, partially offset by the above-noted payment in 2010 from Bruce B.

TransCanada's
proportionate share of Bruce B's Comparable EBITDA decreased $53 million to $154 million in 2011 compared to 2010. The decrease was primarily due
to lower realized prices resulting from expiration of fixed-price contracts at higher prices, higher operating costs and lower volumes due to an increase in planned outage days. Bruce B results
for 2010 included the above-noted payment to Bruce A.

Bruce
Power's Depreciation and Amortization increased $11 million in 2011 compared to 2010 and $13 million in 2010 compared to 2009 primarily due to capital
additions.

TransCanada's
proportionate share of Bruce Power's Comparable EBITDA of $298 million in 2010 decreased $54 million compared to 2009 due to lower realized
prices and higher annual lease expense in 2010 for Bruce B, partially offset by higher volumes at both Bruce A and Bruce B and the positive net impact of the payment made in 2010 by Bruce B to
Bruce A.

The
Independent Electricity System Operator (IESO) periodically requires the curtailment of certain units at Bruce Power to address surplus baseload generation in Ontario.
During these unit curtailments, Bruce power receives deemed generation payments at OPA contract prices. Lower sales volumes in 2009 compared to 2010 and 2011 reflected the impact of higher unit
curtailments in 2009.

The
overall plant availability percentage in 2012 is expected to be in the mid 70s for Bruce A Units 3 and 4. Bruce A commenced the approximate six month West Shift Plus
outage on Unit 3 on November 6, 2011. Additional planned maintenance on one of the units at Bruce A is scheduled for the summer of 2012. Bruce B's overall plant availability is expected
to be in the mid 90s for the four units in 2012. Planned maintenance on one of the units at Bruce B commenced in January 2012.

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, 2011  March 31, 2012 |  | $66.33 
|April 1, 2010  March 31, 2011 |  | $64.71 
|April 1, 2009  March 31, 2010 |  | $64.45 

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.
Payments received under the floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. No amounts recorded in revenues were
subject to repayment in 2011, 2010 or 2009.

Bruce B Floor Price

|                               |  | per MWh
|------------------------------ |  | -------
|                              
|April 1, 2011  March 31, 2012 |  | $50.18 
|April 1, 2010  March 31, 2011 |  | $48.96 
|April 1, 2009  March 31, 2010 |  | $48.76 

54MANAGEMENT'S DISCUSSION AND ANALYSIS

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Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot
price. Bruce B's realized price decreased by $4 per MWh to $54 per MWh in 2011 compared to 2010, and by $6 per MWh to $58 per MWh in 2010 compared to 2009, and reflected revenues recognized from the
floor price mechanism, contract settlements as well as volumes and revenues associated with deemed generation. The decreases reflected the expiration of higher-priced contracts entered into in
previous years.

U.S. PowerU.S. Power owns approximately 3,800 MW of power generation capacity, consisting
of Ravenswood, TC Hydro, Ocean State Power, and Kibby Wind. Ravenswood, located in Queens, New York, 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. 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. Ocean State Power, 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 in service in October 2010.

U.S. Power
focuses on selling power under short- and long-term contracts to wholesale, commercial and industrial customers in the New England,
New York and PJM Interconnection area (PJM) power markets. Exposure to fluctuations in spot prices on these power sales commitments are hedged with a combination of forward purchases of power,
forward purchases of fuel to generate power and through the use of financial contracts.

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. Refer to the Energy  Opportunities and Development section of this
MD&A for more information.

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, Ocean State Power 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS55

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---

U.S. Power Comparable EBIT(1)(2)

|Year ended December 31(millions of U.S. dollars) |             | 2011  |     | 2010  |       | 2009 |    
|------------------------------------------------ | ----------- | ----- | --- | ----- | ----- | ---- | ---
|                                                 |            
|Revenues                                         |             |       |     |       |       |      |    
|                                                 | Power(3)    |       | 919 |       | 1,090 |      | 742
|                                                 | Capacity    |       | 227 |       | 231   |      | 169
|                                                 | Other(3)(4) |       | 80  |       | 78    |      | 79 
|                                                 |            
|                                                 |             | 1,226 |     | 1,399 |       | 990  |    
|                                                 |            
|Commodity purchases resold(3)                    |             | (398  | )   | (543  | )     | (309 | )  
|Plant operating costs and other(4)               |             | (514  | )   | (521  | )     | (471 | )  
|General, administrative and support costs        |             | (41   | )   | (32   | )     | (40  | )  
|                                                 |            
|Comparable EBITDA(1)                             |             | 273   |     | 303   |       | 170  |    
|Depreciation and amortization                    |             | (109  | )   | (116  | )     | (92  | )  
|                                                 |            
|Comparable EBIT(1)                               |             | 164   |     | 187   |       | 78   |    
|                                                 |            

---

U.S. Power Operating Statistics(1)

|Year ended December 31       |            | 2011   |       | 2010   |       | 2009  
|---------------------------- | ---------- | ------ | ----- | ------ | ----- | ------
|                            
|Physical Sales Volumes (GWh) |            |        |       |        |       |       
|Supply                       |            |        |       |        |       |       
|                             | Generation |        | 6,880 |        | 6,755 |       
|                             | Purchased  |        | 6,018 |        | 8,899 |       
|                            
|                             |            | 12,898 |       | 15,654 |       | 11,303
|                            
|Plant Availability(2)        |            | 87%    |       | 86%    |       | 79%   
|                            

U.S. Power's Comparable EBITDA of US$273 million in 2011 decreased US$30 million compared to 2010 primarily due
to the negative impact of lower commodity and capacity prices and lower physical sales volumes, partially offset by new sales activity in PJM, an increase in the New York commercial customer
base and incremental earnings from phase two of Kibby Wind which was placed in service in October 2010.

Physical
sales volumes in 2011 have decreased compared to 2010 due to decreased demand as a result of unseasonable weather and reduced opportunities for wholesale contracts.
As well, fewer physical transactions were used to cover power sales commitments during 2011, in favour of financial transactions, compared to 2010.

U.S. Power's
Power Revenues of US$919 million in 2011 decreased US$171 million compared to 2010 primarily due to lower physical sales volumes and lower
prices, partially offset by new sales activity in New York and PJM.

56MANAGEMENT'S DISCUSSION AND ANALYSIS

---



Capacity
Revenue of US$227 million in 2011 decreased US$4 million compared to 2010. New York capacity revenues in the second half of 2011 were
negatively impacted by low spot prices as a result of the price mitigation issue described further in the Energy  Opportunities and Developments section in this
MD&A. Reduced capacity prices were partially offset by lower forced outage rates at Ravenswood.

Commodity
Purchases Resold of $398 million in 2011 decreased US$145 million compared to 2010 primarily due to a decrease in the quantity of physical power
purchased for resale under U.S. Power's power sales commitments to wholesale and industrial customers in New England, partially offset by higher realized prices on purchased power as
well as new activity in the New York and PJM markets.

U.S. Power's
Comparable EBITDA of US$303 million in 2010 increased US$133 million compared to 2009 primarily due to higher capacity revenues resulting
from higher capacity prices partially offset by higher forced outage rates at Ravenswood, higher volumes of power sold in the New England and New York markets, higher realized prices on
power sold and incremental earnings from Kibby Wind.

U.S. Power
achieved plant availability of 87 per cent in 2011 compared to 86 per cent in 2010 and 79 per cent in 2009. Lower
availability in 2009 was primarily due to an unplanned outage at Ravenswood Unit 30 from September 2008 to May 2009.

As
at December 31, 2011, approximately 3,600 GWh or 30 per cent and 1,000 GWh or 10 per cent of U.S. Power's planned
generation is contracted for 2012 and 2013, respectively. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales
fluctuate based on customer usage.

Natural Gas StorageTransCanada 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. TransCanada also has contracts for long-term, Alberta-based storage capacity from a
third party, which expire in 2030, subject to early termination rights in 2015.

---

Natural Gas Storage Capacity

|                    |  | Working Gas
Storage Capacity
(Bcf) |  | Maximum Injection/
Withdrawal
Capacity (MMcf/d) | 
|------------------- |  | ---------------------------------- |  | ----------------------------------------------- | 
|                   
|Edson               |  | 50                                 |  | 725                                             | 
|CrossAlta(1)        |  | 41                                 |  | 550                                             | 
|Third-party storage |  | 38                                 |  | 630                                             | 
|                   
|                    |  | 129                                |  | 1,905                                           | 
|                   

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
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 TransCanada's 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS57

---



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, 2011, TransCanada had contracted approximately 60 per cent of the total 129 Bcf of working gas storage capacity in 2012 and
20 per cent of storage capacity in 2013. Earnings from third-party storage capacity contracts are recognized over the terms of the contracts.

Proprietary
natural gas storage transactions are comprised of a forward purchase of natural gas to be injected into storage and a simultaneous forward sale of natural gas
for withdrawal at a later period, typically during the winter withdrawal season. By matching purchase and sales volumes on a back-to-back basis, TransCanada locks in future
positive margins, effectively eliminating its exposure to natural gas seasonal price spreads.

These
forward natural gas contracts provide highly effective economic hedges but do not meet the specific criteria for hedge accounting and, therefore, are recorded at their
fair value based on the forward market prices for the contracted month of delivery. Changes in the fair value of these contracts are recorded in revenues. TransCanada records its proprietary natural
gas inventory in storage at its fair value using a weighted average of forward prices for natural gas for the following four months, less selling costs. Changes in the fair value of inventory are
recorded in revenues. Changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sales contracts are excluded in determining comparable earnings, as
they are not representative of amounts that will be realized on settlement.

Natural
Gas Storage's Comparable EBITDA of $83 million in 2011 decreased $49 million compared to 2010 primarily due to decreased third party storage and
proprietary revenues as a result of lower realized natural gas price spreads.

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

Business DevelopmentBusiness Development Comparable EBITDA losses from business development expenses of
$25 million in 2011 decreased $7 million compared to 2010 and decreased $5 million in 2010 compared to 2009 primarily due to decreased development activity in 2011.

ENERGY  OPPORTUNITIES AND DEVELOPMENTS

Bruce PowerIn accordance with terms of the Bruce Power Refurbishment Implementation Agreement (BPRIA) between
Bruce Power and the OPA, Bruce A committed to refurbish and restart Units 1 and 2.

Refurbishment
work on Units 1 and 2 reached significant milestones in 2011. Fuelling of both Unit 1 and Unit 2 has now been completed and the final phases of
commissioning for Unit 2 are underway. Subject to regulatory approval, Bruce Power expects to commence commercial operations of Unit 2 in first quarter 2012 and commercial operations of
Unit 1 in third quarter 2012. TransCanada's share of the total net capital cost is expected to be approximately $2.4 billion of which $2.3 billion was incurred as at
December 31, 2011.

In
February 2011, the BPRIA was amended to extend the suspension date for Bruce A Contingent Support Payments (CSP) from December 31, 2011 to June 1,
2012. The CSP received from the OPA by Bruce A are equal to the difference between the fixed prices under the BPRIA and spot market prices. As a result of the amendment, all output from Bruce A will
be subject to spot market prices effective June 1, 2012 until the restart of both Units 1 and 2 is complete.

In
November 2011, Bruce Power commenced the approximately six month West Shift Plus outage as part of the life extension strategy for Unit 3. Subject to regulatory
approval, Unit 3 is expected to return to service in second quarter 2012.

Sundance AIn December 2010, Sundance A Units 1 and 2 were withdrawn from service and were subject
to a force majeure claim by TransAlta Corporation (TransAlta) in January 2011. In February 2011, TransAlta notified TransCanada that it had determined it was uneconomic to replace or
repair Units 1 and 2, and that the Sundance A PPA should therefore be terminated.

58MANAGEMENT'S DISCUSSION AND ANALYSIS

---



TransCanada
has disputed both the force majeure and the economic destruction claims under the binding dispute resolution process provided in the PPA and both matters will be
heard through a single binding arbitration process. The arbitration panel has scheduled a hearing in April 2012 for these claims. Assuming the hearing concludes within the time allotted,
TransCanada expects to receive a decision in mid-2012.

TransCanada
has continued to record revenues and costs throughout 2011 as it considers this event to be an interruption of supply in accordance with the terms of the PPA.
The Company does not believe TransAlta's claims meet the tests of force majeure or destruction as specified in the PPA and has therefore recorded $156 million of EBITDA for the year ended
December 31, 2011. The outcome of any arbitration process is not certain, however, TransCanada believes the matter will be resolved in its favour. The Company expects that its
unamortized carrying value as at December 31, 2011, of $77 million related to the Sundance A PPA in Intangibles and Other Assets remains fully recoverable under the terms
of the PPA, regardless of the outcome of the arbitration process.

OakvilleIn October 2010, the Government of Ontario announced that it would not proceed with the
$1.2 billion Oakville generating station, a 900 MW facility that TransCanada was intending to build, own, and operate further to a previously awarded 20-year Clean Energy Supply contract
with the OPA. In third quarter 2011, TransCanada, the Government of Ontario and the OPA reached a formal agreement to use an arbitration process to settle the dispute resulting from termination of
this contract. Pursuant to the arbitration agreement, the parties remain in discussions. TransCanada expects to be appropriately compensated for the economic consequences associated with the
contract's termination.

CoolidgeThe US$500 million Coolidge generating station was placed in service in May 2011. Power
from the 575 MW simple-cycle, natural gas-fired peaking facility located near Phoenix, Arizona is sold to the Salt River Project Agricultural Improvement and Power District under a
20-year PPA.

Cartier WindIn November 2011, the 58 MW Montagne-Sèche and the 101 MW first
phase of the Gros-Morne Wind farm projects were placed in service. The 111 MW second phase of Gros-Morne is expected to be operational in December 2012. This will
complete construction of the 590 MW Cartier Wind project in Québec. All of the power produced by Cartier Wind is sold under a 20-year PPA to
Hydro-Québec.

Ontario SolarIn December 2011, TransCanada agreed to purchase nine Ontario solar projects from Canadian
Solar Solutions Inc., with a combined capacity of 86 MW, for approximately $470 million. Under the terms of the agreement, each of the nine solar projects will be developed and
constructed by Canadian Solar Solutions Inc. using photovoltaic panels. TransCanada will purchase each project once construction and acceptance testing have been completed and operations have
begun under 20-year PPAs with the OPA under the Feed-In Tariff program in Ontario. TransCanada anticipates the projects will be placed in service between late 2012 and
mid-2013, subject to regulatory approvals.

BécancourIn June 2011, Hydro-Québec notified TransCanada it would exercise
its option to extend the agreement to suspend all electricity generation from the Bécancour power plant throughout 2012. Under the terms of the suspension 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 capacity payments under the agreement similar to those that would have
been received under the normal course of operation while energy production and payments are suspended.

RavenswoodSince July 2011, spot prices for capacity sales in the New York Zone J market have been
negatively impacted by the manner in which NYISO has applied pricing rules for a new power plant that recently began service in this market. TransCanada believes that this application of pricing rules
by the NYISO is in direct contravention of a series of the FERC orders which direct how new entrant capacity is to be treated for the purpose of determining capacity prices. TransCanada and other
parties have filed formal complaints with the FERC that are currently pending. The outcome of the complaints and longer-term impact that this development may have on Ravenswood
is unknown.

During
third quarter 2011, the demand curve reset process was completed following the FERC's acceptance of the NYISO's September 22, 2011 compliance filing. This
resulted in increased demand curve rates that apply going forward

MANAGEMENT'S DISCUSSION AND ANALYSIS59

---



to
2014. Until the above noted NYISO actions relative to new unit pricing are resolved, capacity prices are expected to remain volatile.

Subsequent
to closing the acquisition of Ravenswood in August 2008, TransCanada experienced a forced outage event related to Ravenswood's 981 MW Unit 30. The
unit returned to service in May 2009. TransCanada has filed claims against the insurers to enforce its rights under the insurance policies and litigation proceedings are ongoing.

Power Transmission Line ProjectsIn June 2011, Zephyr terminated the precedent agreements with its potential shippers
as the parties were unable to resolve key commercial issues. In July 2011, one of Zephyr's potential shippers exercised its contractual rights to acquire 100 per cent of the
Zephyr project from TransCanada.

ENERGY  BUSINESS RISKS

Fluctuating Power and Natural Gas Market PricesTransCanada 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. TransCanada's power generation facilities are exposed to
commodity price volatility in its Western Power operations in Alberta and in its U.S. Power operations in New England and New York. Earnings from these businesses are generally
correlated to the prevailing power supply demand conditions and the price of natural gas, as power prices are set by gas-fired power supplies the majority of the time. Extended periods of
low gas prices will generally place downward pressure on earnings from these facilities. Western Power's Coolidge Generating
Station and TransCanada's portfolio of assets in Eastern Canada have been fully contracted, and are therefore not subject to fluctuating commodity prices. Bruce Power's exposure to fluctuating power
prices is discussed further below.

Sales
of uncontracted power volumes into the spot market in Alberta and the U.S. northeast can be subject to price volatility, directly affecting earnings. To
mitigate this risk, TransCanada commits a portion of its supply to medium-term to long-term sales contracts while retaining an amount of unsold supply to mitigate the financial
impact of unexpected plant outages and to provide 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. As power sales contracts expire, new forward contracts are entered into at prevailing
market prices.

Under
an agreement with the OPA, 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. Bruce B also enters into
third party fixed-price contracts where it receives the difference between the contract price and spot price. All Bruce A output is sold into the Ontario wholesale power spot market under a
fixed-price contract with the OPA. All Bruce A output will be subject to spot market pricing effective June 1, 2012 until the restart of both Units 1 and 2 is complete.

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.

U.S. Power Capacity PaymentsThe 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, available supply and fluctuations in forecast demand. With the downturn in the economy in recent years,
there has been a decrease in demand that, combined with increased supply in these markets, has put downward pressure on capacity prices. In September 2011, the demand curve reset process for
the New York Zone J market was completed for the 2011 to 2014 capacity periods, resulting in increased demand curve rates. These increases, however, were more than offset by the
unexpected capacity price treatment applied to certain new entrants by NYISO in 2011, a matter that remains subject to a pending complaint lodged with the FERC. Refer to
Energy  Opportunities and Development for more information.

Plant AvailabilityOptimizing 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

60MANAGEMENT'S DISCUSSION AND ANALYSIS

---



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.

WeatherExtreme temperature and weather events in North America 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 impact the earnings of Energy's wind assets.

HydrologyTransCanada'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 PermittingEnergy's construction programs in Québec and Ontario,
including its investment in Bruce Power, are subject to execution, capital cost and permitting risks.

Regulation of Power MarketsTransCanada 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, changes in the interpretation and application of market rules by regulators, price caps, emission controls, unfair cost allocations to generators and
out-of-market actions taken by others 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 is an active participant in formal
and informal regulatory proceedings and takes legal action where required.

Refer
to the Risk Management and Financial Instruments and Other Risks sections in this MD&A for information on additional risks related to the Energy business.

ENERGY  OUTLOOK

The power supply/demand dynamic in Alberta is rapidly tightening. The 2011 average pool price rose to $77/MWh compared to $51/MWh in 2010, driven by unexpected plant outages
and increased demand, especially in the peak periods. Increases in Alberta's power demand were a function of economic growth coming from the oil sands and natural gas industries plus population
increases in the province. Over the next decade, further oil sands projects and the associated development are expected to drive continued strong Alberta economic growth. The Alberta Electric System
Operator's forecasts indicate power demand growth rates of 3.2 per cent per year over the next 20 years and estimates that more than 11,000 MW of new generation will be
required. This backdrop will provide an opportunity for TransCanada to participate in new generation and other power infrastructure projects. The current low gas price environment provides an
opportunity for gas generation sources to be a very cost-competitive option to fill these anticipated generation needs.

Ontario's
2011 average power demand was down 0.5 per cent compared to 2010. New renewable energy projects came in service in 2011 and the IESO projects a
further 2,500 MW of new and refurbished power supply additions by early 2013. This increase in supply, combined with lower natural gas prices plus weak 2011 Ontario economic growth of about two
per cent resulted in a decrease in the year-over-year average hourly Ontario energy price from $36/MWh

MANAGEMENT'S DISCUSSION AND ANALYSIS61

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in
2010 to $30/MWh in 2011. The IESO forecasts a return to power demand growth in 2012, however, future power demand growth rates are expected to be modest, as a full return of the energy intensive
industries lost in the recession is not expected. TransCanada's existing energy assets in Ontario are largely insulated from changes in the market price of power through contracts with the OPA.

New England's
average power demand fell slightly in 2011 while approximately 800 MW of new gas-fired power supply was added. This prevailing supply
and demand environment, in addition to lower natural gas prices and weak 2011 economic growth, resulted in power prices down slightly on a year over year basis. The 2011 average ISO New England
power price was US$47/MWh compared to the 2010 average of about US$50/MWh. ISO New England forecasts a return to power growth of about one per cent per year in the coming years, based on
modest economic growth.

New York
City's average power demand dropped slightly in 2011 while approximately 550 MW of new gas-fired power supply was added. Under this
supply/demand environment, coupled with lower natural gas prices, weak 2011 economic growth and continuing high New York City unemployment rates, power prices fell slightly on a year over year
basis. The 2011 average NYISO New York City power price was US$51/MWh versus the 2010 average of about US$56/MWh. The NYISO forecasts a return to power demand growth of about one
per cent per year in the coming years, based on modest population and economic growth.

EarningsTransCanada expects that results from its Energy operations in 2012 will be higher than those in 2011.
There will be a positive earnings impact from a full year of Coolidge, Montagne-Sèche and the first
phase of Gros-Morne, which all came in service during 2011. Additional earnings from Bruce Power will also be realized with the return to service of Unit 2, which is expected in first quarter 2012,
followed by Unit 1 which is expected in third quarter 2012. It is also anticipated that the nine solar projects TransCanada agreed to purchase in late 2011 will come in service between late
2012 and mid-2013 pending certain conditions and approvals. 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.

The
Company expects the positive impact on earnings from the new assets coming in service could be tempered by results from U.S. Power if capacity prices in
New York remain at low levels, and Gas Storage, where storage spreads are expected to remain at low levels throughout 2012. In addition, earnings from Bruce A will be impacted by the West Shift
Plus outage on Unit 3, which commenced on November 6, 2011 and is expected to last six months. Energy earnings in 2012 will also be impacted by fluctuations in Alberta power prices.

Certain
regulatory and arbitration outcomes that are expected to be resolved in 2012 may also have a significant impact on Energy results. Specifically, actions taken by the
FERC related to New York capacity prices, and resolution to the arbitration processes underway on Sundance A and Oakville may have a material financial impact on Energy earnings in 2012.

Other
factors such as plant availability, regulatory changes, weather, currency movements and overall stability of the energy industry can also affect 2012 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.

62MANAGEMENT'S DISCUSSION AND ANALYSIS

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CORPORATE

Corporate had a Comparable EBIT loss of $100 million in 2011 compared to losses of $99 million and $117 million in 2010 and 2009, respectively. The losses
in 2011 were consistent with 2010 and the decrease in the loss in 2010 compared to 2009 was primarily due to lower support services and other corporate costs.

OTHER INCOME STATEMENT ITEMS

---

COMPARABLE INTEREST EXPENSE

|Year ended December 31(millions of dollars) |                             | 2011  |     | 2010  |     | 2009  |    
|------------------------------------------- | --------------------------- | ----- | --- | ----- | --- | ----- | ---
|                                            |                            
|Comparable Interest on long-term debt(1)    |                             |       |     |       |     |       |    
|                                            | Canadian dollar-denominated |       | 490 |       | 514 |       | 548
|                                            | U.S. dollar-denominated     |       | 734 |       | 680 |       | 645
|                                            | Foreign exchange            |       | (7  | )     | 20  |       | 92 
|                                            |                            
|                                            |                             | 1,217 |     | 1,214 |     | 1,285 |    
|Other interest and amortization             |                             | 24    |     | 74    |     | 27    |    
|Capitalized interest                        |                             | (302  | )   | (587  | )   | (358  | )  
|                                            |                            
|Comparable Interest Expense                 |                             | 939   |     | 701   |     | 954   |    
|                                            |                            

Comparable Interest Expense increased in 2011 by $238 million to $939 million compared to 2010. This increase was
primarily due to decreased capitalized interest upon placing Keystone and Coolidge in service in 2011 and Halton Hills in service in the latter part of 2010. Comparable Interest on
long-term debt increased in 2011 compared to 2010 primarily due to new debt issues of US$1.0 billion in September 2010 and US$1.25 billion in June 2010. This
was offset by the impact of a weaker U.S. dollar and the decrease in interest expense on Canadian dollar-denominated debt from debt maturities. Other Interest and Amortization Expense in 2011
was positively affected by increased gains from changes in the fair value of derivatives used to manage TransCanada's exposure to fluctuating interest rates.

Comparable
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. 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 Units 1 and 2.

Comparable
Interest Income and Other was $60 million in 2011 compared to $94 million and $121 million in 2010 and 2009, respectively. The decrease in
2011 compared to 2010 was primarily due to lower gains from derivatives used to manage the Company's exposure to foreign exchange rate fluctuations. The decrease in 2010 compared to 2009 was primarily
due to the positive impact of a weakening U.S. dollar on the translation of U.S. dollar working capital balances throughout each year and gains in 2010 on derivatives used to manage
foreign exchange fluctuations.

Comparable
Income Taxes were $595 million, $400 million and $406 million in 2011, 2010, and 2009, respectively. The increase of $195 million in
2011 compared to 2010 was primarily due to increased pre-tax earnings and higher positive income tax adjustments in 2010 compared to 2011. In 2011 and 2010, the Company recorded a benefit
in Current

MANAGEMENT'S DISCUSSION AND ANALYSIS63

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Income
Taxes with an offsetting provision in Future Income Taxes as a result of bonus depreciation for U.S. income tax purposes on the Bison pipeline which was placed in service in
January 2011 and the Wood River/Patoka and Cushing Extension sections of Keystone which were placed in operational service in June 2010 and February 2011, respectively. The
decrease of $6 million in 2010 compared to 2009 was primarily due to increased pre-tax earnings offset by higher positive income tax adjustments in 2010.

Non-Controlling
Interests were $129 million in 2011 compared to $115 million and $96 million in 2010 and 2009, respectively. The
$14 million increase in 2011 compared to 2010 was primarily due to the sale of a 25 per cent interest in GTN and Bison to TC PipeLines, LP and reduction in the Company's
ownership interest in TC PipeLines, LP in May 2011 partially offset by the impact of a weaker US dollar in 2011. The increase in 2010 compared to 2009 was primarily due to increased TC
PipeLines, LP earnings as a result of higher revenues from Northern Border and the acquisition by TC PipeLines, LP of North Baja, partially offset by the impact of a weaker US dollar
in 2010.

LIQUIDITY AND CAPITAL RESOURCES

TransCanada believes that its financial position remains sound 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 is underpinned by predictable cash flow from operations, available cash balances and unutilized committed revolving bank lines
of US$1.0 billion, $2.0 billion, US$1.0 billion and US$300 million, maturing in November 2012, October 2016, October 2012 and February 2013,
respectively. These facilities also support the Company's three commercial paper programs. In addition, at December 31, 2011, TransCanada's proportionate share of unutilized capacity on
committed bank facilities at TransCanada-operated affiliates was $0.1 billion with maturity dates in 2012 and 2016. As at December 31, 2011, TransCanada had capacity of
$2.0 billion, $1.25 billion and US$4.0 billion under its equity, Canadian debt and U.S. debt shelf prospectuses, respectively. 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)      |  | 2011  |  | 2010  |   | 2009  |  
|------------------------------------------------ |  | ----- |  | ----- | - | ----- | -
|                                                 | 
|Funds generated from operations(1)               |  | 3,663 |  | 3,331 |   | 3,080 |  
|Decrease/(Increase) in operating working capital |  | 310   |  | (249  | ) | (90   | )
|                                                 | 
|Net Cash Provided by Operations                  |  | 3,973 |  | 3,082 |   | 2,990 |  
|                                                 | 

HIGHLIGHTS

Investing Activities

Dividends

64MANAGEMENT'S DISCUSSION AND ANALYSIS

---



CASH FLOW AND CAPITAL RESOURCES

Cash Generated from Operations

Net Cash Provided by Operations was $4.0 billion in 2011 compared to $3.1 billion and $3.0 billion in 2010 and 2009, respectively. Net Cash Provided by
Operations reflects Funds Generated from Operations, net of changes in operating working capital.

Funds Generated from Operations

|GRAPHIC |  | Funds Generated from Operations were $3.7 billion in 2011 compared to $3.3 billion and $3.1 billion in 2010 and 2009, respectively. The increase in 2011 compared to 2010 was primarily due to increased cash
from earnings. This increase was net of lower current income tax benefits from bonus depreciation for U.S. tax purposes recognized in 2011 compared to 2010. The increase in 2010 compared to 2009 was primarily due to the current income tax
benefit generated from bonus depreciation for U.S. tax purposes on Keystone assets placed in service in June 2010.
As at December 31, 2011, TransCanada's current liabilities were $5.9 billion and current assets were $3.6 billion resulting in a working capital deficiency of $2.3 billion. The Company believes this shortfall can be managed
through its ability to generate cash flow from operations, access to the unutilized committed revolving bank lines in excess of $4.0 billion, discussed above, as well as its ongoing access to capital markets.
|------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Investing Activities

|GRAPHIC |  | Capital expenditures totalled $3.3 billion in 2011 compared to $5.0 billion in 2010 and $5.4 billion in 2009. Expenditures in 2011, 2010 and 2009 related primarily to the completion of the
Wood River/Patoka and Cushing Extension Sections of Keystone, advancement of Keystone XL, the refurbishment and restart of Units 1 and 2 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.
|------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Financing Activities

In 2011, TransCanada issued Medium-Term Notes of $500 million and $250 million maturing in 2021 and 2041, respectively, and US$350 million of
Senior Notes due in 2021. The Company also made draws totalling US$0.5 billion on existing facilities and retired or repaid $1.3 billion of long-term debt.

In
2011, the Company's proportionate share of joint venture long-term debt issued and repaid was $48 million and $102 million, respectively. In
addition, Notes Payable decreased by $218 million in 2011.

At
December 31, 2011, 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:



MANAGEMENT'S DISCUSSION AND ANALYSIS65

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In
May 2011, TransCanada sold a 25 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for a total transaction
value of US$605 million, which included US$81 million of long-term debt, or 25 per cent of GTN LLC debt outstanding. GTN LLC and Bison LLC
own the GTN and Bison natural gas pipelines, respectively. Subsequent to the transaction, TransCanada's ownership in TC PipeLines, LP decreased to 33.3 per cent due to TC
PipeLines, LP's public issuance of common units as discussed under the heading 2011 Equity Financing Activities in this section.

The
Company believes it has the capacity to fund its existing capital program through internally-generated cash flow, continued access to capital markets and liquidity
underpinned by in excess of $4 billion of committed credit facilities. TransCanada's financial flexibility is further bolstered by opportunities for portfolio management, including an ongoing
role for TC PipeLines, LP.

