QuickLinks -- Click here to rapidly navigate through this document

U.S. Securities and Exchange Commission
Washington, D.C. 20549
Form 40-F

For the fiscal year ended December 31, 2012            Commission File Number 1-31690

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

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

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

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, 2012, 705,461,386 common shares;
22,000,000 Cumulative Redeemable First Preferred Shares, Series 1;
14,000,000 Cumulative Redeemable First Preferred Shares, Series 3; and
14,000,000 Cumulative Redeemable First Preferred Shares, Series 5
were issued and outstanding

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

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

   

---

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

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 Shareholders 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 97 through 158 of the TransCanada Corporation 2012 Annual Report to Shareholders included herein.

B.    Management's Discussion and Analysis

For management's discussion and analysis, see pages 1 through 96 of the TransCanada Corporation 2012 Annual Report to Shareholders included herein under the heading "Management's discussion and 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 97 of the TransCanada Corporation 2012 Annual Report to Shareholders included herein.

2

---

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 "Other Information — Controls and Procedures" in Management's discussion and analysis on pages 77 and 78 of the TransCanada Corporation 2012 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 a code of business ethics for its directors, officers, employees and contractors. The Registrant's code is available on its website at www.transcanada.com. No waivers have been granted from any provision of the code during the 2012 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 page 32 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 page 67 of the TransCanada Corporation 2012 Annual Report to Shareholders.

3

---

IDENTIFICATION OF THE AUDIT COMMITTEE

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

FORWARD-LOOKING INFORMATION

We disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall.

Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements in this document may include information about the following, among other things:

•

anticipated business prospects



•

our financial and operational performance, including the performance of our subsidiaries



•

expectations or projections about strategies and goals for growth and expansion



•

expected cash flows



•

expected costs for planned projects, including projects under construction and in development



•

expected schedules for planned projects (including anticipated construction and completion dates)



•

expected regulatory processes and outcomes



•

expected outcomes with respect to legal proceedings, including arbitration



•

expected capital expenditures and contractual obligations



•

expected operating and financial results



•

the expected impact of future commitments and contingent liabilities



•

expected industry, market and economic conditions.

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this document.

Our forward-looking information is based on key assumptions, and subject to the following risks and uncertainties including the following:

Assumptions

•

inflation rates, commodity prices and capacity prices



•

timing of debt issuances and hedging



•

regulatory decisions and outcomes



•

foreign exchange rates



•

interest rates



•

tax rates



•

planned and unplanned outages and the use of our pipeline and energy assets

4

---

•

integrity and reliability of our assets



•

access to capital markets



•

anticipated construction costs, schedules and completion dates



•

acquisitions and divestitures.

Risks and uncertainties

•

our ability to successfully implement our strategic initiatives



•

whether our strategic initiatives will yield the expected benefits



•

the operating performance of our pipeline and energy assets



•

amount of capacity sold and rates achieved in our U.S. pipelines