2011 Long-Term Debt Financing Activities

In November 2011, the Company issued Medium-Term Notes of $500 million and $250 million maturing in 2021 and 2041, respectively, and in
June 2011, TC Pipelines, LP issued US$350 million of Senior Notes due in 2021. The Company also made draws totalling US$0.5 billion on existing facilities and
retired or repaid $1.3 billion of long-term debt.

2011 Equity Financing Activities

In November 2011, TransCanada filed a base shelf prospectus in Canada and the U.S. qualifying the issuance of up to $2.0 billion of common shares,
preferred shares and/or subscription receipts until December 2013. The shelf replaced the base shelf prospectus filed in September 2009. No securities have been issued under the
November 2011 base shelf prospectus.

In
May 2011, TC PipeLines, LP completed an underwritten public offering of 7,245,000 common units, including 945,000 common units purchased by
the underwriters upon full exercise of an over-allotment option, at US$47.58 per unit. As part of this offering, TransCanada made a capital contribution of approximately
US$7 million to maintain its two per cent general partnership interest in TC PipeLines, LP and did not purchase any other units. As a result of the common units offering,
TransCanada's ownership in TC PipeLines, LP decreased from 38.2 per cent to 33.3 per cent.

Dividend Reinvestment and Share Purchase Plan

TransCanada's Board of Directors has authorized the issuance of common shares 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 Company reserves the right to satisfy its DRP
obligations by issuing common shares from treasury at a discount of up to five per cent or by purchasing shares on the open market. Commencing with the dividends declared in April 2011,
common

66MANAGEMENT'S DISCUSSION AND ANALYSIS

---



shares
purchased with reinvested cash dividends are satisfied with shares acquired on the open market at 100 per cent of the weighted average purchase price. Previously, common shares
purchased with reinvested cash dividends were satisfied with shares issued from treasury 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. In 2011, dividends of $202 million were paid
(2010  $378 million; 2009  $254 million) through the issuance of 5 million
(2010  11 million; 2009  8 million) common shares from treasury in accordance with the DRP.

Dividends

Cash dividends on common shares of $961 million were paid in 2011 (2010  $710 million;
2009  $722 million). In addition, cash dividends of $55 million were paid on preferred shares in 2011
(2010  $44 million). The increase in common share cash dividends paid in 2011 was primarily due to the Company's decision to satisfy its DRP obligations
with market purchased shares instead of treasury shares effective April 2011, as discussed above, and an increase in the per share dividend amount in 2011. The decrease in common share
dividends paid in cash in 2010 from 2009 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 per share dividend amount in 2010.

The
increase in preferred share dividends paid in 2011 from 2010 was primarily due to a full year of preferred share dividend payments in 2011 on preferred shares issued in
March and June 2010. 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 2012, TransCanada's Board of Directors approved an increase in the quarterly common share dividend payment to $0.44 per share from $0.42 per share for the
quarter ending March 31, 2012. This was the twelfth 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, 2012 and $0.275 per
Series 5 preferred share for the three-month period ended April 30, 2012.

CONTRACTUAL OBLIGATIONS

Obligations and Commitments

At December 31, 2011, the Company had $18.6 billion of total long-term debt and $1.0 billion of Junior Subordinated Notes, compared to
$17.9 billion of total long-term debt and $1.0 billion of Junior Subordinated Notes at December 31, 2010. TransCanada's share of the total long-term debt
of joint ventures, including capital lease obligations, was $0.8 billion at December 31, 2011, compared to $0.9 billion at December 31, 2010. Total Notes Payable, including
TransCanada's proportionate share of the notes payable of joint ventures, were $1.9 billion at December 31, 2011 and $2.1 billion at December 31, 2010. TransCanada has also
provided certain pro-rata guarantees related to the capital lease and performance obligations of Bruce Power and certain other partially owned entities.

MANAGEMENT'S DISCUSSION AND ANALYSIS67

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---

CONTRACTUAL OBLIGATIONS

|                                                           |  |        |  | Payments Due by Period
|---------------------------------------------------------- |  | ------ |  | ----------------------
|                                                           |  |        |  |                       
|Year ended December 31(millions of dollars)                |  | Total  |  | Less than
one year    
|                                                          
|Long-term debt(1)                                          |  | 20,204 |  | 950                   
|Capital lease obligations                                  |  | 194    |  | 18                    
|Operating leases(2)                                        |  | 735    |  | 79                    
|Purchase obligations                                       |  | 9,152  |  | 1,650                 
|Other long-term liabilities reflected on the balance sheet |  | 911    |  | 17                    
|                                                          
|                                                           |  | 31,196 |  | 2,714                 
|                                                          

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 2011 was $394 million (2010  $363 million;
2009  $384 million).

At
December 31, 2011, 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    
|                                           
|Long-term debt                              |  | 18,567 |  | 935                   
|Junior subordinated notes                   |  | 1,009  |  |                      
|Long-term debt of joint ventures            |  | 628    |  | 15                    
|                                           
|                                            |  | 20,204 |  | 950                   
|                                           

|
|
|

---

INTEREST PAYMENTS

|                                            |  |        |  | Payments Due by Period
|------------------------------------------- |  | ------ |  | ----------------------
|                                            |  |        |  |                       
|Year ended December 31(millions of dollars) |  | Total  |  | Less than
one year    
|                                           
|Long-term debt                              |  | 16,541 |  | 1,180                 
|Junior subordinated notes(1)                |  | 355    |  | 65                    
|Long-term debt of joint ventures            |  | 343    |  | 48                    
|                                           
|                                            |  | 17,239 |  | 1,293                 
|                                           

68MANAGEMENT'S DISCUSSION AND ANALYSIS

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At December 31, 2011, 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    
|                                           
|Natural Gas Pipelines                       |  |       |  |                       
|Transportation by others(2)                 |  | 482   |  | 130                   
|Capital expenditures(3)(4)                  |  | 250   |  | 248                   
|Other                                       |  | 1     |  | 1                     
|Oil Pipelines                               |  |       |  |                       
|Capital expenditures(3)(5)                  |  | 992   |  | 98                    
|Other                                       |  | 48    |  | 4                     
|Energy                                      |  |       |  |                       
|Commodity purchases(6)                      |  | 5,121 |  | 666                   
|Capital expenditures(3)(7)                  |  | 290   |  | 234                   
|Other(8)                                    |  | 1,928 |  | 254                   
|Corporate                                   |  |       |  |                       
|Information technology and other            |  | 40    |  | 15                    
|                                           
|                                            |  | 9,152 |  | 1,650                 
|                                           

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
2012, TransCanada expects to make funding contributions of approximately $119 million to its defined benefit pension plans (DB Plan) and approximately
$31 million to the Company's other post-retirement benefit plans, savings plan and defined contribution pension plans. In addition to these contributions, the Company expects to
provide a

MANAGEMENT'S DISCUSSION AND ANALYSIS69

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$48 million
letter of credit in 2012 to the DB Plan. In 2011, the Company made total cash funding contributions of $93 million and provided a $27 million letter of credit to the
DB Plan. TransCanada's proportionate share of cash funding contributions expected to be made by joint ventures to their respective pension and other post-retirement benefit plans in 2012
is approximately $73 million and $7 million, respectively, compared to total contributions of $59 million in 2011.

The
next actuarial valuation for the Company's pension and other post-retirement benefit plans will be carried out as at January 1, 2013. Based on current
market conditions, TransCanada expects funding requirements for these plans to continue at the anticipated 2012 level for the next several years to amortize solvency deficiencies in addition to normal
costs. The Company's 2012 net benefit cost is expected to increase from 2011 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
$95 million. The Company expects $88 million and $7 million to be paid in 2012 and 2013, respectively.

Ontario Solar

In December 2011, an agreement was announced for the purchase of nine Ontario solar projects with a combined capacity of 86 MW, for approximately
$470 million. TransCanada will purchase each project once construction and acceptance testing are completed and operations have begun under 20-year PPAs with the OPA under the
Feed-In Tariff program in Ontario. It is anticipated that the projects will be placed in service between late 2012 and mid-2013, subject to regulatory approvals.

Contingencies

TransCanada is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2011, the Company had accrued approximately
$49 million (2010  $59 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, arbitrations 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.

In
December 2010, Sundance A Units 1 and 2 were withdrawn from service and were subject to a force majeure claim by TransAlta in January 2011. In
February 2011, TransAlta notified TransCanada that it had determined it was uneconomic to replace or repair Units 1 and 2, and that the Sundance A PPA should therefore be terminated.
TransCanada has disputed both the force majeure and the economic destruction claims under the binding dispute resolution process provided in the PPA and both matters will be heard through a single
binding arbitration process. The arbitration panel has scheduled a hearing in April 2012 for these claims. Assuming the hearing concludes within the time allotted, TransCanada expects to
receive a decision in mid-2012. TransCanada has continued to record revenues and costs throughout 2011 as it considers this event to be an interruption of supply in accordance with the
terms of the PPA. The Company does not believe TransAlta's claims meet the tests of force majeure or destruction as specified in the PPA and has therefore recorded $156 million of EBITDA for
the year ended December 31, 2011. The outcome of any arbitration process is not certain, however, TransCanada believes the matter will be resolved in its favour.

70MANAGEMENT'S DISCUSSION AND ANALYSIS

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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
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 $863 million at December 31, 2011. The
fair value of these Bruce Power guarantees at December 31, 2011 is estimated to be $29 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 assurances was estimated at December 31, 2011 to range from $182 million to a maximum of $498 million. The fair value of
these guarantees at December 31, 2011 is estimated to be $7 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 ANALYSIS71

---





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 financial 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:

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 and natural gas. A number
of strategies are used to mitigate these exposures, including the following:

72MANAGEMENT'S DISCUSSION AND ANALYSIS

---



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.

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
interest rates.

A
portion of TransCanada's earnings from its Natural Gas Pipelines, Oil 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, 2011, the Company had designated as a net investment hedge
U.S. dollar-denominated debt with a carrying value of $10 billion (US$9.8 billion) (2010  $9.8 billion (US$9.8 billion)) and a
fair value of $12.7 billion (US$12.5 billion) (2010  $11.3 billion (US$11.4 billion)). At December 31, 2011,
$79 million (December 31, 2010  nil)

MANAGEMENT'S DISCUSSION AND ANALYSIS73

---



was
included in Other Current Assets, $66 million (December 31, 2010  $181 million) was included in Intangibles and Other Assets,
$15 million (December 31, 2010  nil) was included in Accounts Payable, and $41 million (December 31,
2010  nil) was included in Deferred Amounts for the fair value of the forwards and swaps 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)

|                                               |                         | 2011          |    | 2010                         |          |              
|---------------------------------------------- | ----------------------- | ------------- | -- | ---------------------------- | -------- | -------------
|                                               |                         |              
|December 31(millions of dollars)               |                         | Fair Value(1) |    | Notional or
Principal
Amount |          | Fair Value(1)
|                                              
|U.S. dollar cross-currency swaps               |                         |               |    |                              |          |              
|                                               | (maturing 2012 to 2018) |               | 93 |                              | US 3,850 |              
|U.S. dollar forward foreign exchange contracts |                         |               |    |                              |          |              
|                                               | (maturing 2012)         |               | (4 | )                            | US 725   |              
|                                              
|                                               |                         | 89            |    | US 4,575                     |          | 181          
|                                              

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, 2011
(2010  $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 the financial instruments 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

74MANAGEMENT'S DISCUSSION AND ANALYSIS

---



exposures
against these limits, using contract 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, portfolio investments recorded at fair value, 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, and Available for sale assets in the Non-Derivative Financial Instruments Summary table located
in the Fair Values section of this note. The majority of counterparty credit exposure is with counterparties that are investment grade or the exposure is supported by financial assurances provided by
investment grade parties. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At
December 31, 2011, there were no significant amounts past due or impaired, and there were no significant credit losses during the year.

At
December 31, 2011, the Company had a credit risk concentration of $274 million (2010  $317 million) due from a
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.

In
August 2011, the Company received final distributions of 2.1 million common shares, as a result of previous claims in the 2005 Calpine Corporation
bankruptcy. These shares were sold into the open market resulting in total pre-tax gains of $30 million, of which the Company had accrued pre-tax gains of
$15 million in 2010. In 2008, the Company had received 15.5 million common shares which were sold into the open market for $279 million. Claims by NGTL and Foothills PipeLines
(South B.C.) Ltd. for $32 million and $44 million, respectively, were received in cash in 2008 and 2009 and were passed onto the shippers on these systems in 2008 and 2009.

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, 2011, the Company had unutilized committed revolving bank lines of US$1.0 billion, US$1.0 billion, US$300 million and
$2.0 billion maturing in October 2012, November 2012, February 2013 and October 2016, respectively. The Company has also maintained continuous access to the Canadian
commercial paper market on competitive terms and recently initiated a commercial paper program in the U.S.

MANAGEMENT'S DISCUSSION AND ANALYSIS75

---



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 2011, 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 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)                 |  | 2011   |   | 2010   |   | 
|------------------------------------------------ |  | ------ | - | ------ | - | 
|                                                
|Notes payable                                    |  | 1,863  |   | 2,081  |   | 
|Long-term debt                                   |  | 18,567 |   | 17,922 |   | 
|Junior subordinated notes                        |  | 1,009  |   | 985    |   | 
|Cash and cash equivalents                        |  | (654   | ) | (660   | ) | 
|                                                
|Net Debt                                         |  | 20,785 |   | 20,328 |   | 
|                                                
|Equity attributable to non-controlling interests |  | 1,465  |   | 1,157  |   | 
|Equity attributable to controlling interests     |  | 17,324 |   | 16,727 |   | 
|                                                
|Total Equity                                     |  | 18,789 |   | 17,884 |   | 
|                                                
|                                                 |  | 39,574 |   | 38,212 |   | 
|                                                

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 and natural gas 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. The fair value of
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.

76MANAGEMENT'S DISCUSSION AND ANALYSIS

---



Non-Derivative Financial Instruments Summary

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

---

|                                         |  | 2011            |  | 2010       |  |                
|---------------------------------------- |  | --------------- |  | ---------- |  | ---------------
|                                         |  |                
|December 31(millions of dollars)         |  | Carrying Amount |  | Fair Value |  | Carrying Amount
|                                        
|Financial Assets(1)                      |  |                 |  |            |  |                
|Cash and cash equivalents                |  | 765             |  | 765        |  | 764            
|Accounts receivable and other(2)(3)      |  | 1,576           |  | 1,620      |  | 1,555          
|Available for sale assets(2)             |  | 23              |  | 23         |  | 20             
|                                        
|                                         |  | 2,364           |  | 2,408      |  | 2,339          
|                                        
|Financial Liabilities(1)(3)              |  |                 |  |            |  |                
|Notes payable                            |  | 1,880           |  | 1,880      |  | 2,092          
|Accounts payable and deferred amounts(4) |  | 1,536           |  | 1,536      |  | 1,436          
|Accrued interest                         |  | 373             |  | 373        |  | 367            
|Long-term debt                           |  | 18,567          |  | 23,757     |  | 17,922         
|Junior subordinated notes                |  | 1,009           |  | 1,027      |  | 985            
|Long-term debt of joint ventures         |  | 822             |  | 940        |  | 866            
|                                        
|                                         |  | 24,187          |  | 29,513     |  | 23,668         
|                                        

MANAGEMENT'S DISCUSSION AND ANALYSIS77

---



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, 2011:

---

Contractual Repayments of Financial Liabilities(1)

|                                 |  |        |  | Payments Due by Period
|-------------------------------- |  | ------ |  | ----------------------
|                                 |  |        |  |                       
|(millions of dollars)            |  | Total  |  | 2012                  
|                                
|Notes payable                    |  | 1,880  |  | 1,880                 
|Long-term debt                   |  | 18,567 |  | 935                   
|Junior subordinated notes        |  | 1,009  |  |                      
|Long-term debt of joint ventures |  | 822    |  | 33                    
|                                
|                                 |  | 22,278 |  | 2,848                 
|                                

---

Interest Payments on Financial Liabilities

|                                 |  |        |  | Payments Due by Period
|-------------------------------- |  | ------ |  | ----------------------
|                                 |  |        |  |                       
|(millions of dollars)            |  | Total  |  | 2012                  
|                                
|Long-term debt                   |  | 16,541 |  | 1,180                 
|Junior subordinated notes        |  | 355    |  | 65                    
|Long-term debt of joint ventures |  | 343    |  | 48                    
|                                
|                                 |  | 17,239 |  | 1,293                 
|                                

78MANAGEMENT'S DISCUSSION AND ANALYSIS

---



Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments for 2011, excluding hedges of the Company's net investment in self-sustaining foreign operations, is
as follows:

---

|                                                                | 2011             |           |            
|--------------------------------------------------------------- | ---------------- | --------- | -----------
|                                                                |                 
|December 31(all amounts in millions
unless otherwise indicated) | Power            |           | Natural
Gas
|                                                               
|Derivative Financial Instruments Held for Trading(1)            |                  |          
|Fair Values(2)                                                  |                  |           |            
|                                                                | Assets           | $213      |            
|                                                                | Liabilities      | $(212     | )          
|Notional Values                                                 |                  |           |            
|                                                                | Volumes(3)       |           |            
|                                                                |                  | Purchases | 23,500     
|                                                                |                  | Sales     | 23,158     
|                                                                | Canadian dollars |          |            
|                                                                | U.S. dollars     |          |            
|                                                                | Cross-currency   |          |            
|Net unrealized (losses)/gains in the year(4)                    | $(3              | )         | $(50       
|Net realized gains/(losses) in the year(4)                      | $58              |           | $(74       
|Maturity dates                                                  | 2012-2018        |           | 2012-2016  
|Derivative Financial Instruments in Hedging Relationships(5)(6) |                  |           |            
|Fair Values(2)                                                  |                  |           |            
|                                                                | Assets           | $42       |            
|                                                                | Liabilities      | $(277     | )          
|Notional Values                                                 |                  |           |            
|                                                                | Volumes(3)       |           |            
|                                                                |                  | Purchases | 17,188     
|                                                                |                  | Sales     | 9,217      
|                                                                | U.S. dollars     |          |            
|                                                                | Cross-currency   |          |            
|Net realized losses in the year(4)                              | $(150            | )         | $(17       
|Maturity dates                                                  | 2012-2017        |           | 2012-2013  
|                                                               

MANAGEMENT'S DISCUSSION AND ANALYSIS79

---





The anticipated timing of settlement of the derivative contracts assumes constant commodity prices, interest rates and foreign exchange rates from December 31, 2011.
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:

---

|(millions of dollars)                                     |             | Total |      | 2012 |      | 2013
and 2014 |      | 2015
and 2016 |     | 2017 and
Thereafter |     |  
|--------------------------------------------------------- | ----------- | ----- | ---- | ---- | ---- | ------------- | ---- | ------------- | --- | ------------------- | --- | -
|                                                         
|Derivative financial instruments held for trading         |             |       |      |      |      |               |      |               |     |                     |     |  
|                                                          | Assets      |       | 414  |      | 282  |               | 123  |               | 9   |                     |    |  
|                                                          | Liabilities |       | (460 | )    | (292 | )             | (151 | )             | (17 | )                   |    |  
|Derivative financial instruments in hedging relationships |             |       |      |      |      |               |      |               |     |                     |     |  
|                                                          | Assets      |       | 217  |      | 121  |               | 91   |               | 5   |                     |    |  
|                                                          | Liabilities |       | (408 | )    | (208 | )             | (135 | )             | (50 | )                   | (15 | )
|                                                         
|                                                          |             | (237  | )    | (97  | )    | (72           | )    | (53           | )   | (15                 | )   |  
|                                                         

80MANAGEMENT'S DISCUSSION AND ANALYSIS

---



Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments for 2010, excluding hedges of the Company's net investment in self-sustaining foreign operations, is
as follows:

---

|                                                                 |                  | 2010     
|---------------------------------------------------------------- | ---------------- | ---------
|                                                                 |                  |          
|December 31 (all amounts in millions
unless otherwise indicated) |                  | Power    
|                                                                
|Derivative Financial Instruments Held for Trading(1)             |                  |          
|Fair Values(2)                                                   |                  |          
|                                                                 | Assets           |          
|                                                                 | Liabilities      |          
|Notional Values                                                  |                  |          
|                                                                 | Volumes(3)       |          
|                                                                 |                  | Purchases
|                                                                 |                  | Sales    
|                                                                 | Canadian dollars |          
|                                                                 | U.S. dollars     |          
|                                                                 | Cross-currency   |          
|Net unrealized (losses)/gains in the year(4)                     |                  | $(32     
|Net realized gains/(losses) in the year(4)                       |                  | $77      
|Maturity dates                                                   |                  | 2011-2015
|Derivative Financial Instruments in Hedging Relationships(5)(6)  |                  |          
|Fair Values(2)                                                   |                  |          
|                                                                 | Assets           |          
|                                                                 | Liabilities      |          
|Notional Values                                                  |                  |          
|                                                                 | Volumes(3)       |          
|                                                                 |                  | Purchases
|                                                                 |                  | Sales    
|                                                                 | U.S. dollars     |          
|                                                                 | Cross-currency   |          
|Net realized losses in the year(4)                               |                  | $(9      
|Maturity dates                                                   |                  | 2011-2015
|                                                                

MANAGEMENT'S DISCUSSION AND ANALYSIS81

---



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)     |  | 2011 |   | 2010 |   | 
|------------------------------------ |  | ---- | - | ---- | - | 
|                                    
|Current                              |  |      |   |      |   | 
|Other current assets                 |  | 404  |   | 273  |   | 
|Accounts payable                     |  | (502 | ) | (337 | ) | 
|Long Term                            |  |      |   |      |   | 
|Intangibles and other assets(Note 9) |  | 213  |   | 374  |   | 
|Deferred amounts(Note 11)            |  | (352 | ) | (282 | ) | 
|                                    

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 derivatives was $35 million at December 31, 2011
(2010  $48 million). These contracts mature from 2012 to 2018. The Company's proportionate share of the notional sales volumes of power associated with
this exposure was 2,979 GWh at December 31, 2011 (2010  3,772 GWh). The Company's proportionate share of the notional purchased volumes of
power associated with this exposure was 1,595 GWh at December 31, 2011 (2010  2,322 GWh).

Derivatives in Cash Flow Hedging Relationships

Information about how derivatives and hedging activities affect the Company's financial position, financial performance and cash flows is as follows:

|                                                                                                           |  | Cash Flow Hedges
|---------------------------------------------------------------------------------------------------------- |  | ----------------
|                                                                                                           |  |                 
|                                                                                                           |  | Power           
|                                                                                                           |  |                 
|Year ended December 31 (millions of Canadian dollars, pre-tax)                                             |  | 2011            
|                                                                                                          
|Change in fair value of derivative instruments recognized in OCI (effective portion)                       |  | (252            
|Reclassification of gains and losses on derivative instruments from AOCI to Net Income (effective portion) |  | 61              
|                                                                                                          

82MANAGEMENT'S DISCUSSION AND ANALYSIS

---



Credit Risk Related Contingent Features

Derivative contracts entered into to manage market risk often contain financial assurance 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, 2011, the aggregate fair value of all derivative instruments with credit-risk-related contingent features
that were in a net liability position was $110 million (2010  $92 million), for which the Company has provided collateral of $28 million
(2010  $4 million) in the normal course of business. If the credit-risk-related contingent features in these agreements were
triggered on December 31, 2011, the Company would have been required to provide additional collateral of $82 million (2010  $88 million) to
its counterparties. Collateral may also need to be provided should the fair value of derivative financial 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.

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 inputs 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 2011 or 2010. 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)    |                            | 2011                                      |      | 2010                                           |      | 2011                                        |      | 2010  |      | 2011
|                                            
|Natural Gas Inventory                        |                            |                                          |      |                                               |      | 29                                          |      | 49    |      |    
|Derivative Financial Instrument Assets:      |                            |                                           |      |                                                |      |                                             |      |       |      |     
|                                             | Interest rate contracts    |                                           |     |                                                |     |                                             | 35   |       | 28   |     
|                                             | Foreign exchange contracts |                                           | 11   |                                                | 10   |                                             | 131  |       | 179  |     
|                                             | Power commodity contracts  |                                           |     |                                                |     |                                             | 244  |       | 269  |     
|                                             | Gas commodity contracts    |                                           | 124  |                                                | 93   |                                             | 55   |       | 56   |     
|Derivative Financial Instrument Liabilities: |                            |                                           |      |                                                |      |                                             |      |       |      |     
|                                             | Interest rate contracts    |                                           |     |                                                |     |                                             | (23  | )     | (47  | )   
|                                             | Foreign exchange contracts |                                           | (13  | )                                              | (11  | )                                           | (89  | )     | (54  | )   
|                                             | Power commodity contracts  |                                           |     |                                                |     |                                             | (465 | )     | (299 | )   
|                                             | Gas commodity contracts    |                                           | (208 | )                                              | (178 | )                                           | (26  | )     | (15  | )   
|Non-Derivative Financial Instruments:        |                            |                                           |      |                                                |      |                                             |      |       |      |     
|                                             | Available-for-sale assets  |                                           | 23   |                                                | 20   |                                             |     |       |     |     
|                                            
|                                             |                            | (63                                       | )    | (66                                            | )    | (109                                        | )    | 166   |      | (13 
|                                            

MANAGEMENT'S DISCUSSION AND ANALYSIS83

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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, 2009                                   |  | (2             | ) | 
|New contracts(2)                                               |  | (16            | ) | 
|Settlements                                                    |  | (3             | ) | 
|Transfers into Level III(3)                                    |  | 3              |   | 
|Transfers out of Level III(3)(4)                               |  | (38            | ) | 
|Change in unrealized gains recorded in Net Income              |  | 14             |   | 
|Change in fair value of derivative instruments recorded in OCI |  | 39             |   | 
|                                                              
|Balance at December 31, 2010                                   |  | (3             | ) | 
|New contracts(2)                                               |  | 1              |   | 
|Settlements                                                    |  | 1              |   | 
|Transfers out of Level III(3)(4)                               |  | (1             | ) | 
|Change in unrealized gains recorded in Net Income              |  | 1              |   | 
|Change in fair value of derivative instruments recorded in OCI |  | (12            | ) | 
|                                                              
|Balance at December 31, 2011                                   |  | (13            | ) | 
|                                                              

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a
$10 million decrease or increase, respectively, in the fair value of outstanding derivative financial instruments included in Level III as at December 31, 2011.

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.

84MANAGEMENT'S DISCUSSION AND ANALYSIS

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Operational and Other Business Risks

There are a number of operating risks associated with TransCanada's pipelines and energy businesses including: labour disputes; the breakdown or failure of equipment; acts of
terror; and catastrophic events such as natural disasters. The occurrence or continuance of any of these events could impact earnings through the costs associated with remediation or a reduction
in revenues.

The
Company has established emergency response plans to address certain unplanned events, which include an ongoing program to provide local emergency responders with the
information and training necessary to ensure their preparedness for responding to events. TransCanada maintains a comprehensive insurance program to mitigate the risk of potential losses arising from
operational risks and other potential losses related to its
business. In certain circumstances, not all events will be covered by insurance, which may have an adverse effect on the Company's operations, earnings, cash flow and financial position.

Health, Safety and Environment Risk Management

Health, safety and environment (HSE) are top priorities in all of TransCanada's operations and business activities. These areas are guided by the Company's HSE 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 HSE 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 the public and the environment. The Company is committed to continually improving its HSE 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 and expectation on HSE performance and will
influence them to improve their collective performance and culture. TransCanada is committed to respecting the diverse environments and cultures in which it operates and to supporting open
communication with its stakeholders.

The
HSE Committee of TransCanada's Board of Directors monitors compliance with the Company's HSE corporate policy through regular reporting. TransCanada's integrated HSE
management system is modeled after the International Organization for Standardization (ISO) standard for environmental management systems, ISO 14001; and the Occupational Health and Safety
Assessment Series (OHSAS 18001) for occupational health and safety. TransCanada's HSE management system conforms to external industry consensus standards and voluntary regulatory programs and
complies with applicable legislated requirements and various other internal management systems. Resources are focused on the areas of significant risk to the organization's HSE business activities.
Management is informed regularly of all important and/or significant HSE operational issues and initiatives through formal reporting and incident management processes. TransCanada's HSE management
system and performance are assessed by an independent outside firm every three years. The most recent assessment occurred in 2009 and did not identify any material issues. The HSE management system is
subject to ongoing internal and external 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 2011, one of the Company's objectives was to sustain health and safety
performance year over year. Overall, the Company's safety frequency rates in 2011 continued to be better than most industry benchmarks.

The
safety and integrity of the Company's existing and newly-developed infrastructure is also a top priority. All new assets are designed, constructed and commissioned with
full consideration given to safety and integrity, and are brought in service only after all necessary requirements have been satisfied. The Company expects to spend approximately $322 million
in 2012 for pipeline integrity on the pipelines it operates, an increase of approximately $78 million over 2011 primarily due to increased levels of in-line pipeline inspection on
all systems. 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

MANAGEMENT'S DISCUSSION AND ANALYSIS85

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contracts,
pipeline integrity expenditures are recovered through the tolling mechanism and, as a result, these expenditures have no impact on TransCanada's earnings. TransCanada's pipeline safety
record in 2011 continued to be better than industry benchmarks. TransCanada experienced two pipeline breaks in 2011 on its operated pipelines. The first break occurred in a remote part of Northern
Ontario on the Canadian Mainline pipeline system. The second break occurred in a remote part of Wyoming on the Bison pipeline system.

Spending
associated with public safety on the Energy assets is focused primarily on the Company's hydro dams and associated equipment, and is slightly higher than previous
years due to increased spending to repair damage from the high flow events of 2011 caused by Hurricane Irene.

Environment

TransCanada's facilities are subject to stringent federal, state, provincial, and local environmental statutes and regulations governing environmental protection, including,
but not limited to, air emissions, water quality, wastewater discharges and waste management. Such laws and regulations generally require facilities to obtain or comply with a wide variety of
environmental registrations, licences, permits and other approvals and requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil 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, 2011, TransCanada recorded liabilities of approximately $69 million (2010  $84 million) for
remediation obligations and compliance costs associated with certain 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.

The
Company owns 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 comply with these regulations.

In
Alberta, under theSpecified Gas Emitters Regulation, industrial facilities emitting GHG emissions over an intensity
threshold level are required to reduce the intensity of GHG emissions 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 certain rights under the PPAs. TransCanada has a program in place to manage the compliance costs
incurred by these assets as a result of the 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 GHG emissions related costs of
$13 million for 2011 (2010  $22 million), 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 2011, 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
carbon tax in B.C., which came into effect in mid-2008, applies to carbon dioxide (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 2011 were approximately $3 million
(2010  $4 million). The cost per tonne of CO2 will be increased in July 2012 to $30 from $25.

States
in the northeastern U.S. 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 were 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

86MANAGEMENT'S DISCUSSION AND ANALYSIS

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State
Power generation facilities and incurred related costs of $4 million in 2011 (2010  $5 million). These costs were generally recovered through
the power market and the net impact on TransCanada was not significant.

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.

Environmental
risks from TransCanada's operating facilities typically include: air emissions, GHG emissions; potential impacts on land, including land reclamation or
restoration following construction; the use, storage and release of hydrocarbons or other chemicals; the generation, handling and disposal of wastes and hazardous wastes; and water impacts such as
uncontrolled water discharge.

The
Company'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:

The
impact of new or proposed federal, state, and/or provincial 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 for 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.

Regulation
of air pollutant emissions under theU.S. Clean Air Actand state regulations continue to evolve. A number
of EPA initiatives could lead to impacts ranging from requirements to install enhanced 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 federal, regional, state, 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.

In
August 2011, the Canadian government published the first sector specific draft regulation that will impact industrial GHG emissions. This proposed regulation is
focused on the coal-fired generation of electricity and requires a natural gas performance standard for all coal-fired facilities reaching the end of their economic life. The
draft regulation is expected to come into effect in July 2015. This process is not expected to pose a significant risk or financial impact to TransCanada's existing facilities and may present
opportunities for new power generation investment. Additional sectors,

MANAGEMENT'S DISCUSSION AND ANALYSIS87

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including
the natural gas-fired generation of electricity and upstream oil and gas facility sectors, are expected to begin consultations with Environment Canada.

The
Western Climate Initiative (WCI) continues to work toward implementing a regional cap-and-trade program. California and Québec are
the only WCI members with cap and trade regulations. In December 2011, the Government of Québec adopted the "Regulation respecting the cap-and-trade
system for greenhouse gas emission allowances". The initial phase of the cap and trade system will begin January 1, 2013. The regulation will have a limited impact on TransCanada's
Bécancour power generation facility and natural gas pipeline assets. With respect to California, the Air Resources Board adopted a cap and trade regulation in October 2011. The
regulation is divided into two phases: the first, beginning in 2013, will include all major industrial sources and electricity utilities; the second, starting in 2015, will cover distributors of
transportation fuels, natural gas and other fuels. The regulation may impact the Company's importation of electricity into the state.

Future Abandonment Costs

Depending 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 recognizes the fair value of a liability for asset retirement obligations (ARO), which is
accreted through changes to operating expenses. The Company recorded ARO 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 ARO include scope of abandonment and reclamation activities,
inflation rates, discount rates and timing of asset retirements. By their nature, these assumptions are subject to measurement uncertainty. The Company has determined that the scope and timing of
asset retirements related to its U.S. regulated natural gas pipelines, oil pipelines and hydroelectric power plants is indeterminable. As a result, the Company has not recorded amounts for ARO
related to these assets, with the exception of certain abandoned facilities.

The
NEB's LMCI 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
filed its estimates of abandonment costs for its Canadian oil and natural gas pipelines in November 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. In addition, as the actual timing of retirements for the assets is indeterminable, the Company
has not recorded amounts for ARO.

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, 2011, 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

88MANAGEMENT'S DISCUSSION AND ANALYSIS

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concluded
that, as at December 31, 2011, 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 CGAAP,
including a reconciliation to U.S. generally accepted accounting principles (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, 2011, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

In
2011, 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.

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 2011 reports filed with the SEC and the Canadian securities regulators.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

To prepare financial statements that conform with CGAAP, 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. A summary of TransCanada's significant accounting
policies can be found in Note 2 to the Consolidated Financial Statements. 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 CGAAP. The following three criteria must be met to use these accounting principles:

MANAGEMENT'S DISCUSSION AND ANALYSIS89

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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 (RRA) 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 CGAAP in order to appropriately reflect the economic impact of the regulators' decisions regarding the
Company's revenues and tolls. At December 31, 2011, the Company reported regulatory assets of $0.2 billion and $1.4 billion in Other Current Assets and Regulatory Assets,
respectively (2010  $0.3 billion and $1.5 billion, respectively), and regulatory liabilities of $0.1 billion and $0.3 billion in
Accounts Payable and Regulatory Liabilities, respectively (2010  $0.1 billion and $0.3 billion, respectively).

Financial Instruments and Hedges

Financial Instruments

The Company initially records all financial instruments on the Balance Sheet at 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.

Held
for trading derivative financial assets and liabilities consist of swaps, options, forwards and futures with changes in the fair value recorded in Net Income. 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 with changes in
the fair value recorded in Other Comprehensive (Loss)/Income (OCI). 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 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.

Hedges

The Company applies hedge accounting to arrangements that qualify for hedge accounting treatment, which include fair value and cash flow hedges, and hedges of foreign currency
exposures of net investments in self-sustaining foreign operations. Hedge accounting is discontinued prospectively when the hedging relationship ceases to be effective or the hedging or
hedged items cease to exist as a result of maturity, expiry, sale, termination or cancellation.

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 initially recognized in OCI, 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 it is probable the anticipated transaction will not occur.

The
Company also enters into cash flow hedges and fair value hedges for activities subject to rate regulation in Canada. 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 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.

90MANAGEMENT'S DISCUSSION AND ANALYSIS

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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 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 in certain circumstances, fluctuations can result in variability in Net Income.

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 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 2011 was $1,528 million (2010  $1,354 million;
2009  $1,377 million) and was recorded in Natural Gas Pipelines, Oil Pipelines, Energy and Corporate. 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 2009 through 2011.

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, 2011, the Company reported Goodwill of $3.7 billion (2010  $3.6 billion). Goodwill 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 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS91

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These
valuations are based on management's projections of future cash flows and, therefore, require estimates and assumptions with respect to:

Significant
changes in these assumptions could affect the Company's requirement to record an impairment charge. In addition to the above noted estimates and assumptions used
by the Company in its fair value determinations, the realization of Ravenswood's fair value is partially dependent on a favourable resolution of the NYISO actions relating to capacity prices as
described further in Energy  Opportunities and Developments. An unfavourable outcome could have a negative effect on the estimated fair value and may, in future
periods, result in an impairment of a portion of the US$834 million Goodwill balance relating to Ravenswood at December 31, 2011
(2010  US$834 million).

ACCOUNTING CHANGES

CHANGES IN ACCOUNTING POLICIES FOR 2011

Business Combinations

Effective January 1, 2011, the Company adopted CICA Handbook Section 1582 "Business Combinations", which 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, expensing of
acquisition costs, and increased disclosure. Adoption of this standard had no effect on the financial statements as at and for the year ended December 31, 2011.

Consolidated Financial Statements and Non-Controlling Interests

Entities adopting Section 1582 were also required to adopt CICA Handbook Sections 1601 "Consolidated Financial Statements" and 1602 "Non-Controlling
Interests". Sections 1601 and 1602 require Non-Controlling Interests to be presented as part of Equity on the balance sheet. In addition, the income statement of the controlling parent now
includes 100 per cent of the subsidiary's results and presents the allocation of net income between the controlling and non-controlling interests. Changes resulting fromt he adoption of
Sections 1601 and 1602 were applied retrospectively.

FUTURE ACCOUNTING CHANGES

U.S. GAAP

The CICA's Accounting Standards Board previously announced that Canadian publicly accountable enterprises were required to adopt International Financial Reporting Standards
(IFRS) effective January 1, 2011, with the exception of certain qualifying entities historically using RRA that were given a one year deferral from adopting IFRS. TransCanada is a qualifying
entity for these purposes and has deferred the adoption of IFRS. The Company has prepared its consolidated financial statements for 2011 in accordance with CGAAP in order to continue using RRA.

In
the application of CGAAP, TransCanada follows specific accounting guidance under U.S. GAAP unique to rate-regulated businesses. These RRA standards
allow the timing of recognition of certain revenues and expenses to differ from the timing that may otherwise be expected in a non-rate-regulated business under CGAAP in order
to

92MANAGEMENT'S DISCUSSION AND ANALYSIS

---



appropriately
reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. The International Accounting Standards Board has concluded that the development of RRA
under IFRS requires further analysis and TransCanada does not expect a final RRA standard under IFRS to be effective in the foreseeable future.

As
a registrant with the SEC, TransCanada has the option under Canadian disclosure rules to prepare and file its consolidated financial statements using U.S. GAAP. As
a result of the developments noted above, the Company's Board of Directors has approved the adoption of U.S. GAAP effective January 1, 2012. The financial reporting impact of TransCanada
adopting U.S. GAAP is disclosed in Note 25 of the Consolidated Financial Statements. The differences between CGAAP and U.S. GAAP are consistent with those reported by the Company
in its annual "Reconciliation to United States GAAP" as filed in prior years. Significant changes to existing systems and processes are not required to implement U.S. GAAP as the
Company's primary accounting framework.

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board (FASB) issued amended guidance on fair value measurements, which updated some of the existing measurement guidance
and included enhanced disclosure requirements under U.S. GAAP. This guidance is effective for interim and annual periods beginning after December 15, 2011. Adoption of these amendments
is expected to result in an increase in the qualitative and quantitative disclosures regarding Level 3 measurements, however, the Company expects no material effect on the financial statements.

Intangibles  Goodwill and Other

In September 2011, the FASB issued new guidance on testing goodwill for impairment which simplifies an entity's testing for goodwill impairment under U.S. GAAP by
permitting an entity to first assess qualitative factors affecting the fair value of a reporting unit in comparison to the carrying amount, as a basis for determining whether it is required to proceed
to the two-step quantitative goodwill impairment test. This guidance is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after
December 15, 2011. Adoption is not expected to impact the financial statements.

Balance Sheet Offsetting/Netting

In December 2011, the FASB issued amended guidance to enhance disclosures that will enable users of the financial statements to evaluate the effect, or potential effect,
of netting arrangements on an entity's financial position. The amendments result in enhanced disclosures by requiring additional information regarding financial instruments and derivative instruments
that are either offset in accordance with current U.S. GAAP or subject to an enforceable master netting agreement. This guidance is effective for annual periods beginning on or after
January 1, 2013. Adoption of these amendments is expected to result in an increase in disclosures regarding financial instruments which are subject to offsetting as described in
this amendment.

MANAGEMENT'S DISCUSSION AND ANALYSIS93

---



---

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA(1)

|                                                           |                                          | 2011  
|---------------------------------------------------------- | ---------------------------------------- | ------
|                                                           |                                          |       
|(unaudited)
(millions of dollars except per share amounts) |                                          | Fourth
|                                                          
|Revenues                                                   |                                          | 2,360 
|Net Income Attributable to Common Shares                   |                                          | 375   
|Share Statistics                                           |                                          |       
|                                                           | Net income per share  basic and diluted |       
|                                                           | Dividend declared per common share       |       
|                                                          

|
|

|                                                           |                                          | 2010  
|---------------------------------------------------------- | ---------------------------------------- | ------
|                                                           |                                          |       
|(unaudited)
(millions of dollars except per share amounts) |                                          | Fourth
|                                                          
|Revenues                                                   |                                          | 2,057 
|Net Income Attributable to Common Shares                   |                                          | 269   
|Share Statistics                                           |                                          |       
|                                                           | Net income per share  basic and diluted |       
|                                                           | Dividend declared per common share       |       
|                                                          

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 prices and 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 2011 and 2010 were as follows:

94MANAGEMENT'S DISCUSSION AND ANALYSIS

---



MANAGEMENT'S DISCUSSION AND ANALYSIS95

---





FOURTH QUARTER 2011 HIGHLIGHTS

---

Reconciliation of Non-GAAP Measures

|                                                                |                               | Natural Gas
Pipelines |   | Oil
Pipelines |   | Energy |   | Corporate |  | Total |   |     
|--------------------------------------------------------------- | ----------------------------- | --------------------- | - | ------------- | - | ------ | - | --------- |  | ----- | - | ----
|                                                                |                               |                       |   |              
|Three months ended
December 31(unaudited)
(millions of dollars) |                               | 2011                  |   | 2010          |   | 2011   |   | 2010      |  | 2011  |   | 2010
|                                                               
|Comparable EBITDA                                               |                               | 739                   |   | 737           |   | 179    |   |          |  | 295   |   | 301 
|Depreciation and amortization                                   |                               | (251                  | ) | (241          | ) | (35    | ) |          |  | (100  | ) | (103
|                                                               
|Comparable EBIT                                                 |                               | 488                   |   | 496           |   | 144    |   |          |  | 195   |   | 198 
|                                                                |                               |                       |   |               |   |       
|Other Income Statement Items                                    |                               |                       |   |               |   |        |   |           |  |       |   |     
|Comparable interest expense                                     |                               |                       |   |               |   |        |   |           |  |       |   |     
|Interest expense of joint ventures                              |                               |                       |   |               |   |        |   |           |  |       |   |     
|Comparable interest income and other                            |                               |                       |   |               |   |        |   |           |  |       |   |     
|Comparable income taxes                                         |                               |                       |   |               |   |        |   |           |  |       |   |     
|Net income attributable to non-controlling interests            |                               |                       |   |               |   |        |   |           |  |       |   |     
|Preferred share dividends                                       |                               |                       |   |               |   |        |   |           |  |       |   |     
|                                                               
|Comparable Earnings                                             |                               |                       |   |               |   |        |   |           |  |       |   |     
|Specific items (net of tax):                                    |                               |                       |   |               |   |        |   |           |  |       |   |     
|                                                                | Valuation provision for MGP   |                       |   |               |   |        |   |           |  |       |   |     
|                                                                | Risk management activities(1) |                       |   |               |   |        |   |           |  |       |   |     
|                                                               
|Net Income Attributable to Common Shares                        |                               |                       |   |               |   |        |   |           |  |       |   |     
|                                                               

|
|

|Three months ended December 31 (unaudited)(millions of dollars except per share amounts) |                               | 2011  |      | 2010  |       |  
|---------------------------------------------------------------------------------------- | ----------------------------- | ----- | ---- | ----- | ----- | -
|                                                                                        
|Comparable Interest Income and Other                                                     |                               | 8     |      | 61    |       |  
|Specific item:                                                                           |                               |       |      |       |       |  
|Risk management activities(1)                                                            |                               | 35    |      |      |       |  
|                                                                                        
|Interest Income and Other                                                                |                               | 43    |      | 61    |       |  
|                                                                                        
|Comparable Income Taxes                                                                  |                               | (123  | )    | (103  | )     |  
|Specific items:                                                                          |                               |       |      |       |       |  
|                                                                                         | Valuation provision for MGP   |       |     |       | 19    |  
|                                                                                         | Risk management activities(1) |       |     |       | (10   | )
|                                                                                        
|Income Taxes Expense                                                                     |                               | (123  | )    | (94   | )     |  
|                                                                                        
|Comparable Earnings per Common Share                                                     |                               | $0.52 |      | $0.55 |       |  
|Specific items (net of tax):                                                             |                               |       |      |       |       |  
|                                                                                         | Valuation provision for MGP   |       |     |       | (0.18 | )
|                                                                                         | Risk management activities(1) |       | 0.01 |       | 0.02  |  
|                                                                                        
|Net Income per Common Share                                                              |                               | $0.53 |      | $0.39 |       |  
|                                                                                        

(unaudited)(millions of dollars)

2011

2010Risk Management Activities Gains/(Losses):U.S. Power derivatives

(33
)
24Natural Gas Storage proprietary inventory and derivatives

7

(2
)Foreign exchange derivatives

35

Income taxes attributable to risk management activities



(10
)Risk Management Activities

9

12


96MANAGEMENT'S DISCUSSION AND ANALYSIS

---



Comparable Earnings in fourth quarter 2011 were $366 million or $0.52 per share compared to $384 million or $0.55 per
share for the same period in 2010. Comparable Earnings in fourth quarter 2011 excluded net unrealized after-tax gains of $9 million ($9 million pre-tax)
(2010  $12 million after-tax gains; $22 million pre-tax) resulting from changes in the fair value of certain risk
management activities. Comparable Earnings in fourth quarter 2010 also excluded the $127 million after tax ($146 million pre-tax) valuation provision on advances to the APG
for the MGP.

Comparable
Earnings decreased $18 million or $0.03 per share in fourth quarter 2011 compared to the same period in 2010 and included the following:

TransCanada's
Net Income Attributable to Common Shares was $375 million or $0.53 per share in fourth quarter 2011 compared to $269 million or $0.39 per share
in fourth quarter 2010.

Natural
Gas Pipelines' Comparable EBIT was $488 million in fourth quarter 2011 compared to $496 million for the same period in 2010. Comparable EBIT in 2010
excluded a $146 million pre-tax valuation provision on advances to the APG for the MGP.

Canadian
Mainline's net income in fourth quarter 2011 decreased $11 million to $60 million compared to the same period in 2010. This decrease was primarily due
to lower incentive earnings, a lower ROE as determined by the NEB of 8.08 per cent in 2011 compared to 8.52 per cent in 2010, as well as a lower average
investment base.

The
Alberta System's net income of $51 million in fourth quarter 2011 decreased $2 million compared to the same period in 2010. The lower net income was
primarily due to lower incentive earnings, partially offset by the positive impact of a higher average investment base.

Canadian
Mainline's Comparable EBITDA of $262 million in fourth quarter 2011 decreased $7 million compared to the same period in 2010. The Alberta System's
Comparable EBITDA was $185 million in fourth quarter 2011 compared to $194 million for the same period in 2010. EBITDA from the Canadian Mainline and the Alberta System includes net
income variances discussed above as well as flow through items which do not affect net income.

ANR's
Comparable EBITDA in fourth quarter 2011 was US$73 million compared to US$76 million for the same period in 2010. The decrease in fourth quarter 2011 was
primarily due to higher OM&A costs.

GTN's
Comparable EBITDA in fourth quarter 2011 from TransCanada's direct investment was US$26 million compared to US$45 million for the same period in 2010.
The decrease was primarily due to TransCanada's sale of a 25 per cent interest in GTN to TC PipeLines, LP in May 2011 and lower revenues.

MANAGEMENT'S DISCUSSION AND ANALYSIS97

---



The
Bison pipeline was placed in service on January 14, 2011. TransCanada's portion of Comparable EBITDA from its direct investment was US$14 million in fourth
quarter 2011. EBITDA reflects TransCanada's 75 per cent direct interest in Bison subsequent to the sale of a 25 per cent interest in Bison to TC PipeLines, LP in
May 2011 and 100 per cent prior to that date.

Comparable
EBITDA from the remainder of the U.S. Natural Gas Pipelines was US$145 million in fourth quarter 2011 compared to US$128 million for the same
period in 2010. The increases were primarily due to incremental earnings from the Guadalajara pipeline, which was placed in service in June 2011. In addition, lower general, administrative and
support costs increased EBITDA in fourth quarter 2011, offset by lower earnings from Great Lakes and Portland.

Natural
Gas Pipelines' Depreciation and Amortization increased $10 million in fourth quarter 2011 compared to the same period in 2010 primarily due to the Guadalajara
and Bison pipelines being placed in service in 2011.

Natural
Gas Pipelines' Business Development Comparable EBITDA losses, resulting from business development expenses, decreased $6 million in fourth quarter 2011
compared to the same period in 2010 primarily due to decreased business development costs related to the Alaska Pipeline Project. Project applicable expenses and reimbursements are shared
proportionately with ExxonMobil, TransCanada's joint venture partner in developing the Alaska Pipeline Project.

Oil
Pipelines Comparable EBIT in fourth quarter 2011 was $144 million. At the beginning of February 2011, the Company commenced recording EBITDA for the Wood
River/Patoka section of Keystone following the NEB's decision to remove the MOP restriction along the conversion section of the system and completion of the required operational modifications. The
Cushing Extension was also placed in service at that time.

Energy's
Comparable EBIT was $195 million in fourth quarter 2011 compared to $198 million for the same period in 2010.

Western
Power's Comparable EBITDA of $143 million and Power revenues of $294 million in fourth quarter 2011 increased $95 million and
$114 million, respectively, compared to the same period in 2010, primarily due to higher overall realized power prices in Alberta and incremental earnings from Coolidge, which went in service
under a 20-year PPA in May 2011. Plant outages and higher demand resulted in average spot market power prices in Alberta increasing 65 per cent to $76 per MWh in
fourth quarter 2011 compared to $46 per MWh in fourth quarter 2010.

Western
Power's Comparable EBITDA in fourth quarter 2011 included $57 million of accrued earnings from the Sundance A PPA, the revenues and costs of which have been
recorded as though the outages of Sundance A Units 1 and 2 were interruptions of supply in accordance with the terms of the PPA.

Eastern
Power's Comparable EBITDA of $87 million and Power Revenues of $125 million in fourth quarter 2011 increased $10 million and $12 million,
respectively, compared to the same period in 2010 primarily due to higher Bécancour contractual earnings.

TransCanada's
proportionate share of Bruce A's Comparable EBITDA decreased $34 million to a loss of $1 million in fourth quarter 2011 compared to EBITDA of
$33 million in fourth quarter 2010. The decrease was primarily due to lower volumes reflecting the November 6, 2011 commencement of the approximate six-month West Shift Plus
planned outage as part of the life extension strategy for Unit 3.

TransCanada's
proportionate share of Bruce B's Comparable EBITDA decreased $32 million to $34 million in fourth quarter 2011 compared to $66 million in
fourth quarter 2010 due to higher operating costs, lower volumes due to increased planned outage days and lower realized prices resulting from the expiry of fixed-price contracts at
higher prices.

U.S. Power's
Comparable EBITDA in fourth quarter 2011 of US$32 million decreased US$27 million compared to the same period in 2010 primarily due to the
negative impact of lower commodity and capacity prices and lower physical sales volumes partially offset by new sales activity in PJM.

98MANAGEMENT'S DISCUSSION AND ANALYSIS

---



Natural
Gas Storage's Comparable EBITDA in fourth quarter 2011 was $23 million compared to $37 million for the same period in 2010. The decrease of
$14 million in Comparable EBITDA in fourth
quarter 2011 was primarily due to decreased proprietary natural gas and third party storage revenues as a result of lower realized natural gas price spreads.

Comparable
Interest Expense in fourth quarter 2011 increased $78 million to $251 million from $173 million in fourth quarter 2010. The increase
primarily reflected lower capitalized interest upon placing Keystone and other new assets in service in 2011.

Comparable
Interest Income and Other in fourth quarter 2011 decreased $53 million to $8 million from income of $61 million in fourth quarter 2010. The
decrease in fourth quarter reflected realized losses in 2011 compared to gains in 2010 on derivatives used to manage the Company's net exposure to foreign exchange rate fluctuations on
U.S. dollar-denominated income.

Comparable
Income Taxes were $123 million in fourth quarter 2011 compared to $103 million for the same period in 2010. The increase was primarily due to higher
positive income tax adjustments that reduced income taxes in fourth quarter 2010 compared to 2011.

SHARE INFORMATION

At February 8, 2012, TransCanada had 704 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 seven million outstanding options to purchase common shares, of which five million were
exercisable as at February 8, 2012.

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 2007 to 2011 is found under the heading "Five Year Financial Highlights" in the Supplementary Information section of
the Company's Annual Report.

MANAGEMENT'S DISCUSSION AND ANALYSIS99

---





GLOSSARY OF TERMS

|AFUDC                   |  | Allowance for funds used during construction                                                                                                                                                                                                                                                                 
|----------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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                                                                                                                                                                                                                                                                
|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,
Indiana and Ohio, and regulated underground natural gas storage facilities in Michigan
|APG                     |  | Aboriginal Pipeline Group                                                                                                                                                                                                                                                                                    
|ARO                     |  | Asset retirement obligation                                                                                                                                                                                                                                                                                  
|ATWACC                  |  | After-tax weighted average cost of capital                                                                                                                                                                                                                                                                   
|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                                                                                                                                                                                                   
|Bison LLC               |  | Bison Pipeline LLC                                                                                                                                                                                                                                                                                           
|BPC                     |  | BPC Generation Infrastructure Trust                                                                                                                                                                                                                                                                          
|BPRIA                   |  | Bruce Power Refurbishment Implementation Agreement                                                                                                                                                                                                                                                           
|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)                                                                                                                                                                                                
|Canadian Mainline       |  | A natural gas transmission system extending from the Alberta/Saskatchewan border east into Québec                                                                                                                                                                                                            
|Cancarb                 |  | A waste-heat fuelled power plant and 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, four plus the first phase of the fifth which are operational and phase two of the fifth under construction                                                                                                                                                                 
|CFE                     |  | Comisión Federal de Electricidad                                                                                                                                                                                                                                                                             
|CGAAP                   |  | Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants Handbook                                                                                                                                                                           
|CICA                    |  | Canadian Institute of Chartered Accountants                                                                                                                                                                                                                                                                  
|CO2                     |  | Carbon dioxide                                                                                                                                                                                                                                                                                               
|Coolidge                |  | A simple-cycle, natural gas-fired peaking power generation station in Coolidge, Arizona                                                                                                                                                                                                                      
|COSO                    |  | Committee of Sponsoring Organizations of the Treadway Commission                                                                                                                                                                                                                                             
|CrossAlta               |  | An underground natural gas storage facility near Crossfield, Alberta                                                                                                                                                                                                                                         
|CSP                     |  | Contingent Support Payments                                                                                                                                                                                                                                                                                  
|Cushing Extension       |  | A crude oil pipeline extending from Steele City, Nebraska to Cushing, Oklahoma                                                                                                                                                                                                                               
|DB Plans                |  | Defined benefit pension plans                                                                                                                                                                                                                                                                                
|DC Plans                |  | Defined contribution pension plans                                                                                                                                                                                                                                                                           
|DOS                     |  | U.S. Department of State                                                                                                                                                                                                                                                                                     
|DRP                     |  | Dividend Reinvestment and Share Purchase Plan                                                                                                                                                                                                                                                                
|EBIT                    |  | Earnings before interest and taxes                                                                                                                                                                                                                                                                           
|EBITDA                  |  | Earnings before interest, taxes, depreciation and amortization                                                                                                                                                                                                                                               

100MANAGEMENT'S DISCUSSION AND ANALYSIS

---



|Edson                       |  | An underground natural gas storage facility near Edson, Alberta                                                                                                                                                                                                                                                                                              
|--------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|EPA                         |  | Environmental Protection Agency (U.S.)                                                                                                                                                                                                                                                                                                                       
|ExxonMobil                  |  | Exxon Mobil Corporation                                                                                                                                                                                                                                                                                                                                      
|FASB                        |  | Financial Accounting Standards Board                                                                                                                                                                                                                                                                                                                         
|FCM                         |  | Forward Capacity Market                                                                                                                                                                                                                                                                                                                                      
|FEIS                        |  | Final Environmental Impact Statement                                                                                                                                                                                                                                                                                                                         
|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                                                                                                                                                                                                                                 
|Fracking                    |  | Multi-stage hydraulic fracturing                                                                                                                                                                                                                                                                                                                             
|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.                                                                                                                                                                                                       
|GTN                         |  | A natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border, traversing Idaho, Washington and Oregon                                                                                                                                                                                                              
|GTN LLC                     |  | Gas Transmission Northwest LLC                                                                                                                                                                                                                                                                                                                               
|Guadalajara                 |  | A natural gas pipeline 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                                                                                                                                                                                                                                                                                     
|HOEP                        |  | Hourly Ontario energy price                                                                                                                                                                                                                                                                                                                                  
|HSE                         |  | Health, safety and environment                                                                                                                                                                                                                                                                                                                               
|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                    |  | The crude oil pipeline system which extends from Hardisty, Alberta to the U.S. markets and includes the Wood River/Patoka, the Cushing Extension and Keystone XL                                                                                                                                                                                             
|Keystone XL                 |  | A proposed extension and expansion of the Keystone oil pipeline to the U.S. Gulf Coast, which includes the construction of a new crude oil pipeline from Cushing, Oklahoma to the U.S. Gulf Coast, the expansion of
existing facilities at Hardisty, Alberta and the construction of a new crude oil pipeline from Hardisty, Alberta to Steele City, Nebraska
|Kibby Wind                  |  | A wind farm located in Kibby and Skinner townships in northwestern Franklin County, Maine                                                                                                                                                                                                                                                                    
|km                          |  | Kilometre(s)                                                                                                                                                                                                                                                                                                                                                 
|LMCI                        |  | Land Matters Consultation Initiative                                                                                                                                                                                                                                                                                                                         
|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                                                                                                                                                                                                                                                                                                                                        
|NEXT                        |  | Natural Gas Liquids Extraction Model                                                                                                                                                                                                                                                                                                                         
|NGTL                        |  | NOVA Gas Transmission Ltd.                                                                                                                                                                                                                                                                                                                                   
|NID                         |  | National Interest Determination                                                                                                                                                                                                                                                                                                                              

MANAGEMENT'S DISCUSSION AND ANALYSIS101

---



|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                                                                               
|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          |  | A natural gas-fired, combined-cycle plant in Burrillville, Rhode Island                                                                                                              
|PHMSA                      |  | Pipeline and Hazardous Materials Safety Administration                                                                                                                               
|PJM Interconnection (PJM)  |  | 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                                                                                                                                                           
|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                                                                                                                        
|Restructuring Proposal     |  | Canadian Mainline 2012 Tolls Application and Restructuring Proposal                                                                                                                  
|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                                                                                                          
|TC Keystone                |  | TransCanada Keystone Pipeline, LP                                                                                                                                                    
|Tcf                        |  | Trillion cubic feet                                                                                                                                                                  
|TCPL                       |  | TransCanada PipeLines Limited                                                                                                                                                        
|TCPL USA                   |  | TransCanada PipeLine USA Ltd.                                                                                                                                                        
|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                                                                                                                                        
|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          |  | A crude oil pipeline extending from Hardisty, Alberta to U.S. markets at Wood River and Patoka in Illinois                                                                           
|Zephyr                     |  | A proposed power transmission line project originating in Wyoming and terminating in Nevada                                                                                          

102MANAGEMENT'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 as defined in Part V of the Canadian
Institute of Chartered Accountants (CICA) Handbook (CGAAP) 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 2011
to that in 2010, and highlights significant changes between 2010 and 2009. 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 control 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
control 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 (COSO). Management concluded, based on its evaluation, that internal control over
financial reporting are effective as of December 31, 2011, 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 controls. 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 CGAAP. The report of KPMG LLP outlines the scope of its examination and its opinion on the consolidated financial statements.
|-------------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | SIG                                   |  | SIG                                                 
| |  | ------------------------------------- |  | ----------------------------------------------------
| |  | Russell K. Girling                    |  | Donald R. Marchand                                  
| |  | President and
Chief Executive Officer |  | Executive Vice-President and
Chief Financial Officer
| |  | February 13, 2012                     |  |                                                     

TRANSCANADA
CORPORATION103

---





|Independent
Auditors'
Report |  | To the Shareholders of TransCanada CorporationWe have audited the accompanying consolidated financial statements of TransCanada Corporation, which comprise the consolidated balance sheets as at December 31, 2011 and 2010, the consolidated statements of income, comprehensive
income, accumulated other comprehensive income, equity and cash flows for each of the years in the three-year period ended December 31, 2011, 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 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 opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of TransCanada Corporation as at December 31, 2011 and 2010 and its consolidated results of
operations and its consolidated cash flows for each of the years in the three-year period ended December 31, 2011 in accordance with Canadian generally accepted accounting principles.
|---------------------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|
|

|
|

| |  | GRAPHIC                              
| |  | -------------------------------------
| |  | Chartered Accountants
Calgary, Canada
| |  | February 13, 2012                    

104CONSOLIDATED
FINANCIAL STATEMENTS

---





TRANSCANADA CORPORATIONCONSOLIDATED INCOME

|Year ended December 31
(millions of dollars except per share amounts) |  | 2011  |   | 2010  |   | 2009  |   | 
|--------------------------------------------------------------------- |  | ----- | - | ----- | - | ----- | - | 
|                                                                     
|Revenues                                                              |  | 9,139 |   | 8,064 |   | 8,181 |   | 
|Operating and Other Expenses                                          |  |       |   |       |   |       |   | 
|Plant operating costs and other                                       |  | 3,449 |   | 3,114 |   | 3,213 |   | 
|Commodity purchases resold                                            |  | 941   |   | 1,017 |   | 831   |   | 
|Depreciation and amortization                                         |  | 1,528 |   | 1,354 |   | 1,377 |   | 
|Valuation provision for MGP (Note 9)                                  |  |      |   | 146   |   |      |   | 
|                                                                     
|                                                                      |  | 5,918 |   | 5,631 |   | 5,421 |   | 
|                                                                     
|Financial Charges/(Income)                                            |  |       |   |       |   |       |   | 
|Interest expense (Note 13)                                            |  | 937   |   | 701   |   | 954   |   | 
|Interest expense of joint ventures (Note 14)                          |  | 55    |   | 59    |   | 64    |   | 
|Interest income and other                                             |  | (55   | ) | (94   | ) | (121  | ) | 
|                                                                     
|                                                                      |  | 937   |   | 666   |   | 897   |   | 
|                                                                     
|Income before Income Taxes                                            |  | 2,284 |   | 1,767 |   | 1,863 |   | 
|                                                                     
|Income Tax Expense/(Recovery)(Note 12)                                |  |       |   |       |   |       |   | 
|Current                                                               |  | 209   |   | (141  | ) | 30    |   | 
|Future                                                                |  | 364   |   | 521   |   | 357   |   | 
|                                                                     
|                                                                      |  | 573   |   | 380   |   | 387   |   | 
|                                                                     
|Net Income                                                            |  | 1,711 |   | 1,387 |   | 1,476 |   | 
|Net Income Attributable to Non-Controlling Interests (Note 16)        |  | 129   |   | 115   |   | 96    |   | 
|                                                                     
|Net Income Attributable to Controlling Interests                      |  | 1,582 |   | 1,272 |   | 1,380 |   | 
|Preferred Share Dividends (Note 18)                                   |  | 55    |   | 45    |   | 6     |   | 
|                                                                     
|Net Income Attributable to Common Shares                              |  | 1,527 |   | 1,227 |   | 1,374 |   | 
|                                                                     
|Net Income per Common Share(Note 17)                                  |  |       |   |       |   |       |   | 
|Basic                                                                 |  | $2.18 |   | $1.78 |   | $2.11 |   | 
|                                                                     
|Diluted                                                               |  | $2.17 |   | $1.77 |   | $2.11 |   | 
|                                                                     

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

CONSOLIDATED FINANCIAL
STATEMENTS105

---



TRANSCANADA CORPORATIONCONSOLIDATED COMPREHENSIVE INCOME

|Year ended December 31
(millions of dollars)                                                                   |  | 2011  |   | 2010  |   | 2009  |   | 
|-------------------------------------------------------------------------------------------------------------- |  | ----- | - | ----- | - | ----- | - | 
|                                                                                                              
|Net Income                                                                                                     |  | 1,711 |   | 1,387 |   | 1,476 |   | 
|                                                                                                              
|Other Comprehensive Income/(Loss), Net of Income Taxes                                                         |  |       |   |       |   |       |   | 
|Change in foreign currency translation gains and losses on investments in foreign operations(1)                |  | 113   |   | (180  | ) | (471  | ) | 
|Change in fair value of derivative instruments to hedge the net investments in foreign operations(2)           |  | (73   | ) | 89    |   | 258   |   | 
|Change in fair value of derivative instruments designated as cash flow hedges(3)                               |  | (203  | ) | (141  | ) | 75    |   | 
|Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges(4) |  | 127   |   | (7    | ) | (15   | ) | 
|                                                                                                              
|Other Comprehensive Loss                                                                                       |  | (36   | ) | (239  | ) | (153  | ) | 
|                                                                                                              
|Comprehensive Income                                                                                           |  | 1,675 |   | 1,148 |   | 1,323 |   | 
|Comprehensive Income Attributable to Non-Controlling Interests                                                 |  | 140   |   | 121   |   | 103   |   | 
|                                                                                                              
|Comprehensive Income Attributable to Controlling Interests                                                     |  | 1,535 |   | 1,027 |   | 1,220 |   | 
|Preferred Share Dividends                                                                                      |  | 55    |   | 45    |   | 6     |   | 
|                                                                                                              
|Comprehensive Income Attributable to Common Shares                                                             |  | 1,480 |   | 982   |   | 1,214 |   | 
|                                                                                                              

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

106CONSOLIDATED
FINANCIAL STATEMENTS

---





TRANSCANADA CORPORATIONCONSOLIDATED CASH FLOWS

|Year ended December 31
(millions of dollars)                         |  | 2011   |   | 2010   |   | 2009   |   | 
|-------------------------------------------------------------------- |  | ------ | - | ------ | - | ------ | - | 
|                                                                    
|Cash Generated from Operations                                       |  |        |   |        |   |        |   | 
|Net income                                                           |  | 1,711  |   | 1,387  |   | 1,476  |   | 
|Depreciation and amortization                                        |  | 1,528  |   | 1,354  |   | 1,377  |   | 
|Future income taxes (Note 12)                                        |  | 364    |   | 521    |   | 357    |   | 
|Employee future benefits funding in excess of expense (Note 20)      |  | (3     | ) | (69    | ) | (111   | ) | 
|Valuation provision for MGP (Note 9)                                 |  |       |   | 146    |   |       |   | 
|Other                                                                |  | 63     |   | (8     | ) | (19    | ) | 
|                                                                    
|                                                                     |  | 3,663  |   | 3,331  |   | 3,080  |   | 
|Decrease/(increase) in operating working capital (Note 22)           |  | 310    |   | (249   | ) | (90    | ) | 
|                                                                    
|Net cash provided by operations                                      |  | 3,973  |   | 3,082  |   | 2,990  |   | 
|                                                                    
|Investing Activities                                                 |  |        |   |        |   |        |   | 
|Capital expenditures (Note 4)                                        |  | (3,274 | ) | (5,036 | ) | (5,417 | ) | 
|Deferred amounts and other                                           |  | (14    | ) | (384   | ) | (594   | ) | 
|Acquisitions, net of cash acquired (Note 23)                         |  |       |   |       |   | (902   | ) | 
|                                                                    
|Net cash used in investing activities                                |  | (3,288 | ) | (5,420 | ) | (6,913 | ) | 
|                                                                    
|Financing Activities                                                 |  |        |   |        |   |        |   | 
|Dividends on common and preferred shares
(Notes 17 and 18)           |  | (1,016 | ) | (754   | ) | (728   | ) | 
|Distributions paid to non-controlling interests                      |  | (131   | ) | (112   | ) | (100   | ) | 
|Notes payable (repaid)/issued, net                                   |  | (218   | ) | 474    |   | (244   | ) | 
|Long-term debt issued, net of issue costs                            |  | 1,622  |   | 2,371  |   | 3,267  |   | 
|Repayment of long-term debt                                          |  | (1,272 | ) | (494   | ) | (1,005 | ) | 
|Long-term debt of joint ventures issued                              |  | 48     |   | 177    |   | 226    |   | 
|Repayment of long-term debt of joint ventures                        |  | (102   | ) | (254   | ) | (246   | ) | 
|Common shares issued, net of issue costs                             |  | 58     |   | 26     |   | 1,820  |   | 
|Preferred shares issued, net of issue costs                          |  |       |   | 679    |   | 539    |   | 
|Partnership units of subsidiary issued, net of issue costs (Note 23) |  | 321    |   |       |   | 193    |   | 
|                                                                    
|Net cash (used in)/provided by financing activities                  |  | (690   | ) | 2,113  |   | 3,722  |   | 
|                                                                    
|Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents |  | 6      |   | (8     | ) | (110   | ) | 
|                                                                    
|Increase/(Decrease) in Cash and Cash Equivalents                     |  | 1      |   | (233   | ) | (311   | ) | 
|Cash and Cash Equivalents                                            |  |        |   |        |   |        |   | 
|Beginning of year                                                    |  | 764    |   | 997    |   | 1,308  |   | 
|                                                                    
|Cash and Cash Equivalents                                            |  |        |   |        |   |        |   | 
|End of year                                                          |  | 765    |   | 764    |   | 997    |   | 
|                                                                    

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

CONSOLIDATED FINANCIAL
STATEMENTS107

---



TRANSCANADA CORPORATIONCONSOLIDATED BALANCE SHEET

|December 31
(millions of dollars)                             |  | 2011   |  | 2010   |  | 
|------------------------------------------------------------- |  | ------ |  | ------ |  | 
|                                                             
|ASSETS                                                        |  |        |  |        |  | 
|Current Assets                                                |  |        |  |        |  | 
|Cash and cash equivalents                                     |  | 765    |  | 764    |  | 
|Accounts receivable                                           |  | 1,265  |  | 1,271  |  | 
|Inventories                                                   |  | 416    |  | 425    |  | 
|Other                                                         |  | 1,194  |  | 870    |  | 
|                                                             
|                                                              |  | 3,640  |  | 3,330  |  | 
|Plant, Property and Equipment(Note 5)                         |  | 38,262 |  | 36,244 |  | 
|Goodwill(Note 6)                                              |  | 3,650  |  | 3,570  |  | 
|Regulatory Assets(Note 7)                                     |  | 1,405  |  | 1,512  |  | 
|Intangibles and Other Assets(Note 9)                          |  | 2,038  |  | 2,138  |  | 
|                                                             
|                                                              |  | 48,995 |  | 46,794 |  | 
|                                                             
|LIABILITIES                                                   |  |        |  |        |  | 
|Current Liabilities                                           |  |        |  |        |  | 
|Notes payable (Note 10)                                       |  | 1,880  |  | 2,092  |  | 
|Accounts payable                                              |  | 2,659  |  | 2,272  |  | 
|Accrued interest                                              |  | 373    |  | 367    |  | 
|Current portion of long-term debt (Note 13)                   |  | 935    |  | 894    |  | 
|Current portion of long-term debt of joint ventures (Note 14) |  | 33     |  | 65     |  | 
|                                                             
|                                                              |  | 5,880  |  | 5,690  |  | 
|Regulatory Liabilities(Note 7)                                |  | 303    |  | 314    |  | 
|Deferred Amounts(Note 11)                                     |  | 805    |  | 694    |  | 
|Future Income Taxes(Note 12)                                  |  | 3,788  |  | 3,398  |  | 
|Long-Term Debt(Note 13)                                       |  | 17,632 |  | 17,028 |  | 
|Long-Term Debt of Joint Ventures(Note 14)                     |  | 789    |  | 801    |  | 
|Junior Subordinated Notes(Note 15)                            |  | 1,009  |  | 985    |  | 
|                                                             
|                                                              |  | 30,206 |  | 28,910 |  | 
|                                                             
|EQUITY                                                        |  |        |  |        |  | 
|Controlling interests                                         |  | 17,324 |  | 16,727 |  | 
|Non-controlling interests (Note 16)                           |  | 1,465  |  | 1,157  |  | 
|                                                             
|                                                              |  | 18,789 |  | 17,884 |  | 
|                                                             
|                                                              |  | 48,995 |  | 46,794 |  | 
|                                                             
|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:

|SIG                        |  | SIG                    
|-------------------------- |  | -----------------------
|Russell K. GirlingDirector |  | Kevin E. BensonDirector

108CONSOLIDATED
FINANCIAL STATEMENTS

---





TRANSCANADA CORPORATIONCONSOLIDATED ACCUMULATED OTHER COMPREHENSIVE (LOSS)/INCOME

|(millions of dollars)                                                                                             |  | Currency
Translation
Adjustments |   | Cash Flow
Hedges
and Other |   | Total |   | 
|----------------------------------------------------------------------------------------------------------------- |  | -------------------------------- | - | -------------------------- | - | ----- | - | 
|                                                                                                                 
|Balance at January 1, 2009                                                                                        |  | (379                             | ) | (93                        | ) | (472  | ) | 
|Change in foreign currency translation gains and losses on investments in foreign operations(1)                   |  | (471                             | ) |                           |   | (471  | ) | 
|Change in fair value of derivative instruments to hedge the net investments in foreign operations(2)              |  | 258                              |   |                           |   | 258   |   | 
|Change in fair value of 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(4)    |  |                                 |   | (24                        | ) | (24   | ) | 
|                                                                                                                 
|Balance at December 31, 2009                                                                                      |  | (592                             | ) | (40                        | ) | (632  | ) | 
|Change in foreign currency translation gains and losses on investments in foreign operations(1)                   |  | (180                             | ) |                           |   | (180  | ) | 
|Change in fair value of derivative instruments to hedge the net investments in foreign operations(2)              |  | 89                               |   |                           |   | 89    |   | 
|Change in fair value of 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(4)    |  |                                 |   | (17                        | ) | (17   | ) | 
|                                                                                                                 
|Balance at December 31, 2010                                                                                      |  | (683                             | ) | (194                       | ) | (877  | ) | 
|Change in foreign currency translation gains and losses on investments in foreign operations(1)                   |  | 113                              |   |                           |   | 113   |   | 
|Change in fair value of derivative instruments to hedge the net investments in foreign operations(2)              |  | (73                              | ) |                           |   | (73   | ) | 
|Change in fair value of derivative instruments designated as cash flow hedges(3)                                  |  |                                 |   | (204                       | ) | (204  | ) | 
|Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges(4)(5) |  |                                 |   | 117                        |   | 117   |   | 
|                                                                                                                 
|Balance at December 31, 2011                                                                                      |  | (643                             | ) | (281                       | ) | (924  | ) | 
|                                                                                                                 

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

CONSOLIDATED FINANCIAL
STATEMENTS109

---



TRANSCANADA CORPORATIONCONSOLIDATED EQUITY

|Year ended December 31
(millions of dollars)                                    |                                         | 2011   |     | 2010   |    | 2009   |     |  
|------------------------------------------------------------------------------- | --------------------------------------- | ------ | --- | ------ | -- | ------ | --- | -
|                                                                               
|Common Shares                                                                   |                                         |        |     |        |    |        |     |  
|Balance at beginning of year                                                    |                                         | 11,745 |     | 11,338 |    | 9,264  |     |  
|Shares issued under dividend reinvestment plan (Note 17)                        |                                         | 202    |     | 378    |    | 254    |     |  
|Shares issued on exercise of stock options (Note 17)                            |                                         | 64     |     | 29     |    | 28     |     |  
|Proceeds from shares issued under public offering, net of issue costs (Note 17) |                                         |       |     |       |    | 1,792  |     |  
|                                                                               
|Balance at end of year                                                          |                                         | 12,011 |     | 11,745 |    | 11,338 |     |  
|                                                                               
|Preferred Shares                                                                |                                         |        |     |        |    |        |     |  
|Balance at beginning of year                                                    |                                         | 1,224  |     | 539    |    |       |     |  
|Shares issued under public offering, net of issue costs (Note 18)               |                                         |       |     | 685    |    | 539    |     |  
|                                                                               
|Balance at end of year                                                          |                                         | 1,224  |     | 1,224  |    | 539    |     |  
|                                                                               
|Contributed Surplus                                                             |                                         |        |     |        |    |        |     |  
|Balance at beginning of year                                                    |                                         | 331    |     | 328    |    | 279    |     |  
|Issuance of stock options, net of exercises                                     |                                         | 1      |     | 3      |    | 2      |     |  
|Increased ownership in TC PipeLines, LP (Note 23)                               |                                         |       |     |       |    | 47     |     |  
|Dilution gain from TC PipeLines, LP units issued (Note 23)                      |                                         | 30     |     |       |    |       |     |  
|                                                                               
|Balance at end of year                                                          |                                         | 362    |     | 331    |    | 328    |     |  
|                                                                               
|Retained Earnings                                                               |                                         |        |     |        |    |        |     |  
|Balance at beginning of year                                                    |                                         | 4,304  |     | 4,186  |    | 3,827  |     |  
|Net income attributable to controlling interests                                |                                         | 1,582  |     | 1,272  |    | 1,380  |     |  
|Common share dividends                                                          |                                         | (1,180 | )   | (1,109 | )  | (1,015 | )   |  
|Preferred share dividends                                                       |                                         | (55    | )   | (45    | )  | (6     | )   |  
|                                                                               
|Balance at end of year                                                          |                                         | 4,651  |     | 4,304  |    | 4,186  |     |  
|                                                                               
|Accumulated Other Comprehensive (Loss)/Income                                   |                                         |        |     |        |    |        |     |  
|Balance at beginning of year                                                    |                                         | (877   | )   | (632   | )  | (472   | )   |  
|Other comprehensive loss                                                        |                                         | (47    | )   | (245   | )  | (160   | )   |  
|                                                                               
|Balance at end of year                                                          |                                         | (924   | )   | (877   | )  | (632   | )   |  
|                                                                               
|Equity Attributable to Controlling Interests                                    |                                         | 17,324 |     | 16,727 |    | 15,759 |     |  
|                                                                               
|Equity Attributable to Non-Controlling Interests                                |                                         |        |     |        |    |        |     |  
|Balance at beginning of year                                                    |                                         | 1,157  |     | 1,174  |    | 1,194  |     |  
|Net income attributable to non-controlling interests                            |                                         |        |     |        |    |        |     |  
|                                                                                | TC PipeLines, LP                        |        | 101 |        | 87 |        | 66  |  
|                                                                                | Preferred share dividends of subsidiary |        | 22  |        | 22 |        | 22  |  
|                                                                                | Portland                                |        | 6   |        | 6  |        | 8   |  
|Other comprehensive income attributable to non-controlling interests            |                                         | 11     |     | 6      |    | 7      |     |  
|Sale of TC PipeLines, LP units                                                  |                                         |        |     |        |    |        |     |  
|                                                                                | Proceeds, net of issue costs            |        | 321 |        |   |        | 193 |  
|                                                                                | Decrease in TransCanada's ownership     |        | (50 | )      |   |        | (29 | )
|Distributions to non-controlling interests                                      |                                         | (131   | )   | (112   | )  | (100   | )   |  
|Foreign exchange and other                                                      |                                         | 28     |     | (26    | )  | (187   | )   |  
|                                                                               
|Balance at end of year                                                          |                                         | 1,465  |     | 1,157  |    | 1,174  |     |  
|                                                                               
|Total Equity                                                                    |                                         | 18,789 |     | 17,884 |    | 16,933 |     |  
|                                                                               

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

110CONSOLIDATED
FINANCIAL STATEMENTS

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TRANSCANADA CORPORATIONNOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1    DESCRIPTION OF TRANSCANADA'S BUSINESS

TransCanada Corporation (TransCanada or the Company) is a leading North American energy company which 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:

Through
its Natural Gas Pipelines segment, TransCanada operates and has ownership interests in natural gas pipeline systems as follows:

TransCanada
does not operate but has ownership interests in natural gas pipelines and natural gas marketing activities as follows:

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS111

---



Oil Pipelines

The Oil Pipelines segment consists of a wholly owned and operated crude oil pipeline system 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 Company plans to expand and extend this oil pipeline system to the U.S. Gulf Coast
(Keystone XL) which includes the construction of a new crude oil pipeline from Cushing, Oklahoma to the U.S. Gulf Coast, the addition of operational storage facilities at Hardisty, Alberta and
the construction of a new crude oil pipeline from Hardisty, Alberta to Steele City, Nebraska. The expanded oil pipeline system is collectively referred to as Keystone.

The
proposed Marketlink projects will connect additional oil supply sourced from U.S. basins to facilities which form part of Keystone XL and provide transportation
services accessing refining markets in the Cushing, Oklahoma region and the U.S. Gulf Coast. The proposed Bakken Marketlink project would transport U.S. crude oil from Baker, Montana to Cushing
and the proposed Cushing Marketlink project would transport crude oil from Cushing to Port Arthur and Houston, Texas.

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:

TransCanada
does not operate but has ownership interests in power generation plants as follows:

TransCanada
also has long-term power purchase arrangements (PPA) in place for:

NOTE 2    ACCOUNTING POLICIES

The Company's consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles as defined in Part V
of the Canadian Institute of Chartered Accountants (CICA) Handbook (CGAAP) as discussed further in Note 3. 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.

112NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



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 to exercise joint control. TransCanada uses the equity method of accounting for investments over which the Company is able to exercise
significant influence.

Regulation

In Canada, regulated natural gas pipelines and oil pipelines are subject to the authority of the National Energy Board (NEB) of Canada. In the U.S., natural gas pipelines, oil
pipelines and regulated storage assets 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. Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in
these rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses under CGAAP to appropriately reflect the economic
impact of the regulators' decisions regarding revenues and tolls.

The
NEB and the FERC regulate construction and operations of Keystone; however, RRA is not applicable to Keystone and, as a result, the regulators' decisions regarding
operations and tolls on Keystone 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 otherwise 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 for a specified period reflect the NEB's last
approved return on equity. 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 reflect adjustments to rates to reflect under-recovery or over-recovery of
certain transportation costs. Revenues earned from contracted 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 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
STATEMENTS113

---



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, which represents the estimated withdrawal
period, 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 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 item. 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. When oil pipelines retire plant, property and equipment from service, the original book cost and related
accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings.

Energy

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 overhauls of equipment is capitalized and depreciated over the estimated service lives of the
overhauls. Interest is capitalized on facilities under construction. When Energy retires plant, property and equipment from service, the original book cost and related accumulated depreciation and
amortization are derecognized and any gain or loss is recorded in earnings.

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 acquisition 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 the asset might
be impaired. An initial test is done by comparing the fair value of the reporting unit to its book value, which includes goodwill. 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.

114NOTES 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 PPAs under which TransCanada buys power are accounted for as operating
leases. The initial payments for the Company's PPAs were recognized in Intangibles and Other Assets and amortized on a straight-line basis over the term of the contracts, which expire in
2017 and 2020. A portion of these
PPAs has been subleased to third parties under terms and conditions similar to the PPAs. 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 the Corporate segment. Upon exercise of 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 revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction.
Translation adjustments are reflected in Other Comprehensive Income/(Loss) (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 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.

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.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS115

---



These
instruments are accounted for initially at their fair value and changes to fair value are recorded through OCI. Gains and losses 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 used to manage 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 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 or cancellation.

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 Accumulated
Other Comprehensive (Loss)/Income (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 it is probable the anticipated transaction will not occur.

116NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



The
Company also enters into cash flow hedges and fair value hedges for activities subject to rate regulation in Canada. 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 through charges to operating expenses.

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 utilized. 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 in the period in which contributions are made. 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

Changes in Accounting Policies for 2011

Business Combinations

Effective January 1, 2011, the Company adopted CICA Handbook Section 1582 "Business Combinations", which 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, expensing of acquisition costs, and
increased disclosure. Adoption of this standard had no effect on the financial statements as at and for the year ended December 31, 2011.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS117

---



Consolidated Financial Statements and Non-Controlling Interests

Entities adopting Section 1582 were also required to adopt CICA Handbook Sections 1601 "Consolidated Financial Statements" and 1602 "Non-Controlling
Interests". Sections 1601 and 1602 require Non-Controlling Interests to be presented as part of Equity on the balance sheet. In addition, the income statement of the
controlling parent now includes 100 per cent of the subsidiary's results
and presents the allocation of net income between the controlling and non-controlling interests. Changes resulting from the adoption of Sections 1601 and 1602 were applied
retrospectively.

Future Accounting Changes

United States Generally Accepted Accounting Principles

The CICA's Accounting Standards Board (AcSB) previously announced that Canadian publicly accountable enterprises were required to adopt International Financial Reporting
Standards (IFRS) effective January 1, 2011, with the exception of certain qualifying entities historically using RRA that were given a one year deferral from adopting IFRS. TransCanada is a
qualifying entity for these purposes and has deferred the adoption of IFRS. The Company has prepared its consolidated financial statements for 2011 in accordance with CGAAP in order to continue
using RRA.

In
the application of CGAAP, TransCanada follows specific accounting guidance under United States generally accepted accounting principles (U.S. GAAP) unique
to rate-regulated businesses. These RRA standards allow the timing of recognition of certain revenues and expenses to differ from the timing that may otherwise be expected in a
non-rate-regulated business under CGAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. The
International Accounting Standards Board has concluded that the development of RRA under IFRS requires further analysis and TransCanada does not expect a final RRA standard under IFRS to be effective
in the foreseeable future.

As
a registrant with the U.S. Securities and Exchange Commission, TransCanada has the option under Canadian disclosure rules to prepare and file its consolidated
financial statements using U.S. GAAP. As a result of the developments noted above, the Company's Board of Directors has approved the adoption of U.S. GAAP effective January 1,
2012. The financial reporting impact of TransCanada adopting U.S. GAAP is disclosed in Note 25 "United States Accounting Principles and Reporting". The differences between CGAAP
and U.S. GAAP are consistent with those reported by the Company in its annual "Reconciliation to United States GAAP" as filed in prior years. Significant changes to existing systems and
processes are not required to implement U.S. GAAP as the Company's primary accounting framework.

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board (FASB) issued amended guidance on fair value measurements, which updated some of the existing measurement guidance
and included enhanced disclosure requirements under U.S. GAAP. This guidance is effective for interim and annual periods beginning after December 15, 2011. Adoption of these amendments
is expected to result in an increase in the qualitative and quantitative disclosures regarding Level 3 measurements, however, the Company expects no material effect on the financial statements.

Intangibles  Goodwill and Other

In September 2011, the FASB issued new guidance on testing goodwill for impairment which simplifies an entity's testing for goodwill impairment under U.S. GAAP by
permitting an entity to first assess qualitative factors affecting the fair value of a reporting unit in comparison
to the carrying amount, as a basis for determining whether it is required to proceed to the two-step quantitative goodwill impairment test. This guidance is effective for interim and
annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Adoption is not expected to impact the financial statements.

Balance Sheet Offsetting/Netting

In December 2011, the FASB issued amended guidance to enhance disclosures that will enable users of the financial statements to evaluate the effect, or potential effect,
of netting arrangements on an entity's financial position. The amendments result in enhanced disclosures by requiring additional information regarding financial instruments and derivative instruments
that are either offset in accordance with current U.S. GAAP or subject to an enforceable master netting agreement. This guidance is effective for annual periods beginning on or after
January 1, 2013. Adoption of these amendments is expected to result in an increase in disclosures regarding financial instruments which are subject to offsetting as described in
this amendment.

NOTE 4    SEGMENTED INFORMATION

Commencing in February 2011, TransCanada began recording earnings related to the Wood River/Patoka and Cushing Extension sections of Keystone.

During
2010, the Company began recognizing a separate segment, Oil Pipelines. Also during that period, Wood River/Patoka began delivering oil but at reduced operating
pressure due to regulatory restrictions. As a result, the Company continued to classify Wood River/Patoka as under construction along with the Cushing Extension and Keystone XL. At December 31,
2010, Keystone capital costs were net of $99 million of operating cash flows relating to Wood River/Patoka.

118NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---





|Year ended December 31, 2011 (millions of dollars)   |  | Natural Gas
Pipelines |   | Oil
Pipelines |   | Energy |   | Corporate |   |  | Total  |   | 
|---------------------------------------------------- |  | --------------------- | - | ------------- | - | ------ | - | --------- | - |  | ------ | - | 
|                                                    
|Revenues                                             |  | 4,500                 |   | 827           |   | 3,812  |   |          |   |  | 9,139  |   | 
|Plant operating costs and other                      |  | (1,533                | ) | (240          | ) | (1,590 | ) | (86       | ) |  | (3,449 | ) | 
|Commodity purchases resold                           |  |                      |   |              |   | (941   | ) |          |   |  | (941   | ) | 
|Depreciation and amortization                        |  | (986                  | ) | (130          | ) | (398   | ) | (14       | ) |  | (1,528 | ) | 
|                                                    
|                                                     |  | 1,981                 |   | 457           |   | 883    |   | (100      | ) |  | 3,221  |   | 
|                                                     |  |                       |  
|                                                     |  |                       |   |               |   |        |   |           |   |  |        |   | 
|Interest expense                                     |  |                       |   |               |   |        |   |           |   |  | (937   | ) | 
|Interest expense of joint ventures                   |  |                       |   |               |   |        |   |           |   |  | (55    | ) | 
|Interest income and other                            |  |                       |   |               |   |        |   |           |   |  | 55     |   | 
|Income tax expense                                   |  |                       |   |               |   |        |   |           |   |  | (573   | ) | 
|                                                     |  |                       |   |               |   |        |   |           |   |  |       
|Net Income                                           |  |                       |   |               |   |        |   |           |   |  | 1,711  |   | 
|Net Income Attributable to Non-Controlling Interests |  |                       |   |               |   |        |   |           |   |  | (129   | ) | 
|                                                     |  |                       |   |               |   |        |   |           |   |  |       
|Net Income Attributable to Controlling Interests     |  |                       |   |               |   |        |   |           |   |  | 1,582  |   | 
|Preferred Share Dividends                            |  |                       |   |               |   |        |   |           |   |  | (55    | ) | 
|                                                     |  |                       |   |               |   |        |   |           |   |  |       
|Net Income Attributable to Common Shares             |  |                       |   |               |   |        |   |           |   |  | 1,527  |   | 
|                                                     |  |                       |   |               |   |        |   |           |   |  |       

|
|

|Year ended December 31, 2010 (millions of dollars)   |  | Natural Gas
Pipelines |   | Oil
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 tax expense                                   |  |                       |   |               |  |        |   |           |   |  | (380   | ) | 
|                                                     |  |                       |   |               |  |        |   |           |   |  |       
|Net Income                                           |  |                       |   |               |  |        |   |           |   |  | 1,387  |   | 
|Net Income Attributable to Non-Controlling Interests |  |                       |   |               |  |        |   |           |   |  | (115   | ) | 
|                                                     |  |                       |   |               |  |        |   |           |   |  |       
|Net Income Attributable to Controlling Interests     |  |                       |   |               |  |        |   |           |   |  | 1,272  |   | 
|Preferred Share Dividends                            |  |                       |   |               |  |        |   |           |   |  | (45    | ) | 
|                                                     |  |                       |   |               |  |        |   |           |   |  |       
|Net Income Attributable to Common Shares             |  |                       |   |               |  |        |   |           |   |  | 1,227  |   | 
|                                                     |  |                       |   |               |  |        |   |           |   |  |       

|Year ended December 31, 2009 (millions of dollars)   |  | Natural Gas
Pipelines |   | Oil
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 tax expense                                   |  |                       |   |               |  |        |   |           |   |  | (387   | ) | 
|                                                     |  |                       |   |               |  |        |   |           |   |  |       
|Net Income                                           |  |                       |   |               |  |        |   |           |   |  | 1,476  |   | 
|Net Income Attributable to Non-Controlling Interests |  |                       |   |               |  |        |   |           |   |  | (96    | ) | 
|                                                     |  |                       |   |               |  |        |   |           |   |  |       
|Net Income Attributable to Controlling Interests     |  |                       |   |               |  |        |   |           |   |  | 1,380  |   | 
|Preferred Share Dividends                            |  |                       |   |               |  |        |   |           |   |  | (6     | ) | 
|                                                     |  |                       |   |               |  |        |   |           |   |  |       
|Net Income Attributable to Common Shares             |  |                       |   |               |  |        |   |           |   |  | 1,374  |   | 
|                                                     |  |                       |   |               |  |        |   |           |   |  |       

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS119

---



TOTAL ASSETS

|December 31 (millions of dollars) |  | 2011   |  | 2010   |  |  |  | 
|--------------------------------- |  | ------ |  | ------ |  |  |  | 
|                                  |  |       
|Natural Gas Pipelines             |  | 23,669 |  | 23,629 |  |  |  | 
|Oil Pipelines                     |  | 9,439  |  | 8,501  |  |  |  | 
|Energy                            |  | 14,276 |  | 12,966 |  |  |  | 
|Corporate                         |  | 1,611  |  | 1,698  |  |  |  | 
|                                  |  |       
|                                  |  | 48,995 |  | 46,794 |  |  |  | 
|                                  |  |       

GEOGRAPHIC INFORMATION

|Year ended December 31 (millions of dollars) |  | 2011  |  | 2010  |  | 2009  |  | 
|-------------------------------------------- |  | ----- |  | ----- |  | ----- |  | 
|                                            
|Revenues(1)                                  |  |       |  |       |  |       |  | 
|Canada  domestic                            |  | 4,836 |  | 4,368 |  | 5,079 |  | 
|Canada  export                              |  | 1,087 |  | 838   |  | 756   |  | 
|United States and other                      |  | 3,216 |  | 2,858 |  | 2,346 |  | 
|                                            
|                                             |  | 9,139 |  | 8,064 |  | 8,181 |  | 
|                                            

|December 31 (millions of dollars) |  | 2011   |  | 2010   |  |  |  | 
|--------------------------------- |  | ------ |  | ------ |  |  |  | 
|                                  |  |       
|Plant, Property and Equipment     |  |        |  |        |  |  |  | 
|Canada                            |  | 22,349 |  | 21,561 |  |  |  | 
|United States and other           |  | 15,913 |  | 14,683 |  |  |  | 
|                                  |  |       
|                                  |  | 38,262 |  | 36,244 |  |  |  | 
|                                  |  |       

CAPITAL EXPENDITURES

|Year ended December 31 (millions of dollars) |  | 2011  |  | 2010  |  | 2009  |  | 
|-------------------------------------------- |  | ----- |  | ----- |  | ----- |  | 
|                                            
|Natural Gas Pipelines                        |  | 935   |  | 1,196 |  | 965   |  | 
|Oil Pipelines                                |  | 1,204 |  | 2,696 |  | 2,939 |  | 
|Energy                                       |  | 1,127 |  | 1,129 |  | 1,487 |  | 
|Corporate                                    |  | 8     |  | 15    |  | 26    |  | 
|                                            
|                                             |  | 3,274 |  | 5,036 |  | 5,417 |  | 
|                                            

120NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



NOTE 5    PLANT, PROPERTY AND EQUIPMENT

|                                  |                    | 2011   | 2010 
|--------------------------------- | ------------------ | ------ | -----
|                                  |                    |       
|December 31 (millions of dollars) |                    | Cost   |      
|                                 
|Natural Gas Pipelines(1)          |                    |        |      
|Canadian Mainline                 |                    |        |      
|                                  | Pipeline           |        | 8,785
|                                  | Compression        |        | 3,362
|                                  | Metering and other |        | 383  
|                                 
|                                  |                    | 12,530 |      
|                                  | Under construction |        | 28   
|                                 
|                                  |                    | 12,558 |      
|                                 
|Alberta System                    |                    |        |      
|                                  | Pipeline           |        | 6,701
|                                  | Compression        |        | 1,778
|                                  | Metering and other |        | 931  
|                                 
|                                  |                    | 9,410  |      
|                                  | Under construction |        | 368  
|                                 
|                                  |                    | 9,778  |      
|                                 
|ANR                               |                    |        |      
|                                  | Pipeline           |        | 858  
|                                  | Compression        |        | 510  
|                                  | Metering and other |        | 576  
|                                 
|                                  |                    | 1,944  |      
|                                  | Under construction |        | 20   
|                                 
|                                  |                    | 1,964  |      
|                                 
|Joint Ventures and Others         |                    |        |      
|                                  | GTN                |        | 1,612
|                                  | Great Lakes        |        | 1,581
|                                  | Foothills          |        | 1,630
|                                  | Northern Border    |        | 1,288
|                                  | Other(2)           |        | 3,132
|                                 
|                                  |                    | 9,243  |      
|                                 
|                                  |                    | 33,543 |      
|                                 
|Oil Pipelines                     |                    |        |      
|Keystone                          |                    |        |      
|                                  | Pipeline           |        | 4,904
|                                  | Pumping equipment  |        | 1,502
|                                  | Tanks and other    |        | 548  
|                                 
|                                  |                    | 6,954  |      
|Under construction(3)             |                    | 2,433  |      
|                                 
|                                  |                    | 9,387  |      
|                                 
|Energy                            |                    |        |      
|Nuclear(4)                        |                    | 1,712  |      
|Natural Gas  Ravenswood          |                    | 1,799  |      
|Natural Gas  Other(5)            |                    | 3,337  |      
|Hydro                             |                    | 620    |      
|Wind(6)                           |                    | 843    |      
|Natural Gas Storage               |                    | 454    |      
|Other                             |                    | 163    |      
|                                 
|                                  |                    | 8,928  |      
|Under construction  Nuclear(7)   |                    | 3,217  |      
|Under construction  Other(8)     |                    | 308    |      
|                                 
|                                  |                    | 12,453 |      
|                                 
|Corporate                         |                    | 129    |      
|                                 
|                                  |                    | 55,512 |      
|                                 

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS121

---



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, 2010    |  | 2,891                 |   | 872    |   | 3,763 |   | 
|Foreign exchange rate changes |  | (144                  | ) | (49    | ) | (193  | ) | 
|                             
|Balance at December 31, 2010  |  | 2,747                 |   | 823    |   | 3,570 |   | 
|Foreign exchange rate changes |  | 62                    |   | 18     |   | 80    |   | 
|                             
|Balance at December 31, 2011  |  | 2,809                 |   | 841    |   | 3,650 |   | 
|                             

NOTE 7    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.

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 theNational Energy Board Act(Canada). 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 ROE formula in accordance with the terms of the current Canadian Mainline
tolls settlement, described below.

122NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



Canadian Mainline

In 2011, the Canadian Mainline operated under its five-year settlement, which was 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 2011 for the Canadian Mainline was 8.08 per cent (2010  8.52 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 for performance-based
incentive arrangements. In 2009, the NEB approved an adjustment 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 account are to be amortized at the composite depreciation rate and included in tolls beginning in 2011.

In
September 2011, the NEB approved the Canadian Mainline's interim tolls as final for 2011, including TransCanada's proposal to carry forward any revenue variances
into the determination of 2012 tolls. However, the NEB determined that TransCanada's inclusion of certain elements in the proposed 2011 revenue requirement derived in accordance with the 2007-2011
settlement will be examined with TransCanada's 2012-2013 Tolls Application before a final decision is rendered on the 2011 revenue requirement.

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.

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. A component of OM&A is fixed, subject to the terms of the B.C System/Foothills Integration Settlement, and variances between actual and fixed amounts were
shared with customers up to and including June 2011 when the OM&A savings cap was reached.

TQM

In November 2010, the NEB approved TQM's multi-year settlement with its interested parties regarding its annual revenue requirements for 2010 to 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 theNatural Gas Act of
1938,theNatural Gas Policy Act of 1978(NGA) and theEnergy Policy Act of 2005, and
are subject to the jurisdiction of the FERC. The NGA 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. The Company's significant regulated U.S. natural gas pipelines are described below.

ANR

ANR's natural gas transportation and storage services are provided for under tariffs regulated by the FERC. These tariffs include maximum and minimum rates for services and
allow 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 that was effective
beginning in 1997. ANR Pipeline Company is not required to conduct a review of currently effective rates with the FERC at any time in the future but is not prohibited from filing for new rates if
necessary. ANR Storage Company, which is another FERC regulated entity that owns and operates storage fields in Michigan, has rates that were established pursuant to a settlement approved by the FERC
that were effective beginning in 1990. ANR Storage Company is currently subject to a review, initiated by the FERC in late 2011, of its existing rates.

In
2011, ANR Pipeline Company filed an application with the FERC to sell its offshore Gulf of Mexico assets and certain related onshore facilities to its wholly owned
subsidiary, TC Offshore LLC. At the same time, TC Offshore LLC requested authorization from the FERC to acquire, own and operate those facilities under the FERC's regulations. These
filings are currently pending before the FERC and a decision is expected in second or third quarter 2012.

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. That settlement
required GTN to file a rate case within seven years of the effective date. In November 2011, the FERC approved, without modification, GTN's new settlement with its shippers regarding
GTN's rates, terms and

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS123

---



conditions
of service which will become effective January 1, 2012. This new settlement provides for a four year moratorium during which GTN and the settling parties
are prohibited from taking certain actions under the NGA, including filings to adjust rates. GTN is required to file for new rates to be effective January 1, 2016.

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. Great Lakes rates were established pursuant to a settlement approved by the FERC in July 2010. The
settlement included a moratorium on participants and customers from initiating a NGA Section 5 rate case to adjust rates prior to November 1, 2012. In addition, Great Lakes is required
to file a NGA Section 4 general rate case no later than November 1, 2013.

Bison

Bison is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for various services. Bison is
permitted to discount or negotiate these rates on a non-discriminatory basis. Bison's rates were established pursuant to its initial certificate to construct and operate the pipeline that
initiated service in January 2011.

Regulatory Assets and Liabilities

|Year ended December 31 (millions of dollars)           |  | 2011  |  | 2010  |  |  |  | Remaining Recovery/
Settlement
Period
(years) |  | 
|------------------------------------------------------ |  | ----- |  | ----- |  |  |  | --------------------------------------------- |  | 
|                                                      
|Regulatory Assets                                      |  |       |  |       |  |  |  |                                               |  | 
|Future income taxes(1)                                 |  | 1,178 |  | 1,256 |  |  |  | n/a                                           |  | 
|Operating and debt-service regulatory assets(2)        |  | 172   |  | 237   |  |  |  | 1                                             |  | 
|Adjustment account(3)                                  |  | 82    |  | 85    |  |  |  | 31                                            |  | 
|Other(4)                                               |  | 151   |  | 174   |  |  |  | n/a                                           |  | 
|                                                       |  |       |  |      
|                                                       |  | 1,583 |  | 1,752 |  |  |  |                                               |  | 
|Less: Current portion included in Other Current Assets |  | 178   |  | 240   |  |  |  |                                               |  | 
|                                                       |  |       |  |      
|                                                       |  | 1,405 |  | 1,512 |  |  |  |                                               |  | 
|                                                       |  |       |  |      
|Regulatory Liabilities                                 |  |       |  |       |  |  |  |                                               |  | 
|Foreign exchange on long-term debt(5)                  |  | 184   |  | 200   |  |  |  | 1 - 18                                        |  | 
|Operating and debt-service regulatory liabilities(2)   |  | 135   |  | 98    |  |  |  | 1                                             |  | 
|Other(4)                                               |  | 123   |  | 150   |  |  |  | n/a                                           |  | 
|                                                       |  |       |  |      
|                                                       |  | 442   |  | 448   |  |  |  |                                               |  | 
|Less: Current portion included in Accounts Payable     |  | 139   |  | 134   |  |  |  |                                               |  | 
|                                                       |  |       |  |      
|                                                       |  | 303   |  | 314   |  |  |  |                                               |  | 
|                                                       |  |       |  |      

124NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



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,
2011 |  | 2011                                              |  | 2010                  
|                      
|Natural Gas Pipelines  |  |                                            |  |                                                   |  |                       
|Northern Border(1)     |  |                                            |  | 75                                                |  | 69                    
|Iroquois               |  | 44.5%                                      |  | 40                                                |  | 40                    
|TQM                    |  | 50.0%                                      |  | 17                                                |  | 16                    
|Other                  |  | Various                                    |  | 14                                                |  | 16                    
|Energy                 |  |                                            |  |                                                   |  |                       
|Bruce A                |  | 48.8%                                      |  | 33                                                |  | 35                    
|Bruce B                |  | 31.6%                                      |  | 77                                                |  | 138                   
|ASTC Power Partnership |  | 50.0%                                      |  | 84                                                |  | 41                    
|Portlands Energy       |  | 50.0%                                      |  | 33                                                |  | 33                    
|CrossAlta              |  | 60.0%                                      |  | 23                                                |  | 45                    
|Cartier Wind(2)        |  | 62.0%                                      |  | 27                                                |  | 24                    
|Other                  |  | Various                                    |  | 7                                                 |  | 8                     
|                      
|                       |  |                                            |  | 430                                               |  | 465                   
|                      

Summarized Financial Information of Joint Ventures

|Year ended December 31 (millions of dollars)                    |  | 2011  |   | 2010  |   | 2009  |   | 
|--------------------------------------------------------------- |  | ----- | - | ----- | - | ----- | - | 
|                                                               
|Income                                                          |  |       |   |       |   |       |   | 
|Revenues                                                        |  | 1,668 |   | 1,643 |   | 1,632 |   | 
|Plant operating costs and other                                 |  | (974  | ) | (913  | ) | (856  | ) | 
|Depreciation and amortization                                   |  | (212  | ) | (208  | ) | (196  | ) | 
|Interest expense and other                                      |  | (52   | ) | (57   | ) | (68   | ) | 
|                                                               
|Proportionate Share of Joint Venture Income before Income Taxes |  | 430   |   | 465   |   | 512   |   | 
|                                                               

|
|

|Year ended December 31 (millions of dollars)                                              |  | 2011 |   | 2010 |   | 2009 |   | 
|----------------------------------------------------------------------------------------- |  | ---- | - | ---- | - | ---- | - | 
|                                                                                         
|Cash Flows                                                                                |  |      |   |      |   |      |   | 
|Operating activities                                                                      |  | 733  |   | 678  |   | 455  |   | 
|Investing activities                                                                      |  | (827 | ) | (722 | ) | (651 | ) | 
|Financing activities(1)                                                                   |  | 99   |   | 51   |   | 130  |   | 
|Effect of foreign exchange rate changes on cash and cash equivalents                      |  | 2    |   | (1   | ) | (17  | ) | 
|                                                                                         
|Proportionate Share of Increase/(Decrease) in Cash and Cash Equivalents of Joint Ventures |  | 7    |   | 6    |   | (83  | ) | 
|                                                                                         

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS125

---



|December 31 (millions of dollars)                    |  | 2011  |   | 2010  |   |  |  | 
|---------------------------------------------------- |  | ----- | - | ----- | - |  |  | 
|                                                     |  |      
|Balance Sheet                                        |  |       |   |       |   |  |  | 
|Cash and cash equivalents                            |  | 111   |   | 104   |   |  |  | 
|Other current assets                                 |  | 433   |   | 438   |   |  |  | 
|Plant, property and equipment                        |  | 6,430 |   | 5,704 |   |  |  | 
|Intangibles and other assets/(deferred amounts), net |  | 26    |   | 14    |   |  |  | 
|Current liabilities                                  |  | (437  | ) | (387  | ) |  |  | 
|Long-term debt                                       |  | (789  | ) | (801  | ) |  |  | 
|Future income taxes                                  |  |      |   | 1     |   |  |  | 
|                                                     |  |      
|Proportionate Share of Net Assets of Joint Ventures  |  | 5,774 |   | 5,073 |   |  |  | 
|                                                     |  |      

NOTE 9    INTANGIBLES AND OTHER ASSETS

|December 31 (millions of dollars)            |  | 2011  |  | 2010  |  |  |  | 
|-------------------------------------------- |  | ----- |  | ----- |  |  |  | 
|                                             |  |      
|Employee benefit plans (Note 20)             |  | 499   |  | 473   |  |  |  | 
|PPAs(1)                                      |  | 482   |  | 539   |  |  |  | 
|Loans and advances(2)                        |  | 224   |  | 241   |  |  |  | 
|Fair value of derivative contracts (Note 21) |  | 213   |  | 374   |  |  |  | 
|Future income tax assets (Note 12)           |  | 133   |  | 112   |  |  |  | 
|Margin calls                                 |  | 104   |  | 76    |  |  |  | 
|Equity investments(3)                        |  | 41    |  | 78    |  |  |  | 
|Other                                        |  | 342   |  | 245   |  |  |  | 
|                                             |  |      
|                                             |  | 2,038 |  | 2,138 |  |  |  | 
|                                             |  |      

|                                  |  | 2011 |  | 2010                     |  |               
|--------------------------------- |  | ---- |  | ------------------------ |  | --------------
|                                  |  |     
|December 31
(millions of dollars) |  | Cost |  | Accumulated
Amortization |  | Net
Book Value
|                                 
|Sheerness                         |  | 585  |  | 234                      |  | 351           
|Sundance A                        |  | 225  |  | 148                      |  | 77            
|Sundance B                        |  | 110  |  | 56                       |  | 54            
|                                 
|PPAs                              |  | 920  |  | 438                      |  | 482           
|                                 



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, if successful, would 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.

126NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



At
December 31, 2010, due to uncertainty 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, a valuation provision of $146 million was recorded on the loan to the APG. Amounts advanced to the APG in
furtherance of the MGP in 2011 have been expensed.

NOTE 10    NOTES PAYABLE

|                                                |  | 2011                    |  | 2010 |  |                                                        
|----------------------------------------------- |  | ----------------------- |  | ---- |  | -------------------------------------------------------
|                                                |  |                        
|                                                |  | Outstanding
December 31 |  |      |  | Weighted
Average
Interest Rate
per Annum at
December 31
|                                               
|                                                |  | (millions of dollars)   |  |      |  |                                                        
|Canadian dollars                                |  | 483                     |  |      |  | 1.2%                                                   
|U.S. dollars (2011  US$1,373; 2010  US$1,499) |  | 1,397                   |  |      |  | 0.5%                                                   
|                                                |  |                        
|                                                |  | 1,880                   |  |      |  |                                                        
|                                                |  |                        

Notes
payable consists of commercial paper issued by TransCanada PipeLines Limited (TCPL), TransCanada PipeLine USA Ltd. (TCPL USA) and TransCanada Keystone
Pipeline, LP (TC Keystone) and draws on line-of-credit and demand facilities.

At
December 31, 2011, 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:



NOTE 11    DEFERRED AMOUNTS

|December 31 (millions of dollars)            |  | 2011 |  | 2010 |  |  |  | 
|-------------------------------------------- |  | ---- |  | ---- |  |  |  | 
|                                             |  |     
|Fair value of derivative contracts (Note 21) |  | 352  |  | 282  |  |  |  | 
|Employee benefit plans (Note 20)             |  | 285  |  | 251  |  |  |  | 
|Asset retirement obligations (Note 19)       |  | 68   |  | 65   |  |  |  | 
|Other                                        |  | 100  |  | 96   |  |  |  | 
|                                             |  |     
|                                             |  | 805  |  | 694  |  |  |  | 
|                                             |  |     

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS127

---



NOTE 12    INCOME TAXES

Provision for Income Taxes

|Year ended December 31 (millions of dollars) |  | 2011 |   | 2010 |   | 2009 |   | 
|-------------------------------------------- |  | ---- | - | ---- | - | ---- | - | 
|                                            
|Current                                      |  |      |   |      |   |      |   | 
|Canada                                       |  | 211  |   | 29   |   | (70  | ) | 
|Foreign                                      |  | (2   | ) | (170 | ) | 100  |   | 
|                                            
|                                             |  | 209  |   | (141 | ) | 30   |   | 
|                                            
|Future                                       |  |      |   |      |   |      |   | 
|Canada                                       |  | 138  |   | 170  |   | 339  |   | 
|Foreign                                      |  | 226  |   | 351  |   | 18   |   | 
|                                            
|                                             |  | 364  |   | 521  |   | 357  |   | 
|                                            
|Income Tax Expense                           |  | 573  |   | 380  |   | 387  |   | 
|                                            

Geographic Components of Income

|Year ended December 31 (millions of dollars) |  | 2011  |  | 2010  |  | 2009  |  | 
|-------------------------------------------- |  | ----- |  | ----- |  | ----- |  | 
|                                            
|Canada                                       |  | 1,175 |  | 798   |  | 1,095 |  | 
|Foreign                                      |  | 1,109 |  | 969   |  | 768   |  | 
|                                            
|Income before Income Taxes                   |  | 2,284 |  | 1,767 |  | 1,863 |  | 
|                                            

Reconciliation of Income Tax Expense

|Year ended December 31 (millions of dollars)                 |  | 2011  |   | 2010  |   | 2009  |   | 
|------------------------------------------------------------ |  | ----- | - | ----- | - | ----- | - | 
|                                                            
|Income before Income Taxes                                   |  | 2,284 |   | 1,767 |   | 1,863 |   | 
|Federal and provincial statutory tax rate                    |  | 26.5  | % | 28.0  | % | 29.0  | % | 
|Expected income tax expense                                  |  | 605   |   | 495   |   | 540   |   | 
|Income tax differential related to regulated operations      |  | 42    |   | 8     |   | 39    |   | 
|Lower effective foreign tax rates                            |  | (5    | ) | (36   | ) | (63   | ) | 
|Tax rate and legislative changes                             |  |      |   |      |   | (30   | ) | 
|Income from equity investments and non-controlling interests |  | (45   | ) | (40   | ) | (37   | ) | 
|Other                                                        |  | (24   | ) | (47   | ) | (62   | ) | 
|                                                            
|Actual Income Tax Expense                                    |  | 573   |   | 380   |   | 387   |   | 
|                                                            

128NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



Future Income Tax Assets and Liabilities

|December 31 (millions of dollars)                                   |  | 2011  |  | 2010  |  |  |  | 
|------------------------------------------------------------------- |  | ----- |  | ----- |  |  |  | 
|                                                                    |  |      
|Future Income Tax Assets                                            |  |       |  |       |  |  |  | 
|Operating loss carryforwards                                        |  | 905   |  | 494   |  |  |  | 
|Financial instruments                                               |  | 163   |  | 108   |  |  |  | 
|Other post-employment benefits                                      |  | 74    |  | 75    |  |  |  | 
|Deferred amounts                                                    |  | 49    |  | 42    |  |  |  | 
|Other                                                               |  | 141   |  | 153   |  |  |  | 
|                                                                    |  |      
|                                                                    |  | 1,332 |  | 872   |  |  |  | 
|                                                                    |  |      
|Future Income Tax Liabilities                                       |  |       |  |       |  |  |  | 
|Difference in accounting and tax bases of plant, equipment and PPAs |  | 4,164 |  | 3,439 |  |  |  | 
|Taxes on future revenue requirement                                 |  | 299   |  | 321   |  |  |  | 
|Unrealized foreign exchange gains on long-term debt                 |  | 133   |  | 161   |  |  |  | 
|Pension benefits                                                    |  | 94    |  | 96    |  |  |  | 
|Other                                                               |  | 107   |  | 77    |  |  |  | 
|                                                                    |  |      
|                                                                    |  | 4,797 |  | 4,094 |  |  |  | 
|                                                                    |  |      
|Net Future Income Tax Liabilities                                   |  | 3,465 |  | 3,222 |  |  |  | 
|                                                                    |  |      

The
above future tax amounts have been classified in the Consolidated Balance Sheet as follows:

|December 31 (millions of dollars)     |  | 2011  |  | 2010  | (1) |  | 
|------------------------------------- |  | ----- |  | ----- | --- |  | 
|                                      |  |      
|Future Income Tax Assets              |  |       |  |       |     |  | 
|Other current assets                  |  | 265   |  | 93    |     |  | 
|Intangibles and other assets (Note 9) |  | 133   |  | 112   |     |  | 
|                                      |  |      
|                                      |  | 398   |  | 205   |     |  | 
|                                      |  |      
|Future Income Tax Liabilities         |  |       |  |       |     |  | 
|Accounts payable                      |  | 75    |  | 29    |     |  | 
|Future income taxes                   |  | 3,788 |  | 3,398 |     |  | 
|                                      |  |      
|                                      |  | 3,863 |  | 3,427 |     |  | 
|                                      |  |      
|Net Future Income Tax Liabilities     |  | 3,465 |  | 3,222 |     |  | 
|                                      |  |      

At
December 31, 2011, the Company has recognized the benefit of unused non-capital loss carryforwards of $450 million
(2010  $42 million) for federal and provincial purposes in Canada, which expire from 2014 to 2031.

At
December 31, 2011, the Company has recognized the benefit of unused net operating loss carryforwards of US$2,119 million
(2010  US$1,320 million) for federal purposes in the U.S., which expire from 2028 to 2031.

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, 2011 by approximately $136 million (2010  $105 million) if there had been a provision for
these taxes.

Income Tax Payments

Income tax refunds of $84 million, net of payments made, were received in 2011 (2010  payments, net of refunds, of
$53 million; 2009  payments, net of refunds, of $83 million).

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS129

---





NOTE 13    LONG-TERM DEBT

|                                                 |                                             |                |              | 2011                    |       | 2010 |                  |      
|------------------------------------------------ | ------------------------------------------- | -------------- | ------------ | ----------------------- | ----- | ---- | ---------------- | -----
|                                                 |                                             |                |              |                        
|Outstanding loan amounts
(millions of dollars)   |                                             | Maturity Dates |              | Outstanding
December 31 |       |      | Interest
Rate(1) |      
|                                                
|TRANSCANADA PIPELINES LIMITED                    |                                             |                |              |                         |       |      |                  |      
|Debentures                                       |                                             |                |              |                         |       |      |                  |      
|                                                 | Canadian dollars                            |                | 2014 to 2020 |                         | 873   |      |                  | 10.9%
|                                                 | U.S. dollars (2011 and 2010  US$600)       |                | 2012 to 2021 |                         | 608   |      |                  | 9.5% 
|Medium-Term Notes                                |                                             |                |              |                         |       |      |                  |      
|                                                 | Canadian dollars                            |                | 2013 to 2041 |                         | 4,537 |      |                  | 5.9% 
|Senior Unsecured Notes                           |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011 and 2010  US$8,626)(2)  |                | 2013 to 2040 |                         | 8,693 |      |                  | 5.7% 
|                                                 |                                             |                |              |                         |       |      |                  |      
|                                                 |                                             |                |              | 14,711                  |       |      |                  |      
|                                                 |                                             |                |              |                         |       |      |                  |      
|NOVA GAS TRANSMISSION LTD.                       |                                             |                |              |                         |       |      |                  |      
|Debentures and Notes                             |                                             |                |              |                         |       |      |                  |      
|                                                 | Canadian dollars                            |                | 2014 to 2024 |                         | 386   |      |                  | 11.5%
|                                                 | U.S. dollars (2011 and 2010  US$375)       |                | 2012 to 2023 |                         | 380   |      |                  | 8.2% 
|Medium-Term Notes                                |                                             |                |              |                         |       |      |                  |      
|                                                 | Canadian dollars                            |                | 2025 to 2030 |                         | 502   |      |                  | 7.4% 
|                                                 | U.S. dollars (2011 and 2010  US$33)        |                | 2026         |                         | 33    |      |                  | 7.5% 
|                                                 |                                             |                |              |                         |       |      |                  |      
|                                                 |                                             |                |              | 1,301                   |       |      |                  |      
|                                                 |                                             |                |              |                         |       |      |                  |      
|TRANSCANADA PIPELINE USA LTD.                    |                                             |                |              |                         |       |      |                  |      
|Bank Loan                                        |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011  US$500; 2010  US$700) |                | 2012         |                         | 509   |      |                  | 0.6% 
|                                                 |                                             |                |              |                         |       |      |                  |      
|ANR PIPELINE COMPANY                             |                                             |                |              |                         |       |      |                  |      
|Senior Unsecured Notes                           |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011 and 2010  US$432)       |                | 2021 to 2025 |                         | 438   |      |                  | 8.9% 
|                                                 |                                             |                |              |                         |       |      |                  |      
|GAS TRANSMISSION NORTHWEST CORPORATION           |                                             |                |              |                         |       |      |                  |      
|Senior Unsecured Notes                           |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011 and 2010  US$325)       |                | 2015 to 2035 |                         | 329   |      |                  | 5.5% 
|                                                 |                                             |                |              |                         |       |      |                  |      
|TC PIPELINES, LP                                 |                                             |                |              |                         |       |      |                  |      
|Unsecured Loan                                   |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011  US$363; 2010  US$483) |                | 2016         |                         | 366   |      |                  | 1.6% 
|Senior Unsecured Notes                           |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011  US$350)                |                | 2021         |                         | 356   |      |                  | 4.7% 
|                                                 |                                             |                |              |                         |       |      |                  |      
|                                                 |                                             |                |              | 722                     |       |      |                  |      
|                                                 |                                             |                |              |                         |       |      |                  |      
|GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP |                                             |                |              |                         |       |      |                  |      
|Senior Unsecured Notes                           |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011  US$373; 2010  US$392) |                | 2018 to 2030 |                         | 379   |      |                  | 7.8% 
|                                                 |                                             |                |              |                         |       |      |                  |      
|TUSCARORA GAS TRANSMISSION COMPANY               |                                             |                |              |                         |       |      |                  |      
|Senior Secured Notes                             |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011  US$30; 2010  US$31)   |                | 2012 to 2017 |                         | 31    |      |                  | 4.4% 
|                                                 |                                             |                |              |                         |       |      |                  |      
|PORTLAND NATURAL GAS TRANSMISSION SYSTEM         |                                             |                |              |                         |       |      |                  |      
|Senior Secured Notes(3)                          |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011  US$147; 2010  US$164) |                | 2018         |                         | 147   |      |                  | 6.1% 
|                                                 |                                             |                |              |                         |       |      |                  |      
|OTHER                                            |                                             |                |              |                         |       |      |                  |      
|Senior Notes                                     |                                             |                |              |                         |       |      |                  |      
|                                                 | U.S. dollars (2011  nil; 2010  US$12)     |                |              |                         |      |      |                  |     
|                                                 |                                             |                |              |                         |       |      |                  |      
|                                                 |                                             |                |              | 18,567                  |       |      |                  |      
|Less: Current Portion of Long-Term Debt          |                                             |                |              | 935                     |       |      |                  |      
|                                                 |                                             |                |              |                         |       |      |                  |      
|                                                 |                                             |                |              | 17,632                  |       |      |                  |      
|                                                 |                                             |                |              |                         |       |      |                  |      

130NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



Principal Repayments

Principal repayments on the long-term debt of the Company for the next five years are approximately as follows:
2012  $935 million; 2013  $903 million; 2014  $971 million;
2015  $1,084 million; and 2016 $1,227 million.

In
the normal course of business, TransCanada and various wholly owned subsidiaries also provide guarantees on behalf of the Company or wholly owned subsidiaries for debt
owed to third parties. This is to facilitate the extension of sufficient credit to accomplish their intended commercial activity.

TransCanada PipeLines Limited

In November 2011, TCPL issued $500 million and $250 million of Medium-Term Notes maturing November 15, 2021 and November 15, 2041,
respectively, and bearing interest at 3.65 per cent and 4.55 per cent, respectively.

In
May 2011, TCPL retired $60 million of 9.50 per cent Medium-Term Notes.

In
January 2011, TCPL retired $300 million of 4.3 per cent Medium-Term Notes.

In
September 2010, 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, 2011.

TransCanada PipeLine USA Ltd.

TCPL USA has an initial US$1.0 billion committed, unsecured, syndicated credit facility, guaranteed by TransCanada which was reduced to a US$800 million credit
facility through a US$200 million term loan repayment in August 2011. The facility consists of a US$500 million five-year term loan maturing in 2012 and a
US$300 million revolving facility maturing in February 2013, described further in Note 10. Included in Long-Term Debt was an outstanding balance of
US$500 million on the term loan at December 31, 2011 (2010  US$700 million) which was fully repaid in January
2012.

TC PipeLines, LP

In July 2011, TC PipeLines, LP increased its senior syndicated revolving credit facility to US$500 million and extended the maturity date to
July 2016. In December 2011, TC PipeLines, LP repaid a maturing US$300 million term loan with a draw under this facility, and at December 31, 2011,
US$363 million (2010  US$8 million) was outstanding on the facility.

In
June 2011, TC PipeLines, LP issued US$350 million of 4.65 per cent Senior Notes due 2021. The proceeds from the issuance were used to
partially repay TC PipeLines, LP's term loan and borrowings under its senior revolving credit facility, and repay its bridge loan facility described below.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS131

---



In
May 2011, TC PipeLines, LP made draws of US$61 million on a bridge loan facility and US$125 million on its senior revolving credit facility to
partially fund the acquisition of a 25 per cent interest in each of Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC (Bison LLC) as further
described in Note 23.

Interest Expense

|Year ended December 31 (millions of dollars) |  | 2011  |   | 2010  |   | 2009  |   | 
|-------------------------------------------- |  | ----- | - | ----- | - | ----- | - | 
|                                            
|Interest on long-term debt                   |  | 1,154 |   | 1,149 |   | 1,212 |   | 
|Interest on junior subordinated notes        |  | 63    |   | 65    |   | 73    |   | 
|Interest on short-term debt                  |  | 16    |   | 15    |   | 10    |   | 
|Capitalized interest                         |  | (302  | ) | (587  | ) | (358  | ) | 
|Amortization and other financial charges(1)  |  | 6     |   | 59    |   | 17    |   | 
|                                            
|                                             |  | 937   |   | 701   |   | 954   |   | 
|                                            

The
Company made interest payments of $926 million in 2011 (2010  $652 million;
2009  $916 million) on long-term debt and junior subordinated notes, net of interest capitalized on construction projects.

NOTE 14    LONG-TERM DEBT OF JOINT VENTURES

|                                                          |                                              |                |              | 2011                       |     | 2010 |                  |     
|--------------------------------------------------------- | -------------------------------------------- | -------------- | ------------ | -------------------------- | --- | ---- | ---------------- | ----
|                                                          |                                              |                |              |                           
|Outstanding loan amounts
(millions of dollars)            |                                              | Maturity Dates |              | Outstanding
December 31(1) |     |      | Interest
Rate(2) |     
|                                                         
|NORTHERN BORDER PIPELINE COMPANY                          |                                              |                |              |                            |     |      |                  |     
|Senior Unsecured Notes                                    |                                              |                |              |                            |     |      |                  |     
|                                                          | U.S. dollars (2011 and 2010  US$175)        |                | 2016 to 2021 |                            | 177 |      |                  | 7.1%
|Bank Facility                                             |                                              |                |              |                            |     |      |                  |     
|                                                          | U.S. dollars (2011  US$62; 2010   US$96)   |                | 2016         |                            | 62  |      |                  | 1.6%
|IROQUOIS GAS TRANSMISSION SYSTEM, L.P.                    |                                              |                |              |                            |     |      |                  |     
|Senior Unsecured Notes                                    |                                              |                |              |                            |     |      |                  |     
|                                                          | U.S. dollars (2011  US$169; 2010   US$178) |                | 2019 to 2027 |                            | 171 |      |                  | 6.1%
|BRUCE POWER L.P. AND BRUCE POWER A L.P.                   |                                              |                |              |                            |     |      |                  |     
|Capital Lease Obligations                                 |                                              | 2018           |              | 194                        |     |      | 7.5%             |     
|Term Loan                                                 |                                              | 2031           |              | 88                         |     |      | 7.1%             |     
|TRANS QUÉBEC & MARITIMES PIPELINE INC.                    |                                              |                |              |                            |     |      |                  |     
|Bonds                                                     |                                              | 2014 to 2017   |              | 87                         |     |      | 4.2%             |     
|Term Loan                                                 |                                              | 2016           |              | 30                         |     |      | 2.2%             |     
|OTHER                                                     |                                              | 2012 to 2016   |              | 13                         |     |      | 4.0%             |     
|                                                          |                                              |                |              |                            |     |      |                  |     
|                                                          |                                              |                |              | 822                        |     |      |                  |     
|Less: Current Portion of Long-Term Debt of Joint Ventures |                                              |                |              | 33                         |     |      |                  |     
|                                                          |                                              |                |              |                            |     |      |                  |     
|                                                          |                                              |                |              | 789                        |     |      |                  |     
|                                                          |                                              |                |              |                            |     |      |                  |     

132NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



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 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: 2012  $15 million; 2013  $8 million;
2014  $44 million; 2015  $7 million; and 2016  $149 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:
2012  $18 million; 2013  $20 million; 2014  $22 million;
2015  $26 million; and 2016  $31 million.

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
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.

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)    |  | 2011 |   | 2010 |  | 2009 |   | 
|----------------------------------------------- |  | ---- | - | ---- |  | ---- | - | 
|                                               
|Interest on long-term debt                      |  | 34   |   | 39   |  | 51   |   | 
|Interest on capital lease obligations           |  | 22   |   | 16   |  | 17   |   | 
|Short-term interest and other financial charges |  | (1   | ) | 4    |  | (4   | ) | 
|                                               
|                                                |  | 55   |   | 59   |  | 64   |   | 
|                                               

The
Company's proportionate share of the interest payments by joint ventures was $31 million in 2011 (2010  $42 million;
2009  $41 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 $15 million in 2011
(2010  $16 million; 2009  $17 million).

NOTE 15    JUNIOR SUBORDINATED NOTES

|                                              |                                         |               |      | 2011                    |       | 2010
|--------------------------------------------- | --------------------------------------- | ------------- | ---- | ----------------------- | ----- | ----
|                                              |                                         |               |      |                        
|Outstanding loan amount
(millions of dollars) |                                         | Maturity Date |      | Outstanding
December 31 |       |     
|                                             
|TRANSCANADA PIPELINES LIMITED                 |                                         |               |      |                         |       |     
|                                              | U.S. dollars (2011 and 2010  US$1,000) |               | 2017 |                         | 1,009 |     
|                                              |                                         |               |      |                         |       |     

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS133

---





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 16    NON-CONTROLLING INTERESTS

The Company's non-controlling interests included in the Consolidated Balance Sheet were as follows:

|December 31 (millions of dollars)               |  | 2011  |  | 2010  |  |  |  | 
|----------------------------------------------- |  | ----- |  | ----- |  |  |  | 
|                                                |  |      
|Non-controlling interest in TC PipeLines, LP(1) |  | 997   |  | 686   |  |  |  | 
|Preferred shares of subsidiary                  |  | 389   |  | 389   |  |  |  | 
|Non-controlling interest in Portland(2)         |  | 79    |  | 82    |  |  |  | 
|                                                |  |      
|                                                |  | 1,465 |  | 1,157 |  |  |  | 
|                                                |  |      

The
Company's non-controlling interests included in the Consolidated Income Statement were as follows:

|Year ended December 31 (millions of dollars)    |  | 2011 |  | 2010 |  | 2009 |  | 
|----------------------------------------------- |  | ---- |  | ---- |  | ---- |  | 
|                                               
|Non-controlling interest in TC PipeLines, LP(1) |  | 101  |  | 87   |  | 66   |  | 
|Preferred share dividends of subsidiary         |  | 22   |  | 22   |  | 22   |  | 
|Non-controlling interest in Portland(2)         |  | 6    |  | 6    |  | 8    |  | 
|                                               
|                                                |  | 129  |  | 115  |  | 96   |  | 
|                                               

Preferred Shares of Subsidiary

|December 31                                     | Number of
Shares |  | Dividend Rate
per Share |  | Redemption
Price per Share |  | 2011                  |  | 2010                  |  | 
|----------------------------------------------- | ---------------- |  | ----------------------- |  | -------------------------- |  | --------------------- |  | --------------------- |  | 
|                                               
|                                                | (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.

134NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



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 2011, 2010 and 2009.

In
2011, TransCanada received fees of $2 million from TC PipeLines, LP (2010 and 2009  $2 million) and
$7 million from Portland (2010  $7 million; 2009  $8 million) for services provided.

NOTE 17    COMMON SHARES

|                                 |                                               | Number of Shares |        | Amount                |       | 
|-------------------------------- | --------------------------------------------- | ---------------- | ------ | --------------------- | ----- | 
|                                
|                                 |                                               | (thousands)      |        | (millions of dollars) |       | 
|Outstanding at January 1, 2009   |                                               | 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                |       | 
|                                 | Dividend reinvestment and share purchase plan |                  | 5,371  |                       | 202   | 
|                                 | Exercise of options                           |                  | 2,260  |                       | 64    | 
|                                
|Outstanding at December 31, 2011 |                                               | 703,861          |        | 12,011                |       | 
|                                

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.

Net Income per Share

Net income per share is calculated by dividing Net Income Attributable to Common Shares by the weighted average number of common shares. During the year, the weighted average
number of common shares of 701.6 million and 702.8 million (2010  690.5 million and 691.7 million;
2009  651.8 million and 652.8 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.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS135

---



Stock Options

|                                 |  | Number of
Options |   |  |  | Weighted
Average
Exercise Prices |  | Options
Exercisable |  | 
|-------------------------------- |  | ----------------- | - |  |  | -------------------------------- |  | ------------------- |  | 
|                                
|                                 |  | (thousands)       |   |  |  |                                  |  | (thousands)         |  | 
|Outstanding at January 1, 2009   |  | 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               |  | 
|Granted                          |  | 970               |   |  |  | $38.02                           |  |                     |  | 
|Exercised                        |  | (2,260            | ) |  |  | $25.86                           |  |                     |  | 
|Forfeited                        |  | (16               | ) |  |  | $35.83                           |  |                     |  | 
|                                 |  |                   |   |  |  |                                  |  |                    
|Outstanding at December 31, 2011 |  | 7,100             |   |  |  | $35.44                           |  | 5,165               |  | 
|                                 |  |                   |   |  |  |                                  |  |                    

Stock
options outstanding were as follows:

|December 31, 2011        |        | Options Outstanding |       | Options Exercisable
|------------------------ | ------ | ------------------- | ----- | -------------------
|                        
|Range of Exercise Prices |        | Number of
Options   |       |                    
|                        
|                         |        | (thousands)         |       |                    
|$21.43 to $31.93         |        | 414                 |       |                    
|$31.97 to $33.08         |        | 1,496               |       |                    
|                         | $35.08 |                     | 1,135 |                    
|                         | $35.23 |                     | 1,001 |                    
|$36.26 to $38.10         |        | 2,100               |       |                    
|$38.14 to $41.65         |        | 954                 |       |                    
|                         |        |                     |       |                    
|                         |        | 7,100               |       |                    
|                         |        |                     |       |                    

An
additional 4.4 million common shares were reserved for future issuance under TransCanada's Stock Option Plan at December 31, 2011. The weighted average fair
value of options granted to purchase common shares under the Company's Stock Option Plan was determined to be $2.94 for the year ended December 31, 2011
(2010  $5.76; 2009  $4.78). The Company used the Black-Scholes model for determining the fair value of options granted
applying the following weighted average assumptions for
2011: four years of expected life (2010 and 2009  four years); 2.1 per cent interest rate
(2010  2.0 per cent; 2009  1.7 per cent); 14 per cent volatility
(2010  27 per cent; 2009  29 per cent); and 4.3 per cent dividend yield
(2010  4.7 per cent; 2009  5.2 per cent). Volatility is derived based on the historical
volatility of the Company's shares. The amount expensed for stock options, with a corresponding increase in contributed surplus, was $5 million in 2011 (2010 and
2009  $4 million).

The
total intrinsic value of options exercised in 2011 was $34 million (2010  $17 million;
2009  $15 million). As at December 31, 2011, the aggregate intrinsic value of the total options exercisable was $48 million and the total
intrinsic value of options outstanding was $64 million. In 2011, the 0.9 million (2010  1.5 million;
2009  1.2 million) shares that vested had a fair value of $42 million (2010  $57 million;
2009  $43 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.

136NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



Cash Dividends

Cash dividends of $961 million, net of the Dividend Reinvestment and Share Purchase Plan (DRP), or $1.66 per common share were paid in 2011
(2010  $710 million or $1.58 per common share; 2009  $722 million or $1.50 per common share).

Dividend Reinvestment and Share Purchase Plan

TransCanada's Board of Directors has authorized the issuance of common shares 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 Company reserves the right to satisfy its DRP
obligations by issuing common shares from treasury at a discount of up to five per cent or by purchasing shares on the open market. Commencing with the dividends declared in April 2011,
common shares purchased with reinvested cash dividends are satisfied with shares acquired on the open market at 100 per cent of the weighted average purchase price. Previously, common
shares purchased with reinvested cash dividends were satisfied with shares issued from treasury 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. In 2011, TransCanada issued 5.4 million
(2010  10.7 million; 2009  8.2 million) common shares from treasury in accordance with the DRP in lieu of
making cash dividend payments of $202 million (2010  $378 million; 2009  $254 million).

NOTE 18    PREFERRED SHARES

|December 31 |  | Number of Shares
Authorized and
Outstanding |  | Dividend Rate
per Share |  | Redemption
Price per Share |  | 2011                     |  | 2010                     |  | 
|----------- |  | ------------------------------------------- |  | ----------------------- |  | -------------------------- |  | ------------------------ |  | ------------------------ |  | 
|           
|            |  | (thousands)                                 |  |                         |  |                            |  | (millions of dollars)(1) |  | (millions of dollars)(1) |  | 
|
|Series 1    |  | 22,000                                      |  | $1.15                   |  | $25.00                     |  | 539                      |  | 539                      |  | 
|Series 3    |  | 14,000                                      |  | $1.00                   |  | $25.00                     |  | 343                      |  | 343                      |  | 
|Series 5    |  | 14,000                                      |  | $1.10                   |  | $25.00                     |  | 342                      |  | 342                      |  | 
|            |  |                                             |  |                         |  |                            |  |                         
|            |  |                                             |  |                         |  |                            |  | 1,224                    |  | 1,224                    |  | 
|            |  |                                             |  |                         |  |                            |  |                         

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, 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, 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.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS137

---





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, 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 and 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 2011, the Company made cash dividend payments of $25 million, net of DRP, or $1.15 per Series 1 preferred share
(2010  $24 million or $1.15 per share; 2009  $6 million or $0.2875 per share), $14 million, net of
DRP, or $1.00 per Series 3 preferred share (2010  $11 million or $0.8041 per share) and $16 million, net of DRP, or $1.10 per
Series 5 preferred share (2010  $9 million or $0.3707 per share).

NOTE 19    ASSET RETIREMENT OBLIGATIONS

The scope and timing of asset retirements related to regulated oil and natural gas pipelines in the U.S. and hydroelectric power plants is indeterminable. 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.

Through
its Land Matters Consultation Initiative, the NEB is addressing several significant issues relating to future pipeline abandonment costs for Canadian regulated
pipelines. 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. TransCanada filed its estimates of abandonment costs for its Canadian natural gas and oil pipelines on November 30, 2011, as required by the NEB decision.
These estimates are expected to clarify the scope of ARO, however, the timing of retirements for these assets remains indeterminable. As a result, the Company has not recorded an amount for ARO
related to these assets.

ARO
recognized in the Natural Gas Pipelines segment relates to non-regulated natural gas pipelines and regulated natural gas storage operations. The estimated
undiscounted cash flows required to settle the ARO with respect to these operations were $63 million at December 31, 2011
(2010  $62 million), calculated using an annual inflation rate ranging from 1.2 per cent to 4.0 per cent. The estimated fair
value of this liability was $26 million at December 31, 2011 (2010  $24 million) after discounting the estimated cash flows at rates ranging
from 4.3 per cent to 11.0 per cent. At December 31, 2011, the expected timing of payment for settlement of the obligations ranged from 2012 to 2029.

ARO
recognized in the Energy segment relates to certain power generation facilities and non-regulated natural gas storage facilities. The estimated undiscounted
cash flows required to settle the ARO with respect to the Energy segment were $641 million at December 31, 2011 (2010  $719 million),
calculated using an annual inflation rate ranging from 2.0 per cent to 2.5 per cent. The estimated fair value of this liability was $43 million at
December 31, 2011 (2010  $42 million), after discounting the estimated cash flows at average rates ranging from 5.2 per cent to
6.8 per cent. During 2010, the economic life of certain Energy assets was extended after reviewing market trends and asset conditions. At December 31, 2011, the expected timing of
payment for settlement of the obligations ranged from 2018 to 2061.

Reconciliation of Asset Retirement Obligations(1)

|(millions of dollars)                                 |  | Natural Gas Pipelines |   | Energy |   | Total |   | 
|----------------------------------------------------- |  | --------------------- | - | ------ | - | ----- | - | 
|                                                     
|Balance at January 1, 2010                            |  | 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    |   | 
|New obligations and revisions in estimated cash flows |  |                      |   | (1     | ) | (1    | ) | 
|Accretion expense                                     |  | 2                     |   | 2      |   | 4     |   | 
|                                                     
|Balance at December 31, 2011                          |  | 26                    |   | 43     |   | 69    |   | 
|                                                     

138NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



NOTE 20    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 (2010  eight years;
2009  eight years).

The
Company also provides its employees with a Savings Plan in Canada, DC Plans consisting of 401(k) 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, 2011. Contributions to the Savings Plan and DC Plans are expensed as
incurred. In 2011, the Company expensed $23 million (2010 and 2009  $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 $93 million in 2011
(2010  $127 million; 2009  $168 million), including $23 million in 2011 (2010 and
2009  $21 million) related to the Savings Plan and DC Plans. In addition to these cash payments, in 2011 the Company provided a $27 million
letter of credit to the DB Plan.

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, 2012, and the next required valuation will be as at January 1, 2013.

|                                                                     |  | Pension Benefit Plans |   | Other Benefit Plans |   |     
|-------------------------------------------------------------------- |  | --------------------- | - | ------------------- | - | ----
|                                                                     |  |                      
|December 31 (millions of dollars)                                    |  | 2011                  |   | 2010                |   | 2011
|                                                                    
|Change in Benefit Obligation                                         |  |                       |   |                     |   |     
|Benefit obligation  beginning of year                               |  | 1,622                 |   | 1,476               |   | 159 
|Current service cost                                                 |  | 54                    |   | 50                  |   | 2   
|Interest cost                                                        |  | 91                    |   | 89                  |   | 9   
|Employee contributions                                               |  | 4                     |   | 4                   |   | 1   
|Benefits paid                                                        |  | (71                   | ) | (73                 | ) | (9  
|Actuarial loss                                                       |  | 131                   |   | 95                  |   | 7   
|Transfers                                                            |  |                      |   | (8                  | ) |    
|Foreign exchange rate changes                                        |  | 5                     |   | (11                 | ) | 1   
|                                                                    
|Benefit obligation  end of year                                     |  | 1,836                 |   | 1,622               |   | 170 
|                                                                    
|Change in Plan Assets                                                |  |                       |   |                     |   |     
|Plan assets at fair value  beginning of year                        |  | 1,636                 |   | 1,447               |   | 29  
|Actual return on plan assets                                         |  | 21                    |   | 177                 |   |    
|Employer contributions                                               |  | 62                    |   | 98                  |   | 8   
|Employee contributions                                               |  | 4                     |   | 4                   |   | 1   
|Benefits paid                                                        |  | (71                   | ) | (73                 | ) | (9  
|Transfers                                                            |  |                      |   | (8                  | ) |    
|Foreign exchange rate changes                                        |  | 4                     |   | (9                  | ) |    
|                                                                    
|Plan assets at fair value  end of year                              |  | 1,656                 |   | 1,636               |   | 29  
|                                                                    
|Funded status  plan (deficit)/surplus                               |  | (180                  | ) | 14                  |   | (141
|Unamortized net actuarial loss                                       |  | 549                   |   | 345                 |   | 50  
|Unamortized past service costs                                       |  | 15                    |   | 18                  |   | (3  
|                                                                    
|Accrued Benefit Asset/(Liability), Net of Valuation Allowance of Nil |  | 384                   |   | 377                 |   | (94 
|                                                                    

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) |  | 2011                  |   | 2010                |   | 2011
|                                 
|Intangibles and Other Assets      |  | 399                   |   | 380                 |   |    
|Deferred Amounts                  |  | (15                   | ) | (3                  | ) | (94 
|                                 
|                                  |  | 384                   |   | 377                 |   | (94 
|                                 

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS139

---



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) |  | 2011                  |   | 2010                |   | 2011
|                                 
|Benefit obligation                |  | (1,836                | ) | (417                | ) | (170
|Plan assets at fair value         |  | 1,656                 |   | 391                 |   | 29  
|                                 
|Funded Status  Plan Deficit      |  | (180                  | ) | (26                 | ) | (141
|                                 

The
Company's expected funding contributions in 2012 are approximately $119 million for the DB Plans and approximately $31 million for the other benefit plans,
Savings Plan and DC Plans. In addition to these contributions, the Company expects to provide a $48 million letter of credit in 2012 to the DB Plan.

The
following are estimated future benefit payments, which reflect expected future service:

|(millions of dollars) |  | Pension
Benefits |  | Other
Benefits |  | 
|--------------------- |  | ---------------- |  | -------------- |  | 
|                     
|2012                  |  | 85               |  | 9              |  | 
|2013                  |  | 90               |  | 9              |  | 
|2014                  |  | 94               |  | 10             |  | 
|2015                  |  | 99               |  | 10             |  | 
|2016                  |  | 104              |  | 10             |  | 
|2017 to 2021          |  | 591              |  | 57             |  | 

The
rate used to discount pension and other post-employment benefit plan obligations was developed based on a yield curve of corporate AA bond yields at
December 31, 2011. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other
post-employment obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.

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                   |  | 2011                  |  | 2010                |  | 2011 
|                             
|Discount rate                 |  | 5.05%                 |  | 5.55%               |  | 5.10%
|Rate of compensation increase |  | 3.15%                 |  | 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                           |  | 2011                  |  | 2010                |  | 2009 
|                                                
|Discount rate                                    |  | 5.55%                 |  | 6.00%               |  | 6.65%
|Expected long-term rate of return on plan assets |  | 6.95%                 |  | 6.95%               |  | 6.95%
|Rate of compensation increase                    |  | 3.10%                 |  | 3.20%               |  | 3.25%

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.

140NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



An
8.50 per cent average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012 measurement purposes. The rate was
assumed to decrease gradually to five per cent by 2019 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            |  | 15       |  | (13      | ) | 

The
Company's net benefit cost is as follows:

|                                                                                                                   |  | Pension Benefit Plans |   | Other Benefit Plans |   |     
|------------------------------------------------------------------------------------------------------------------ |  | --------------------- | - | ------------------- | - | ----
|                                                                                                                   |  |                      
|Year ended December 31 (millions of dollars)                                                                       |  | 2011                  |   | 2010                |   | 2009
|                                                                                                                  
|Current service cost                                                                                               |  | 54                    |   | 50                  |   | 45  
|Interest cost                                                                                                      |  | 91                    |   | 89                  |   | 89  
|Actual return on plan assets                                                                                       |  | (21                   | ) | (177                | ) | (206
|Actuarial loss                                                                                                     |  | 131                   |   | 95                  |   | 107 
|                                                                                                                  
|Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost            |  | 255                   |   | 57                  |   | 35  
|Difference between expected and actual return on plan assets                                                       |  | (93                   | ) | 68                  |   | 107 
|Difference between actuarial loss/(gain) recognized and actual actuarial loss/(gain) on accrued benefit obligation |  | (110                  | ) | (86                 | ) | (101
|Difference between amortization of past service costs and actual plan amendments                                   |  | 3                     |   | 4                   |   | 4   
|Amortization of transitional obligation related to regulated business                                              |  |                      |   |                    |   |    
|                                                                                                                  
|                                                                                                                   |  | 55                    |   | 43                  |   | 45  
|                                                                                                                  

The
Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:

Asset Category

|                  |  | Percentage of Plan Assets |  | Target Allocations |  | 
|----------------- |  | ------------------------- |  | ------------------ |  | 
|                  |  |                          
|December 31       |  | 2011                      |  | 2010               |  | 
|                 
|Debt securities   |  | 39%                       |  | 37%                |  | 
|Equity securities |  | 61%                       |  | 63%                |  | 
|                  |  |                           |  |                    |  | 
|                  |  | 100%                      |  | 100%               |  | 
|                  |  |                           |  |                    |  | 

Debt
securities included the Company's debt of $2 million (0.1 per cent of total plan assets) and $4 million (0.2 per cent of total
plan assets) at December 31, 2011 and 2010, respectively. Equity securities included the Company's common shares of $3 million (0.2 per cent of total plan assets) and
$3 million (0.2 per cent of total plan assets) at December 31, 2011 and 2010, respectively.

Pension
plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable
level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities, as well as alternative assets such as infrastructure, private equity and
derivatives to diversify 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.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS141

---



The
following table presents plan assets for DB Plans and other post-employment benefits measured at fair value, which have been categorized into three
categories based on a fair value hierarchy. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets. In Level II,
determination of the fair value of assets includes valuations using inputs, other than quoted prices, for which all significant inputs 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 is based on
inputs that are not readily observable and are significant to the overall fair value measurement.

|Asset Category                             | Quoted
Prices in
Active Markets
(Level I) |                 | Significant Other
Observable
Inputs
(Level II) |     | Significant
Unobservable
Inputs
(Level III) |     | Total |     | Percentage of
Total Portfolio |    |     
|------------------------------------------ | ----------------------------------------- | --------------- | ---------------------------------------------- | --- | ------------------------------------------- | --- | ----- | --- | ----------------------------- | -- | ----
|                                           |                                          
|December 31
(millions of Canadian dollars) | 2011                                      |                 | 2010                                           |     | 2011                                        |     | 2010  |     | 2011                          |    | 2010
|                                          
|Cash and cash equivalents                  | 25                                        |                 | 19                                             |     |                                            |     |      |     |                              |    |    
|Equity Securities:                         |                                           |                 |                                                |     |                                             |     |       |     |                               |    |     
|                                           | Canadian                                  | 374             |                                                | 394 |                                             | 95  |       | 93  |                               |   |     
|                                           | U.S.                                      | 251             |                                                | 225 |                                             | 55  |       | 117 |                               |   |     
|                                           | International                             | 25              |                                                | 31  |                                             | 231 |       | 199 |                               |   |     
|Fixed Income Securities:                   |                                           |                 |                                                |     |                                             |     |       |     |                               |    |     
|                                           | Canadian Bonds:                           |                 |                                                |     |                                             |     |       |     |                               |    |     
|                                           |                                           | Federal         |                                               |     |                                            |     | 303   |     | 302                           |    |    
|                                           |                                           | Provincial      |                                               |     |                                            |     | 158   |     | 127                           |    |    
|                                           |                                           | Municipal       |                                               |     |                                            |     | 4     |     | 4                             |    |    
|                                           |                                           | Corporate       |                                               |     |                                            |     | 47    |     | 64                            |    |    
|                                           | U.S. Bonds:                               |                 |                                                |     |                                             |     |       |     |                               |    |     
|                                           |                                           | State           |                                               |     |                                            |     | 29    |     | 28                            |    |    
|                                           |                                           | Corporate       |                                               |     |                                            |     | 29    |     | 19                            |    |    
|                                           | International:                            |                 |                                                |     |                                             |     |       |     |                               |    |     
|                                           |                                           | Corporate       |                                               |     |                                            |     | 9     |     |                              |    |    
|                                           |                                           | Mortgage Backed |                                               |     |                                            |     | 30    |     | 22                            |    |    
|Other Investments:                         |                                           |                 |                                                |     |                                             |     |       |     |                               |    |     
|                                           | Private Equity Funds                      |                |                                                |    |                                             |    |       |    |                               | 20 |     
|                                          
|                                           | 675                                       |                 | 669                                            |     | 990                                         |     | 975   |     | 20                            |    | 21  
|                                          

The
following table presents the net change in the Level III fair value category:

|(millions of dollars, pre-tax) |  | Private Equity
Funds |  
|------------------------------ |  | -------------------- | -
|                               | 
|Balance at December 31, 2009   |  | 25                   |  
|Realized and unrealized losses |  | (6                   | )
|Purchases and sales            |  | 2                    |  
|                               | 
|Balance at December 31, 2010   |  | 21                   |  
|Realized and unrealized losses |  | (2                   | )
|Purchases and sales            |  | 1                    |  
|                               | 
|Balance at December 31, 2011   |  | 20                   |  
|                               | 

142NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



Employee Future Benefits of Joint Ventures

Certain of the Company's joint ventures sponsor DB Plans as well as post-employment benefits other than pensions, including defined life insurance and medical benefits beyond
those provided by government-sponsored plans. The obligations of these plans are non-recourse to 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 $59 million
in 2011 (2010  $58 million; 2009  $54 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, 2012, and the next required valuations will be as at January 1, 2013.

|                                                                     |  | Pension Benefit Plans |   | Other Benefit Plans |   |     
|-------------------------------------------------------------------- |  | --------------------- | - | ------------------- | - | ----
|                                                                     |  |                      
|December 31 (millions of dollars)                                    |  | 2011                  |   | 2010                |   | 2011
|                                                                    
|Change in Benefit Obligation                                         |  |                       |   |                     |   |     
|Benefit obligation  beginning of year                               |  | 864                   |   | 695                 |   | 208 
|Current service cost                                                 |  | 27                    |   | 19                  |   | 11  
|Interest cost                                                        |  | 46                    |   | 42                  |   | 11  
|Employee contributions                                               |  | 8                     |   | 7                   |   |    
|Benefits paid                                                        |  | (33                   | ) | (31                 | ) | (4  
|Actuarial loss                                                       |  | 73                    |   | 132                 |   | 25  
|                                                                    
|Benefit obligation  end of year                                     |  | 985                   |   | 864                 |   | 251 
|                                                                    
|Change in Plan Assets                                                |  |                       |   |                     |   |     
|Plan assets at fair value  beginning of year                        |  | 727                   |   | 641                 |   |    
|Actual return on plan assets                                         |  | 13                    |   | 57                  |   |    
|Employer contributions                                               |  | 53                    |   | 53                  |   | 6   
|Employee contributions                                               |  | 8                     |   | 7                   |   |    
|Benefits paid                                                        |  | (33                   | ) | (31                 | ) | (4  
|                                                                    
|Plan assets at fair value  end of year                              |  | 768                   |   | 727                 |   | 2   
|                                                                    
|Funded status  plan deficit                                         |  | (217                  | ) | (137                | ) | (249
|Unamortized net actuarial loss                                       |  | 317                   |   | 230                 |   | 71  
|Unamortized past service costs                                       |  |                      |   |                    |   | 2   
|                                                                    
|Accrued Benefit Asset/(Liability), Net of Valuation Allowance of Nil |  | 100                   |   | 93                  |   | (176
|                                                                    

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) |  | 2011                  |  | 2010                |  | 2011
|                                 
|Intangibles and Other Assets      |  | 100                   |  | 93                  |  |    
|Deferred Amounts                  |  |                      |  |                    |  | (176
|                                 
|                                  |  | 100                   |  | 93                  |  | (176
|                                 

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) |  | 2011                  |   | 2010                |   | 2011
|                                 
|Benefit obligation                |  | (979                  | ) | (864                | ) | (251
|Plan assets at fair value         |  | 761                   |   | 727                 |   | 2   
|                                 
|Funded Status  Plan Deficit      |  | (218                  | ) | (137                | ) | (249
|                                 

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS143

---



The
expected total funding contributions of the Company's joint ventures in 2012 are approximately $73 million for the pension benefit plans and approximately
$7 million for the other benefit plans.

The
following are estimated future benefit payments, which reflect expected future service:

|(millions of dollars) |  | Pension
Benefits |  | Other
Benefits |  | 
|--------------------- |  | ---------------- |  | -------------- |  | 
|                     
|2012                  |  | 37               |  | 7              |  | 
|2013                  |  | 38               |  | 8              |  | 
|2014                  |  | 40               |  | 8              |  | 
|2015                  |  | 42               |  | 9              |  | 
|2016                  |  | 44               |  | 10             |  | 
|2017 to 2021          |  | 310              |  | 60             |  | 

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                   |  | 2011                  |  | 2010                |  | 2011 
|                             
|Discount rate                 |  | 4.75%                 |  | 5.25%               |  | 4.60%
|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                           |  | 2011                  |  | 2010                |  | 2009 
|                                                
|Discount rate                                    |  | 5.25%                 |  | 6.00%               |  | 6.75%
|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%

An
8.50 per cent average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012 measurement purposes. The rate was
assumed to decrease gradually to five per cent by 2019 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 |  | 4        |  | (3       | ) | 
|Effect on post-employment benefit obligation            |  | 35       |  | (28      | ) | 

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)                                                                       |  | 2011                  |   | 2010                |   | 2009
|                                                                                                                  
|Current service cost                                                                                               |  | 27                    |   | 19                  |   | 16  
|Interest cost                                                                                                      |  | 46                    |   | 42                  |   | 40  
|Actual return on plan assets                                                                                       |  | (13                   | ) | (57                 | ) | (63 
|Actuarial loss/(gain)                                                                                              |  | 73                    |   | 132                 |   | 68  
|                                                                                                                  
|Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost            |  | 133                   |   | 136                 |   | 61  
|Difference between expected and actual return on plan assets                                                       |  | (38                   | ) | 12                  |   | 25  
|Difference between actuarial loss/(gain) recognized and actual actuarial loss/(gain) on accrued benefit obligation |  | (62                   | ) | (128                | ) | (67 
|                                                                                                                  
|                                                                                                                   |  | 33                    |   | 20                  |   | 19  
|                                                                                                                  

144NOTES 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    |  | 2011                      |  | 2010               |  | 
|                 
|Debt securities   |  | 45%                       |  | 41%                |  | 
|Equity securities |  | 55%                       |  | 59%                |  | 
|                  |  |                           |  |                    |  | 
|                  |  | 100%                      |  | 100%               |  | 
|                  |  |                           |  |                    |  | 

Debt
securities included the Company's debt of $1 million (0.2 per cent of total plan assets) and $1 million (0.2 per cent of total
plan assets) at December 31, 2011 and 2010, respectively. Equity securities included the Company's common shares of $4 million (0.6 per cent of total plan assets) and
$4 million (0.5 per cent of total plan assets) at December 31, 2011 and 2010, 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 21    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 financial 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:

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
STATEMENTS145

---



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 and natural gas. A number of
strategies are used to mitigate these exposures, including the following:

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.

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
interest rates.

A
portion of TransCanada's earnings from its Natural Gas Pipelines, Oil 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, 2011, the Company had designated as a net investment hedge
U.S. dollar-denominated debt with a carrying value of $10 billion (US$9.8 billion) (2010  $9.8 billion (US$9.8 billion)) and a
fair value of $12.7 billion (US$12.5 billion) (2010  $11.3 billion (US$11.4 billion)). At December 31, 2011,
$79 million (December 31, 2010  nil) was included in Other Current Assets, $66 million (December 31,
2010  $181 million) was included in Intangibles and Other Assets, $15 million (December 31,
2010  nil) was included in Accounts Payable, and $41 million (December 31, 2010  nil) was included in
Deferred Amounts for the fair value of the forwards and swaps used to hedge the Company's net U.S. dollar investment in foreign operations.

146NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



The
fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows:

|                                                               |  | 2011          |   | 2010                         |  |              
|-------------------------------------------------------------- |  | ------------- | - | ---------------------------- |  | -------------
|                                                               |  |              
|Asset/(Liability)December 31 (millions of dollars)             |  | Fair Value(1) |   | Notional or
Principal
Amount |  | Fair Value(1)
|                                                              
|U.S. dollar cross-currency swaps (maturing 2012 to 2018)       |  | 93            |   | US 3,850                     |  | 179          
|U.S. dollar forward foreign exchange contracts (maturing 2012) |  | (4            | ) | US 725                       |  | 2            
|                                                              
|                                                               |  | 89            |   | US 4,575                     |  | 181          
|                                                              

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, 2011
(2010  $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 the financial instruments 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 contract 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, portfolio investments recorded at fair value, 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, and Available for sale assets in the Non-Derivative Financial Instruments Summary table located
in the Fair Values section of this note. The majority of counterparty credit exposure is with counterparties that are investment grade or the exposure is supported by financial assurances provided by
investment grade parties. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At
December 31, 2011, there were no significant amounts past due or impaired, and there were no significant credit losses during the year.

At
December 31, 2011, the Company had a credit risk concentration of $274 million (2010  $317 million) due from a
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

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS147

---



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.

In
August 2011, the Company received final distributions of 2.1 million common shares as a result of previous claims in the 2005 Calpine Corporation
bankruptcy. These shares were sold into the open market resulting in total pre-tax gains of $30 million, of which the Company had accrued pre-tax gains of
$15 million in 2010. In 2008, the Company had received
15.5 million common shares which were sold into the open market for $279 million. Claims by NGTL and Foothills PipeLines (South B.C.) Ltd. for $32 million and
$44 million, respectively, were received in cash in 2008 and 2009 and were passed onto the shippers on these systems in 2008 and 2009.

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, 2011, the Company had unutilized committed revolving bank lines of US$1.0 billion, US$1.0 billion, US$300 million and
$2.0 billion maturing in October 2012, November 2012, February 2013 and October 2016, respectively. The Company has also maintained continuous access to the Canadian
commercial paper market on competitive terms and recently initiated a commercial paper program in the U.S.

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 2011, 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 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)                |  | 2011   |   | 2010   |   | 
|------------------------------------------------ |  | ------ | - | ------ | - | 
|                                                
|Notes payable                                    |  | 1,863  |   | 2,081  |   | 
|Long-term debt                                   |  | 18,567 |   | 17,922 |   | 
|Junior subordinated notes                        |  | 1,009  |   | 985    |   | 
|Cash and cash equivalents                        |  | (654   | ) | (660   | ) | 
|                                                
|Net Debt                                         |  | 20,785 |   | 20,328 |   | 
|                                                
|Equity attributable to non-controlling interests |  | 1,465  |   | 1,157  |   | 
|Equity attributable to controlling interests     |  | 17,324 |   | 16,727 |   | 
|                                                
|Total Equity                                     |  | 18,789 |   | 17,884 |   | 
|                                                
|                                                 |  | 39,574 |   | 38,212 |   | 
|                                                

|
|

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 and natural gas 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. The fair value of
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.

148NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---





Non-Derivative Financial Instruments Summary

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

|                                         |  | 2011            |  | 2010       |  |                
|---------------------------------------- |  | --------------- |  | ---------- |  | ---------------
|                                         |  |                
|December 31 (millions of dollars)        |  | Carrying
Amount |  | Fair
Value |  | Carrying
Amount
|                                        
|Financial Assets(1)                      |  |                 |  |            |  |                
|Cash and cash equivalents                |  | 765             |  | 765        |  | 764            
|Accounts receivable and other(2)(3)      |  | 1,576           |  | 1,620      |  | 1,555          
|Available for sale assets(2)             |  | 23              |  | 23         |  | 20             
|                                        
|                                         |  | 2,364           |  | 2,408      |  | 2,339          
|                                        
|Financial Liabilities(1)(3)              |  |                 |  |            |  |                
|Notes payable                            |  | 1,880           |  | 1,880      |  | 2,092          
|Accounts payable and deferred amounts(4) |  | 1,536           |  | 1,536      |  | 1,436          
|Accrued interest                         |  | 373             |  | 373        |  | 367            
|Long-term debt                           |  | 18,567          |  | 23,757     |  | 17,922         
|Junior subordinated notes                |  | 1,009           |  | 1,027      |  | 985            
|Long-term debt of joint ventures         |  | 822             |  | 940        |  | 866            
|                                        
|                                         |  | 24,187          |  | 29,513     |  | 23,668         
|                                        

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, 2011:

Contractual Repayments of Financial Liabilities(1)

|                                 |  |        |  | Payments Due by Period
|-------------------------------- |  | ------ |  | ----------------------
|                                 |  |        |  |                       
|(millions of dollars)            |  | Total  |  | 2012                  
|                                
|Notes payable                    |  | 1,880  |  | 1,880                 
|Long-term debt                   |  | 18,567 |  | 935                   
|Junior subordinated notes        |  | 1,009  |  |                      
|Long-term debt of joint ventures |  | 822    |  | 33                    
|                                
|                                 |  | 22,278 |  | 2,848                 
|                                

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS149

---



Interest Payments on Financial Liabilities

|                                 |  |        |  | Payments Due by Period
|-------------------------------- |  | ------ |  | ----------------------
|                                 |  |        |  |                       
|(millions of dollars)            |  | Total  |  | 2012                  
|                                
|Long-term debt                   |  | 16,541 |  | 1,180                 
|Junior subordinated notes        |  | 355    |  | 65                    
|Long-term debt of joint ventures |  | 343    |  | 48                    
|                                
|                                 |  | 17,239 |  | 1,293                 
|                                

|
|

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments for 2011, excluding hedges of the Company's net investment in self-sustaining foreign operations, is
as follows:

|                                                                 |                  | 2011      |       |            
|---------------------------------------------------------------- | ---------------- | --------- | ----- | -----------
|                                                                 |                  |          
|December 31
(all amounts in millions unless otherwise indicated) |                  | Power     |       | Natural
Gas
|                                                                
|Derivative Financial Instruments Held for Trading(1)             |                  |           |       |            
|Fair Values(2)                                                   |                  |           |       |            
|                                                                 | Assets           |           | $213  |            
|                                                                 | Liabilities      |           | $(212 | )          
|Notional Values                                                  |                  |           |       |            
|                                                                 | Volumes(3)       |           |       |            
|                                                                 |                  | Purchases |       | 23,500     
|                                                                 |                  | Sales     |       | 23,158     
|                                                                 | Canadian dollars |           |      |            
|                                                                 | U.S. dollars     |           |      |            
|                                                                 | Cross-currency   |           |      |            
|Net unrealized (losses)/gains in the year(4)                     |                  | $(3       | )     | $(50       
|Net realized gains/(losses) in the year(4)                       |                  | $58       |       | $(74       
|Maturity dates                                                   |                  | 2012-2018 |       | 2012-2016  
|Derivative Financial Instruments in Hedging Relationships(5)(6)  |                  |           |       |            
|Fair Values(2)                                                   |                  |           |       |            
|                                                                 | Assets           |           | $42   |            
|                                                                 | Liabilities      |           | $(277 | )          
|Notional Values                                                  |                  |           |       |            
|                                                                 | Volumes(3)       |           |       |            
|                                                                 |                  | Purchases |       | 17,188     
|                                                                 |                  | Sales     |       | 9,217      
|                                                                 | U.S. dollars     |           |      |            
|                                                                 | Cross-currency   |           |      |            
|Net realized losses in the year(4)                               |                  | $(150     | )     | $(17       
|Maturity dates                                                   |                  | 2012-2017 |       | 2012-2013  

150NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



The
anticipated timing of settlement of the derivative contracts assumes constant commodity prices, interest rates and foreign exchange rates from December 31, 2011.
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:

|(millions of dollars)                                     |             | Total |      | 2012 |      | 2013 and
2014 |      | 2015 and
2016 |     | 2017 and
Thereafter |     |  
|--------------------------------------------------------- | ----------- | ----- | ---- | ---- | ---- | ------------- | ---- | ------------- | --- | ------------------- | --- | -
|                                                         
|Derivative financial instruments held for trading         |             |       |      |      |      |               |      |               |     |                     |     |  
|                                                          | Assets      |       | 414  |      | 282  |               | 123  |               | 9   |                     |    |  
|                                                          | Liabilities |       | (460 | )    | (292 | )             | (151 | )             | (17 | )                   |    |  
|Derivative financial instruments in hedging relationships |             |       |      |      |      |               |      |               |     |                     |     |  
|                                                          | Assets      |       | 217  |      | 121  |               | 91   |               | 5   |                     |    |  
|                                                          | Liabilities |       | (408 | )    | (208 | )             | (135 | )             | (50 | )                   | (15 | )
|                                                         
|                                                          |             | (237  | )    | (97  | )    | (72           | )    | (53           | )   | (15                 | )   |  
|                                                         

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments for 2010, excluding hedges of the Company's net investment in self-sustaining foreign operations, is
as follows:

|                                                                 |                  | 2010     
|---------------------------------------------------------------- | ---------------- | ---------
|                                                                 |                  |          
|December 31
(all amounts in millions unless otherwise indicated) |                  | Power    
|                                                                
|Derivative Financial Instruments Held for Trading(1)             |                  |          
|Fair Values(2)                                                   |                  |          
|                                                                 | Assets           |          
|                                                                 | Liabilities      |          
|Notional Values                                                  |                  |          
|                                                                 | Volumes(3)       |          
|                                                                 |                  | Purchases
|                                                                 |                  | Sales    
|                                                                 | Canadian dollars |          
|                                                                 | U.S. dollars     |          
|                                                                 | Cross-currency   |          
|Net unrealized (losses)/gains in the year(4)                     |                  | $(32     
|Net realized gains/(losses) in the year(4)                       |                  | $77      
|Maturity dates                                                   |                  | 2011-2015
|Derivative Financial Instruments in Hedging Relationships(5)(6)  |                  |          
|Fair Values(2)                                                   |                  |          
|                                                                 | Assets           |          
|                                                                 | Liabilities      |          
|Notional Values                                                  |                  |          
|                                                                 | Volumes(3)       |          
|                                                                 |                  | Purchases
|                                                                 |                  | Sales    
|                                                                 | U.S. dollars     |          
|                                                                 | Cross-currency   |          
|Net realized losses in the year(4)                               |                  | $(9      
|Maturity dates                                                   |                  | 2011-2015

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS151

---



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)     |  | 2011 |   | 2010 |   | 
|------------------------------------- |  | ---- | - | ---- | - | 
|                                     
|Current                               |  |      |   |      |   | 
|Other current assets                  |  | 404  |   | 273  |   | 
|Accounts payable                      |  | (502 | ) | (337 | ) | 
|Long Term                             |  |      |   |      |   | 
|Intangibles and other assets (Note 9) |  | 213  |   | 374  |   | 
|Deferred amounts (Note 11)            |  | (352 | ) | (282 | ) | 

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 derivatives was $35 million at December 31, 2011
(2010  $48 million). These contracts mature from 2012 to 2018. The Company's proportionate share of the notional sales volumes of power associated with
this exposure was 2,979 gigawatt hours (GWh) at December 31, 2011 (2010  3,772 GWh). The Company's proportionate share of the notional
purchased volumes of power associated with this exposure was 1,595 GWh at December 31, 2011 (2010  2,322 GWh).

Derivatives in Cash Flow Hedging Relationships

Information about how derivatives and hedging activities affect the Company's financial position, financial performance and cash flows is as follows:

|                                                                                                           |  | Cash Flow Hedges |   |                        
|---------------------------------------------------------------------------------------------------------- |  | ---------------- | - | -----------------------
|                                                                                                           |  |                 
|Year ended December 31                                                                                     |  | Power            |   | Natural
            Gas
|                                                                                                           |  |                 
|(millions of Canadian dollars, pre-tax)                                                                    |  | 2011             |   | 2010                   
|                                                                                                          
|Change in fair value of derivative instruments recognized in OCI (effective portion)                       |  | (252             | ) | (79                    
|Reclassification of gains and losses on derivative instruments from AOCI to Net Income (effective portion) |  | 61               |   | (7                     

152NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



Credit Risk Related Contingent Features

Derivative contracts entered into to manage market risk often contain financial assurance 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, 2011, the aggregate fair value of all derivative instruments with credit-risk-related contingent features
that were in a net liability position was $110 million (2010  $92 million), for which the Company has provided collateral of $28 million
(2010  $4 million) in the normal course of business. If the credit-risk-related contingent features in these agreements were
triggered on December 31, 2011, the Company would have been required to provide additional collateral of $82 million (2010  $88 million) to
its counterparties. Collateral may also need to be provided should the fair value of derivative financial 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.

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 inputs 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 2011 or 2010. 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)   |                            | 2011                                                                          |      | 2010                                                                                           |      | 2011                                                                            |      | 2010 
|                                            
|Natural Gas Inventory                        |                            |                                                                              |      |                                                                                               |      | 29                                                                              |      | 49   
|Derivative Financial Instrument Assets:      |                            |                                                                               |      |                                                                                                |      |                                                                                 |      |      
|                                             | Interest rate contracts    |                                                                               |     |                                                                                                |     |                                                                                 | 35   |      
|                                             | Foreign exchange contracts |                                                                               | 11   |                                                                                                | 10   |                                                                                 | 131  |      
|                                             | Power commodity contracts  |                                                                               |     |                                                                                                |     |                                                                                 | 244  |      
|                                             | Gas commodity contracts    |                                                                               | 124  |                                                                                                | 93   |                                                                                 | 55   |      
|Derivative Financial Instrument Liabilities: |                            |                                                                               |      |                                                                                                |      |                                                                                 |      |      
|                                             | Interest rate contracts    |                                                                               |     |                                                                                                |     |                                                                                 | (23  | )    
|                                             | Foreign exchange contracts |                                                                               | (13  | )                                                                                              | (11  | )                                                                               | (89  | )    
|                                             | Power commodity contracts  |                                                                               |     |                                                                                                |     |                                                                                 | (465 | )    
|                                             | Gas commodity contracts    |                                                                               | (208 | )                                                                                              | (178 | )                                                                               | (26  | )    
|Non-Derivative Financial Instruments:        |                            |                                                                               |      |                                                                                                |      |                                                                                 |      |      
|                                             | Available-for-sale assets  |                                                                               | 23   |                                                                                                | 20   |                                                                                 |     |      
|                                            
|                                             |                            | (63                                                                           | )    | (66                                                                                            | )    | (109                                                                            | )    | 166  
|                                            

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS153

---



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, 2009                                   |  | (2             | ) | 
|New contracts(2)                                               |  | (16            | ) | 
|Settlements                                                    |  | (3             | ) | 
|Transfers into Level III(3)                                    |  | 3              |   | 
|Transfers out of Level III(3)(4)                               |  | (38            | ) | 
|Change in unrealized gains recorded in Net Income              |  | 14             |   | 
|Change in fair value of derivative instruments recorded in OCI |  | 39             |   | 
|                                                              
|Balance at December 31, 2010                                   |  | (3             | ) | 
|New contracts(2)                                               |  | 1              |   | 
|Settlements                                                    |  | 1              |   | 
|Transfers out of Level III(3)(4)                               |  | (1             | ) | 
|Change in unrealized gains recorded in Net Income              |  | 1              |   | 
|Change in fair value of derivative instruments recorded in OCI |  | (12            | ) | 
|                                                              
|Balance at December 31, 2011                                   |  | (13            | ) | 
|                                                              

A
10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $10 million decrease or increase,
respectively, in the fair value of outstanding derivative financial instruments included in Level III as at December 31, 2011.

NOTE 22    CHANGES IN OPERATING WORKING CAPITAL

|Year ended December 31 (millions of dollars)     |  | 2011 |   | 2010 |   | 2009 |   | 
|------------------------------------------------ |  | ---- | - | ---- | - | ---- | - | 
|                                                
|(Increase)/decrease in accounts receivable       |  | (6   | ) | (305 | ) | 314  |   | 
|Decrease/(increase) in inventories               |  | 27   |   | 70   |   | (19  | ) | 
|Increase in other current assets                 |  | (20  | ) | (89  | ) | (249 | ) | 
|Increase/(decrease) in accounts payable          |  | 300  |   | 84   |   | (154 | ) | 
|Increase/(decrease) in accrued interest          |  | 9    |   | (9   | ) | 18   |   | 
|                                                
|Decrease/(Increase) in Operating Working Capital |  | 310  |   | (249 | ) | (90  | ) | 
|                                                

NOTE 23    ACQUISITIONS AND DISPOSITIONS

Natural Gas Pipelines

TC PipeLines, LP

On May 3, 2011, TransCanada completed the sale of a 25 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an
aggregate purchase price of US$605 million which included US$81 million of long-term debt, or 25 per cent of GTN LLC's outstanding debt. GTN LLC
and Bison LLC own the GTN and Bison natural gas pipelines, respectively.

On
May 3, 2011, TC PipeLines, LP completed an underwritten public offering of 7,245,000 common units, including 945,000 common units purchased by
the underwriters upon full exercise of an over-allotment option, at US$47.58 per unit. Net proceeds of approximately US$331 million from this offering were used to partially fund
the acquisition. The acquisition was also funded by draws of US$61 million on TC PipeLines, LP's bridge loan facility and US$125 million on its US$250 million senior
revolving credit facility.

As
part of this offering, TransCanada made a capital contribution of approximately US$7 million to maintain its two per cent general partnership interest in TC
PipeLines, LP and did not purchase any other units. As a result of the common units offering, TransCanada's

154NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



ownership
in TC PipeLines, LP decreased from 38.2 per cent to 33.3 per cent and an after-tax dilution gain of $30 million ($50 million
pre-tax) was recorded in Contributed Surplus.

In
November 2009, TC PipeLines, LP completed an offering of five million common units at a price of US$38.00 per unit, resulting in net proceeds to TC
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 TC PipeLines, LP decreased to 38.2 per cent and the Company recognized an after-tax dilution gain of
$18 million ($29 million pre-tax) in income.

In
July 2009, TransCanada sold North Baja to TC PipeLines, LP. As part of the transaction, the Company agreed to amend its general partner incentive
distribution rights arrangement with TC PipeLines, LP. TransCanada received aggregate consideration totalling approximately US$395 million from TC PipeLines, LP, including
US$200 million in cash and 6,371,680 common units of TC PipeLines, LP. As a result of this transaction, TransCanada recorded no gain or loss and its ownership in TC
PipeLines, LP increased to 42.6 per cent. The Company's increased ownership in TC PipeLines, LP also resulted in a decrease in Non-Controlling Interests and an
increase in Contributed Surplus.

Oil Pipelines

Keystone

In August 2009, TransCanada purchased the 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 the Company's ownership interest in Keystone to 100 per cent and was recorded in Plant,
Property and Equipment. TransCanada began fully consolidating Keystone upon this acquisition.

In
2009, prior to August, TransCanada funded $1.3 billion of cash calls for Keystone, resulting in the Company acquiring an increase in ownership from
62 per cent to 80 per cent for $313 million. The Company proportionately consolidated the Keystone partnerships prior to August 2009.

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 |  | 
|-------------------------------------------- |  | ---------------------- |  | ------------------------------------ | - | ------------ |  | 
|                                            
|2012                                         |  | 87                     |  | (8                                   | ) | 79           |  | 
|2013                                         |  | 85                     |  | (7                                   | ) | 78           |  | 
|2014                                         |  | 81                     |  | (7                                   | ) | 74           |  | 
|2015                                         |  | 76                     |  | (5                                   | ) | 71           |  | 
|2016                                         |  | 75                     |  | (3                                   | ) | 72           |  | 
|2017 and thereafter                          |  | 363                    |  | (2                                   | ) | 361          |  | 
|                                            
|                                             |  | 767                    |  | (32                                  | ) | 735          |  | 
|                                            

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 2011 was $79 million (2010  $80 million;
2009  $64 million).

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 and other factors. TransCanada's
share of
payments under the PPAs in 2011 was $394 million (2010  $363 million; 2009  $384 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.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS155

---



Other Commitments

At December 31, 2011, TransCanada was committed to Natural Gas Pipelines capital expenditures totalling approximately $250 million, primarily related to
construction costs of the Alberta System and Guadalajara.

At
December 31, 2011, the Company was committed to Oil Pipelines capital expenditures totalling approximately $992 million, primarily related to construction
costs of Keystone XL.

At
December 31, 2011, the Company was committed to Energy capital expenditures totalling approximately $290 million and includes TransCanada's share of capital
costs of Bruce Power and Cartier Wind.

On
December 15, 2011, TransCanada agreed to purchase nine Ontario solar projects from Canadian Solar Solutions Inc., with a combined capacity of 86 MW,
for approximately $470 million. Under the terms of the agreement, each of the nine solar projects will be developed and constructed by Canadian Solar Solutions Inc. using photovoltaic
panels. TransCanada will purchase each project once construction and acceptance testing have been completed and operations have begun under 20-year PPAs with the Ontario Power
Authority (OPA) under the Feed-in Tariff program in Ontario. TransCanada anticipates the projects will be placed in service between late 2012 and mid-2013, subject to
regulatory approvals.

Contingencies

TransCanada is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2011, the Company had accrued approximately
$49 million (2010  $59 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, arbitrations 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.

Sundance A PPA

In December 2010, Sundance A Units 1 and 2 were withdrawn from service and were subject to a force majeure claim by the PPA owner in January 2011. In
February 2011, the owner notified TransCanada that it had determined it was uneconomic to replace or repair Units 1 and 2, and that the Sundance A PPA should therefore be terminated.

TransCanada
has disputed both the force majeure and the economic destruction claims under the binding dispute resolution process provided in the PPA and both matters will be
heard through a single binding arbitration process. The arbitration panel has scheduled a hearing in April 2012 for these claims. Assuming the hearing concludes within the time allotted,
TransCanada expects to receive a decision in mid-2012.

TransCanada
has continued to record revenues and costs throughout 2011 as it considers this event to be an interruption of supply in accordance with the terms of the PPA.
The Company does not believe the owner's claims meet the tests of force majeure or destruction as specified in the PPA and has therefore recorded $156 million of pre-tax income for
the year ended December 31, 2011. The outcome of any arbitration process is not certain, however, TransCanada believes the matter will be resolved in its favour.

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 OPA to refurbish and restart Bruce A power generation units. The guarantees 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 $863 million at December 31, 2011. The fair
value of these Bruce Power guarantees at December 31, 2011 is estimated to be $29 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 assurances was estimated at December 31, 2011 to range from $182 million to a maximum of $498 million. The fair value of
these guarantees at December 31, 2011 is estimated to be $7 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.

156NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---





NOTE 25    UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING

As previously discussed in Note 3, TransCanada will be adopting U.S. GAAP effective January 1, 2012. The consolidated financial statements have been
prepared in accordance with CGAAP which in some respects, differ from U.S. GAAP. The effects of significant differences between CGAAP and U.S. GAAP are described in this note.

Reconciliation of Net Income and Comprehensive Income to U.S. GAAP

|Year ended December 31 (millions of dollars)                               |                                                                                    | 2011  |      | 2010  |      | 2009  |     |  
|-------------------------------------------------------------------------- | ---------------------------------------------------------------------------------- | ----- | ---- | ----- | ---- | ----- | --- | -
|                                                                          
|Net Income  CGAAP                                                         |                                                                                    | 1,711 |      | 1,387 |      | 1,476 |     |  
|U.S. GAAP adjustments:                                                     |                                                                                    |       |      |       |      |       |     |  
|                                                                           | Unrealized loss/(gain) on natural gas inventory held in storage(1)                 |       | 4    |       | 15   |       | (3  | )
|                                                                           | Tax impact of unrealized loss/(gain) on natural gas inventory held in storage      |       | (1   | )     | (5   | )     | 1   |  
|                                                                           | Dilution gain(2)                                                                   |       |     |       |     |       | (29 | )
|                                                                           | Tax impact of dilution gain                                                        |       |     |       |     |       | 11  |  
|                                                                           | Tax recovery due to a change in tax legislation substantively enacted in Canada(4) |       | (4   | )     | (4   | )     |    |  
|                                                                          
|Net Income  U.S. GAAP                                                     |                                                                                    | 1,710 |      | 1,393 |      | 1,456 |     |  
|                                                                           | Less: Net Income Attributable to Non-Controlling Interests                         |       | (129 | )     | (115 | )     | (96 | )
|                                                                          
|Net Income Attributable to Controlling Interests  U.S. GAAP               |                                                                                    | 1,581 |      | 1,278 |      | 1,360 |     |  
|                                                                           | Less: Preferred Share Dividends                                                    |       | (55  | )     | (45  | )     | (6  | )
|                                                                          
|Net Income Attributable to Common Shareholders  U.S. GAAP                 |                                                                                    | 1,526 |      | 1,233 |      | 1,354 |     |  
|                                                                          
|Other Comprehensive Loss  CGAAP                                           |                                                                                    | (36   | )    | (239  | )    | (153  | )   |  
|U.S. GAAP adjustments:                                                     |                                                                                    |       |      |       |      |       |     |  
|                                                                           | Change in funded status of post-retirement plan liability(3)                       |       | (106 | )     | (11  | )     | 7   |  
|                                                                           | Tax impact of change in funded status of post-retirement plan liability            |       | 27   |       | 4    |       | (2  | )
|                                                                           | Change in funded status of post-retirement plan liability of equity investment     |       | (80  | )     | (119 | )     | (48 | )
|                                                                          
|Other Comprehensive Loss  U.S. GAAP                                       |                                                                                    | (195  | )    | (365  | )    | (196  | )   |  
|                                                                           | Less: Other Comprehensive Income Attributable to Non-Controlling Interests         |       | (11  | )     | (6   | )     | (7  | )
|                                                                          
|Other Comprehensive Loss Attributable to Controlling Interests  U.S. GAAP |                                                                                    | (206  | )    | (371  | )    | (203  | )   |  
|                                                                          
|Comprehensive Income Attributable to Common Shares  U.S. GAAP             |                                                                                    | 1,320 |      | 862   |      | 1,151 |     |  
|                                                                          

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS157

---



Information Prepared in Accordance with U.S. GAAP

The differences between CGAAP and the following information prepared in accordance with U.S. GAAP relates principally to the accounting for joint venture investments.
Under CGAAP, the Company accounts for joint venture 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 requires that these joint venture investments be recorded on an equity basis of accounting. Information on
the balances that have been proportionately consolidated under CGAAP is included in Note 8 to these financial statements. The effects of any additional differences between CGAAP and
U.S. GAAP are described in the footnotes below.

Condensed Consolidated Statement of Income  U.S. GAAP

|Year ended December 31 (millions of dollars)                 |                                    | 2011  |       | 2010  |       | 2009  |       |  
|------------------------------------------------------------ | ---------------------------------- | ----- | ----- | ----- | ----- | ----- | ----- | -
|                                                            
|Revenues(1)                                                  |                                    | 7,694 |       | 6,634 |       | 6,778 |       |  
|Income from Equity Investments                               |                                    | 415   |       | 453   |       | 478   |       |  
|Operating and Other Expenses                                 |                                    |       |       |       |       |       |       |  
|                                                             | Plant operating costs and other(2) |       | 2,768 |       | 2,434 |       | 2,621 |  
|                                                             | Commodity purchases resold         |       | 846   |       | 960   |       | 772   |  
|                                                             | Depreciation and amortization      |       | 1,328 |       | 1,160 |       | 1,201 |  
|                                                             | Valuation provision for MGP        |       |      |       | 146   |       |      |  
|                                                            
|                                                             |                                    | 4,942 |       | 4,700 |       | 4,594 |       |  
|                                                            
|Financial Charges/(Income)                                   |                                    |       |       |       |       |       |       |  
|                                                             | Interest expense                   |       | 937   |       | 701   |       | 954   |  
|                                                             | Interest income and other          |       | (55   | )     | (94   | )     | (118  | )
|                                                            
|                                                             |                                    | 882   |       | 607   |       | 836   |       |  
|                                                            
|Income before Income Taxes                                   |                                    | 2,285 |       | 1,780 |       | 1,826 |       |  
|                                                            
|Income Taxes Expenses/(Recovery)                             |                                    |       |       |       |       |       |       |  
|                                                             | Current(2)(4)                      |       | 210   |       | (139  | )     | 13    |  
|                                                             | Deferred(1)                        |       | 365   |       | 526   |       | 357   |  
|                                                            
|                                                             |                                    | 575   |       | 387   |       | 370   |       |  
|                                                            
|Net Income  U.S. GAAP                                       |                                    | 1,710 |       | 1,393 |       | 1,456 |       |  
|Net Income Attributable to Non-Controlling Interests         |                                    | 129   |       | 115   |       | 96    |       |  
|                                                            
|Net Income Attributable to Controlling Interests  U.S. GAAP |                                    | 1,581 |       | 1,278 |       | 1,360 |       |  
|Preferred Share Dividends                                    |                                    | 55    |       | 45    |       | 6     |       |  
|                                                            
|Net Income Attributable to Common Shares  U.S. GAAP         |                                    | 1,526 |       | 1,233 |       | 1,354 |       |  
|                                                            
|Net Income per Common Share  U.S. GAAP                      |                                    |       |       |       |       |       |       |  
|                                                             | Basic                              |       | $2.17 |       | $1.79 |       | $2.08 |  
|                                                            
|                                                             | Diluted                            |       | $2.17 |       | $1.78 |       | $2.08 |  
|                                                            

158NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



Consolidated Statement of Comprehensive Income  U.S. GAAP

|Year ended December 31 (millions of dollars)                                                                                                   |  | 2011  |   | 2010  |   | 2009  |   | 
|---------------------------------------------------------------------------------------------------------------------------------------------- |  | ----- | - | ----- | - | ----- | - | 
|                                                                                                                                              
|Net Income  U.S. GAAP                                                                                                                         |  | 1,710 |   | 1,393 |   | 1,456 |   | 
|                                                                                                                                              
|Other Comprehensive Income/(Loss), Net of Income Taxes                                                                                         |  |       |   |       |   |       |   | 
|Change in foreign currency translation gains and losses on investments in foreign operations(8)                                                |  | 113   |   | (180  | ) | (471  | ) | 
|Change in fair value of derivative instruments to hedge the net investments in foreign operations(9)                                           |  | (73   | ) | 89    |   | 258   |   | 
|Change in fair value of derivative instruments designated as cash flow hedges(10)                                                              |  | (212  | ) | (169  | ) | (29   | ) | 
|Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges(11)                                |  | 147   |   | 53    |   | 71    |   | 
|Unrealized actuarial gains and losses on pension and other post-retirement benefit plans(3)(12)                                                |  | (89   | ) | (12   | ) | (1    | ) | 
|Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans(3)(13) |  | 10    |   | 5     |   | 6     |   | 
|Other Comprehensive Loss on equity investments(14)                                                                                             |  | (91   | ) | (151  | ) | (30   | ) | 
|                                                                                                                                              
|Other Comprehensive Loss  U.S. GAAP                                                                                                           |  | (195  | ) | (365  | ) | (196  | ) | 
|                                                                                                                                              
|Comprehensive Income  U.S. GAAP                                                                                                               |  | 1,515 |   | 1,028 |   | 1,260 |   | 
|Comprehensive Income Attributable to Non-Controlling Interests                                                                                 |  | 140   |   | 121   |   | 103   |   | 
|                                                                                                                                              
|Comprehensive Income Attributable to Controlling Interests  U.S. GAAP                                                                         |  | 1,375 |   | 907   |   | 1,157 |   | 
|Preferred Share Dividends                                                                                                                      |  | 55    |   | 45    |   | 6     |   | 
|                                                                                                                                              
|Comprehensive Income Attributable to Common Shares  U.S. GAAP                                                                                 |  | 1,320 |   | 862   |   | 1,151 |   | 
|                                                                                                                                              

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS159

---



Condensed Consolidated Balance Sheet  U.S. GAAP

|As at December 31 (millions of dollars)          |                                                   | 2011   |   | 2010   |   | 
|------------------------------------------------ | ------------------------------------------------- | ------ | - | ------ | - | 
|                                                
|Assets                                           |                                                   |        |   |        |   | 
|Current Assets(1)                                |                                                   | 3,110  |   | 2,799  |   | 
|Plant, Property and Equipment(7)                 |                                                   | 32,467 |   | 30,987 |   | 
|Equity Investments(3)(5)(6)                      |                                                   | 5,077  |   | 4,683  |   | 
|Goodwill                                         |                                                   | 3,534  |   | 3,457  |   | 
|Regulatory Assets(3)                             |                                                   | 1,684  |   | 1,699  |   | 
|Intangibles and Other Assets(3)(6)               |                                                   | 1,466  |   | 1,624  |   | 
|                                                
|                                                 |                                                   | 47,338 |   | 45,249 |   | 
|                                                
|Liabilities                                      |                                                   |        |   |        |   | 
|Current Liabilities(4)(7)                        |                                                   | 5,522  |   | 5,352  |   | 
|Regulatory Liabilities                           |                                                   | 297    |   | 308    |   | 
|Deferred Amounts(3)(5)                           |                                                   | 929    |   | 728    |   | 
|Deferred Income Tax Liabilities(1)(3)(6)         |                                                   | 3,591  |   | 3,241  |   | 
|Long-Term Debt(6)                                |                                                   | 17,724 |   | 17,122 |   | 
|Junior Subordinated Notes(6)                     |                                                   | 1,016  |   | 993    |   | 
|                                                
|                                                 |                                                   | 29,079 |   | 27,744 |   | 
|                                                
|Equity                                           |                                                   |        |   |        |   | 
|Common shares, no par value                      |                                                   | 12,011 |   | 11,745 |   | 
|                                                 | Issued and outstanding: 2011  704 million shares |        |   |        |   | 
|                                                 | Issued and outstanding: 2010  696 million shares |        |   |        |   | 
|Preferred shares                                 |                                                   | 1,224  |   | 1,224  |   | 
|Additional paid-in capital(2)                    |                                                   | 380    |   | 349    |   | 
|Retained earnings(1)(2)(4)                       |                                                   | 4,628  |   | 4,273  |   | 
|Accumulated other comprehensive (loss)/income(3) |                                                   | (1,449 | ) | (1,243 | ) | 
|                                                
|Equity Attributable to Controlling Interests     |                                                   | 16,794 |   | 16,348 |   | 
|Equity Attributable to Non-Controlling Interests |                                                   | 1,465  |   | 1,157  |   | 
|                                                
|                                                 |                                                   | 18,259 |   | 17,505 |   | 
|                                                
|                                                 |                                                   | 47,338 |   | 45,249 |   | 
|                                                

160NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---



Consolidated Statement of Accumulated Other Comprehensive
(Loss)/Income  U.S. GAAP

|Year ended December 31 (millions of dollars)                                                                                                   |  | 2011   |   | 2010   |   | 2009 |   | 
|---------------------------------------------------------------------------------------------------------------------------------------------- |  | ------ | - | ------ | - | ---- | - | 
|                                                                                                                                              
|Balance at beginning of year                                                                                                                   |  | (1,243 | ) | (872   | ) | (669 | ) | 
|Change in foreign currency translation gains and losses on investments in foreign operations(8)                                                |  | 113    |   | (180   | ) | (471 | ) | 
|Change in fair value of derivative instruments to hedge the net investments in foreign operations(9)                                           |  | (73    | ) | 89     |   | 258  |   | 
|Change in fair value of derivative instruments designated as cash flow hedges(10)                                                              |  | (213   | ) | (165   | ) | (27  | ) | 
|Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges(11)                                |  | 137    |   | 43     |   | 62   |   | 
|Unrealized actuarial gains and losses on pension and other post-retirement benefit plans(3)(12)                                                |  | (89    | ) | (12    | ) | (1   | ) | 
|Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans(3)(13) |  | 10     |   | 5      |   | 6    |   | 
|Other Comprehensive Loss on equity investments(14)                                                                                             |  | (91    | ) | (151   | ) | (30  | ) | 
|                                                                                                                                              
|Balance at end of year                                                                                                                         |  | (1,449 | ) | (1,243 | ) | (872 | ) | 
|                                                                                                                                              

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS161

---



Condensed Consolidated Statement of Cash Flows  U.S. GAAP

|Year ended December 31 (millions of dollars)                         |  | 2011   |   | 2010   |   | 2009   |   | 
|-------------------------------------------------------------------- |  | ------ | - | ------ | - | ------ | - | 
|                                                                    
|Net cash provided by operations                                      |  | 3,759  |   | 2,876  |   | 3,008  |   | 
|Net cash used in investing activities                                |  | (3,127 | ) | (5,296 | ) | (7,347 | ) | 
|Net cash (used in)/provided by financing activities                  |  | (642   | ) | 2,188  |   | 4,204  |   | 
|Effect of foreign exchange rate changes on cash and cash equivalents |  | 4      |   | (7     | ) | (93    | ) | 
|                                                                    
|Decrease in cash and cash equivalents                                |  | (6     | ) | (239   | ) | (228   | ) | 
|Cash and cash equivalents beginning of year                          |  | 660    |   | 899    |   | 1,127  |   | 
|                                                                    
|Cash and cash equivalents end of year                                |  | 654    |   | 660    |   | 899    |   | 
|                                                                    

|December 31 (millions of dollars) |  | 2011 |   | 2010 |   | 
|--------------------------------- |  | ---- | - | ---- | - | 
|                                 
|Intangibles and other assets      |  |     |   | 40   |   | 
|Deferred amounts                  |  | (321 | ) | (156 | ) | 
|                                 
|                                  |  | (321 | ) | (116 | ) | 
|                                 



|                                  |  | 2011             |  | 2010           |  | 2009             |  |               
|--------------------------------- |  | ---------------- |  | -------------- |  | ---------------- |  | --------------
|                                  |  |                 
|December 31 (millions of dollars) |  | Pension
Benefits |  | Other
Benefits |  | Pension
Benefits |  | Other
Benefits
|                                 
|Net loss                          |  | 283              |  | 29             |  | 179              |  | 24            
|Prior service cost                |  | 7                |  | 2              |  | 9                |  | 2             
|                                 
|                                  |  | 290              |  | 31             |  | 188              |  | 26            
|                                 



|                                                        |  | 2011             |   | 2010           |   | 2009             |   |               
|------------------------------------------------------- |  | ---------------- | - | -------------- | - | ---------------- | - | --------------
|                                                        |  |                 
|December 31 (millions of dollars)                       |  | Pension
Benefits |   | Other
Benefits |   | Pension
Benefits |   | Other
Benefits
|                                                       
|Amortization of net loss from AOCI to OCI               |  | (10              | ) | (1             | ) | (5               | ) | (1            
|Amortization of prior service (credit) from AOCI to OCI |  | (2               | ) |               |   | (2               | ) |              
|Funded status adjustment                                |  | 113              |   | 6              |   | 15               |   | 4             
|                                                       
|                                                        |  | 101              |   | 5              |   | 8                |   | 3             
|                                                       



|December 31 (millions of dollars) |  | 2011  |   | 2010  |  | 
|--------------------------------- |  | ----- | - | ----- |  | 
|                                 
|Accumulated benefit obligation    |  | 1,691 |   | 1,463 |  | 
|Fair value of plan assets         |  | 1,656 |   | 1,636 |  | 
|                                 
|Funded status  (deficit)/surplus |  | (35   | ) | 173   |  | 
|                                 

162NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

---





|December 31 (millions of dollars) |  | 2011 |   | 2010 |   | 
|--------------------------------- |  | ---- | - | ---- | - | 
|                                 
|Accumulated benefit obligation    |  | 446  |   | 182  |   | 
|Fair value of plan assets         |  | 391  |   | 178  |   | 
|                                 
|Funded status  (deficit)         |  | (55  | ) | (4   | ) | 
|                                 





|December 31 (millions of dollars)              |  | 2011 |   | 2010 |   | 
|---------------------------------------------- |  | ---- | - | ---- | - | 
|                                              
|Unrecognized tax benefits at beginning of year |  | 62   |   | 55   |   | 
|Gross increases  tax positions in prior years |  | 9    |   | 7    |   | 
|Gross decreases  tax positions in prior years |  | (7   | ) | (1   | ) | 
|Gross increases  current year positions       |  | 11   |   | 9    |   | 
|Settlements                                    |  |     |   | (7   | ) | 
|Lapses of statute of limitations               |  | (23  | ) | (1   | ) | 
|                                              
|Unrecognized tax benefits at end of year       |  | 52   |   | 62   |   | 
|                                              





NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS163

---



164NOTES 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 | 
|------------------------------------------------- |  | ----- |  | ------ |  | ----- |  | ------ |  | ------ | 
|                                                 
|2011 (dollars)                                    |  |       |  |        |  |       |  |        |  |        | 
|High                                              |  | 39.64 |  | 43.72  |  | 43.23 |  | 44.74  |  | 44.74  | 
|Low                                               |  | 36.10 |  | 38.95  |  | 37.00 |  | 39.25  |  | 36.10  | 
|Close                                             |  | 39.31 |  | 42.35  |  | 42.54 |  | 44.53  |  | 44.53  | 
|Volume (millions of shares)                       |  | 106.9 |  | 85.9   |  | 107.4 |  | 120.6  |  | 420.8  | 
|                                                 
|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) |  |       |  |        |  |       |  |        |  |        | 
|                                                 
|2011 (U.S. dollars)                               |  |       |  |        |  |       |  |        |  |        | 
|High                                              |  | 40.76 |  | 45.09  |  | 44.08 |  | 44.38  |  | 45.09  | 
|Low                                               |  | 36.12 |  | 40.37  |  | 37.29 |  | 37.58  |  | 36.12  | 
|Close                                             |  | 40.53 |  | 43.84  |  | 40.49 |  | 43.67  |  | 43.67  | 
|Volume (millions of shares)                       |  | 30.3  |  | 23.8   |  | 51.6  |  | 48.5   |  | 154.2  | 
|                                                 
|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
INFORMATION165

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FIVE YEAR FINANCIAL HIGHLIGHTS

|(millions of dollars except where indicated)        |  | 2011                  |   | 2010   |   | 2009   |   | 2008   |   | 2007     |  
|--------------------------------------------------- |  | --------------------- | - | ------ | - | ------ | - | ------ | - | -------- | -
|                                                   
|Income Statement                                    |  |                       |   |        |   |        |   |        |   |          |  
|Revenues                                            |  | 9,139                 |   | 8,064  |   | 8,181  |   | 8,547  |   | 8,731    |  
|EBITDA                                              |  |                       |   |        |   |        |   |        |   |          |  
|                                                    |  | Natural Gas Pipelines |   | 2,967  |   | 2,769  |   | 3,122  |   | 3,315    |  
|                                                    |  | Oil Pipelines         |   | 587    |   |       |   |       |   |         |  
|                                                    |  | Energy                |   | 1,281  |   | 1,117  |   | 1,132  |   | 1,169    |  
|                                                    |  | Corporate             |   | (86    | ) | (99    | ) | (117   | ) | (104     | )
|                                                   
|                                                    |  | 4,749                 |   | 3,787  |   | 4,137  |   | 4,380  |   | 3,945    |  
|Depreciation                                        |  | (1,528                | ) | (1,354 | ) | (1,377 | ) | (1,247 | ) | (1,237 ) |  
|                                                   
|EBIT                                                |  | 3,221                 |   | 2,433  |   | 2,760  |   | 3,133  |   | 2,708    |  
|Financial charges and other                         |  | (937                  | ) | (666   | ) | (897   | ) | (961   | ) | (898 )   |  
|Income taxes                                        |  | (573                  | ) | (380   | ) | (387   | ) | (602   | ) | (490 )   |  
|                                                   
|Net income                                          |  | 1,711                 |   | 1,387  |   | 1,476  |   | 1,570  |   | 1,320    |  
|Net income attributable to non-controlling interest |  | (129                  | ) | (115   | ) | (96    | ) | (130   | ) | (97 )    |  
|                                                   
|Net income attributable to controlling interests    |  | 1,582                 |   | 1,272  |   | 1,380  |   | 1,440  |   | 1,223    |  
|Preferred share dividends                           |  | (55                   | ) | (45    | ) | (6     | ) |       |   |         |  
|                                                   
|Net income attributable to common shares            |  | 1,527                 |   | 1,227  |   | 1,374  |   | 1,440  |   | 1,223    |  
|                                                   
|Comparable earnings                                 |  | 1,565                 |   | 1,361  |   | 1,325  |   | 1,279  |   | 1,100    |  
|Cash Flow Statement                                 |  |                       |   |        |   |        |   |        |   |          |  
|Funds generated from operations                     |  | 3,663                 |   | 3,331  |   | 3,080  |   | 3,021  |   | 2,621    |  
|Decrease/(increase) in operating working capital    |  | 310                   |   | (249   | ) | (90    | ) | 135    |   | 63       |  
|                                                   
|Net cash provided by operations                     |  | 3,973                 |   | 3,082  |   | 2,990  |   | 3,156  |   | 2,684    |  
|Capital expenditures and acquisitions               |  | 3,274                 |   | 5,036  |   | 6,319  |   | 6,363  |   | 5,874    |  
|Disposition of assets, net of current income taxes  |  |                      |   |       |   |       |   | 28     |   | 35       |  
|Cash dividends paid on common and preferred shares  |  | 1,016                 |   | 754    |   | 728    |   | 577    |   | 546      |  
|Balance Sheet                                       |  |                       |   |        |   |        |   |        |   |          |  
|Assets                                              |  |                       |   |        |   |        |   |        |   |          |  
|Plant, property and equipment:                      |  |                       |   |        |   |        |   |        |   |          |  
|                                                    |  | Natural Gas Pipelines |   | 18,385 |   | 18,230 |   | 18,333 |   | 19,339   |  
|                                                    |  | Oil Pipelines         |   | 9,254  |   | 8,184  |   | 5,305  |   | 1,361    |  
|                                                    |  | Energy                |   | 10,545 |   | 9,745  |   | 9,158  |   | 8,435    |  
|                                                    |  | Corporate             |   | 78     |   | 85     |   | 83     |   | 54       |  
|Total assets                                        |  | 48,995                |   | 46,794 |   | 43,841 |   | 39,414 |   | 30,330   |  
|Capitalization                                      |  |                       |   |        |   |        |   |        |   |          |  
|Long-term debt                                      |  | 17,632                |   | 17,028 |   | 16,186 |   | 15,368 |   | 12,377   |  
|Junior subordinated notes                           |  | 1,009                 |   | 985    |   | 1,036  |   | 1,213  |   | 975      |  
|Non-controlling interests                           |  | 1,465                 |   | 1,157  |   | 1,174  |   | 1,194  |   | 999      |  
|Preferred shares                                    |  | 1,224                 |   | 1,224  |   | 539    |   |       |   |         |  
|Common shareholders' equity                         |  | 16,100                |   | 15,503 |   | 15,220 |   | 12,898 |   | 9,785    |  
|                                                    |  |                       |   |        |   |        |   |        |   |          |  

166SUPPLEMENTARY
INFORMATION

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|Per Common Share Data (dollars)                  |                                                        |                             |       |        |       |        |       |        |       |        |      
|------------------------------------------------ | ------------------------------------------------------ | --------------------------- | ----- | ------ | ----- | ------ | ----- | ------ | ----- | ------ | -----
|Net income  basic                               |                                                        | $2.18                       |       | $1.78  |       | $2.11  |       | $2.53  |       | $2.31  |      
| diluted                                        |                                                        | $2.17                       |       | $1.77  |       | $2.11  |       | $2.52  |       | $2.30  |      
|                                                
|Comparable earnings per share                    |                                                        | $2.23                       |       | $1.97  |       | $2.03  |       | $2.25  |       | $2.08  |      
|Dividends declared                               |                                                        | $1.68                       |       | $1.60  |       | $1.52  |       | $1.44  |       | $1.36  |      
|Book Value(1)(7)                                 |                                                        | $22.87                      |       | $22.27 |       | $22.24 |       | $20.92 |       | $18.13 |      
|Market Price                                     |                                                        |                             |       |        |       |        |       |        |       |        |      
|                                                 | Toronto Stock Exchange ($Cdn)                          |                             |       |        |       |        |       |        |       |        |      
|                                                 |                                                        | High                        |       | 44.74  |       | 39.28  |       | 36.49  |       | 40.97  |      
|                                                 |                                                        | Low                         |       | 36.10  |       | 30.01  |       | 28.86  |       | 29.42  |      
|                                                 |                                                        | Close                       |       | 44.53  |       | 37.99  |       | 36.19  |       | 33.17  |      
|                                                 |                                                        | Volume (millions of shares) |       | 420.80 |       | 382.60 |       | 453.6  |       | 493.8  |      
|                                                 | New York Stock Exchange ($US)                          |                             |       |        |       |        |       |        |       |        |      
|                                                 |                                                        | High                        |       | 45.09  |       | 38.59  |       | 34.59  |       | 41.53  |      
|                                                 |                                                        | Low                         |       | 36.12  |       | 25.80  |       | 20.01  |       | 23.52  |      
|                                                 |                                                        | Close                       |       | 43.67  |       | 38.04  |       | 34.37  |       | 27.14  |      
|                                                 |                                                        | Volume (millions of shares) |       | 154.20 |       | 84.94  |       | 111.9  |       | 44.5   |      
|Common shares outstanding (millions)             |                                                        |                             |       |        |       |        |       |        |       |        |      
|                                                 | Average for the year                                   |                             | 701.6 |        | 690.5 |        | 651.8 |        | 569.6 |        | 529.9
|                                                 | End of year                                            |                             | 703.9 |        | 696.2 |        | 684.4 |        | 616.5 |        | 539.8
|Registered common shareholders(1)                |                                                        | 32,113                      |       | 32,639 |       | 33,169 |       | 33,681 |       | 34,204 |      
|Per Preferred Share Data (dollars)               |                                                        |                             |       |        |       |        |       |        |       |        |      
|                                                 | Dividends declared:                                    |                             |       |        |       |        |       |        |       |        |      
|                                                 | Series 1, 3 and 5 cumulative first preferred shares(2) |                             | $3.25 |        | $2.60 |        | $0.29 |        | $    |        | $   
|Financial Ratios                                 |                                                        |                             |       |        |       |        |       |        |       |        |      
|Return on average common shareholders' equity(3) |                                                        | 9.7%                        |       | 8.0%   |       | 9.8%   |       | 12.7%  |       | 14.0%  |      
|Dividend yield(4)(5)                             |                                                        | 3.8%                        |       | 4.2%   |       | 4.2%   |       | 4.3%   |       | 3.4%   |      
|Price/earnings multiple(5)(6)                    |                                                        | 20.4                        |       | 21.3   |       | 17.2   |       | 13.1   |       | 17.5   |      
|Price/book multiple(5)(7)                        |                                                        | 1.9                         |       | 1.7    |       | 1.6    |       | 1.6    |       | 2.2    |      
|Debt to debt plus shareholders' equity(8)        |                                                        | 54%                         |       | 53%    |       | 53%    |       | 57%    |       | 59%    |      
|Total shareholder return(9)                      |                                                        | 22.2%                       |       | 9.7%   |       | 14.4%  |       | (15%   | )     | 3%     |      
|Earnings to fixed charges(10)                    |                                                        | 2.5                         |       | 1.9    |       | 2.1    |       | 2.7    |       | 2.6    |      

SUPPLEMENTARY
INFORMATION167

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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 MeetingThe annual meeting of shareholders is scheduled for April 27, 2012 at 10:00 a.m. (Mountain Daylight Time) at
the BMO Centre, Calgary, Alberta.

Dividend Payment DatesScheduled common share dividend payment dates in 2012 are January 31, April 30, July 31 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 PlanTransCanada'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 SharesComputershare Trust Company of Canada (Montréal, Toronto, Calgary and Vancouver) and
Computershare Trust Company, N.A. (Golden)

TransCanada Corporation First Preferred Shares, Series 1Computershare Trust Company of Canada (Montréal, Toronto,
Calgary and Vancouver)

TransCanada Corporation First Preferred Shares, Series 3Computershare Trust Company of Canada (Montréal, Toronto, Calgary
and Vancouver)

TransCanada Corporation First Preferred Shares, Series 5Computershare Trust Company of Canada (Montréal, Toronto, Calgary
and Vancouver)

TCPL First Preferred Shares, Series U and Series YComputershare 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 NotesCIBC Mellon Trust Company (Halifax, Montréal, Toronto, Calgary
and Vancouver)

TCPL U.S. Medium-Term Notes and Senior NotesThe Bank of New York Mellon (New York)

TCPL U.S. Junior Subordinated NotesThe Bank of Nova Scotia Trust Company of New York

168TRANSCANADA
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 NotesBNY Trust Company of Canada (Halifax, Montreal, Toronto, Calgary and Vancouver)

NGTL U.S. Medium-Term NotesU.S. Bank Trust National Association (New York)

REGULATORY FILINGS

Annual Information FormTransCanada's 2011 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
CORPORATION169

---



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, 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 DocumentsTransCanada 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
2012, 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 CommunityTransCanada'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:

Communications450 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.

170TRANSCANADA
CORPORATION

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BOARD OF DIRECTORS

(as at December 31, 2011)

|S. Barry Jackson(1)(2)
Chairman
TransCanada Corporation
Calgary, Alberta Russell K. GirlingPresident and CEO
TransCanada Corporation
Calgary, Alberta Kevin E. Benson(1)(3)
Corporate Director
Calgary, Alberta Derek H. Burney, O.C.(1)(4)
Senior Strategic Advisor
Norton Rose Canada 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 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 Paula Rosput Reynolds(9)
President and CEO
PreferWest LLC
Seattle, Washington W. Thomas Stephens(5)(8)
Former Chairman and
Chief Executive Officer
Boise Cascade, LLC
Greenwood Village, Colorado D. Michael G. Stewart(4)(5)
Corporate Director
Calgary, Alberta
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

TRANSCANADA
CORPORATION171

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CORPORATE GOVERNANCE

Please refer to TransCanada's Notice of 2012 annual meeting of shareholders and Management information circular for the company's statement of corporate governance.

TransCanada's
Corporate Governance Guidelines, Board charter, Committee charters, Chair and Chief Executive Officer 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 (www.sedar.com) and in the United States on EDGAR (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-LineThe 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.

172TRANSCANADA
CORPORATION

---



Contact
  information Visit www.transcanada.com
  for more information on: Our pipelines and energy businesses  Projects and initiatives Corporate
  responsibility Corporate governance Investor services TransCanada welcomes
  questions from shareholders and investors. Please contact: David Moneta,
  Vice-President, Investor Relations 1.800.361.6522 (Canada and U.S.
  Mainland) Alex Pourbaix President,
  Energy and Oil Pipelines Wendy
  Hanrahan Executive Vice-President, Corporate Services Sean McMaster Executive Vice-President,
  Stakeholder Relations and General Counsel Russ Girling President and Chief Executive Officer TransCanada Corporation TransCanada
  Tower, 450 First Street SW, Calgary, Alberta T2P 5H1 1.403.920.2000 1.800.661.3805 (From left to right) Don Wishart Executive
  Vice-President, Operations and Major Projects Don Marchand Executive Vice-President and Chief Financial
  Officer Dennis McConaghy Executive
  Vice-President, Corporate Development Greg
  Lohnes President, Natural Gas Pipelines


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. Please recycle Printed in Canada March 2012




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, which comprise the consolidated balance sheets as at December 31, 2011 and 2010, the consolidated
statements of income, comprehensive income, accumulated other comprehensive income, equity and cash flows for each of the years in the three-year period ended December 31, 2011, 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 consolidated financial position of TransCanada
Corporation as at December 31, 2011 and 2010 and the results of its consolidated operations and its consolidated cash flows for each of the years in the three-year period ended
December 31, 2011 in accordance with Canadian generally accepted accounting principles.

Other Matters

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, 2011, 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 13, 2012 expressed an unmodified opinion on the effectiveness of
TransCanada Corporation's internal control over financial reporting.

/s/
KPMG LLP
Chartered Accountants
Calgary, Canada
February 13, 2012

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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, 2011, based on 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 the Company's internal control over financial reporting based on our audit.

We
conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit
also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A
company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In
our opinion, TransCanada Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, 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 the standards of the Public Company Accounting Oversight Board (United States), the consolidated
balance sheets of TransCanada Corporation as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, accumulated other comprehensive income,
equity and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated February 13, 2012 expressed an unqualified opinion on those
consolidated financial statements.

/s/
KPMG LLP
Chartered Accountants
Calgary, Canada
February 13, 2012

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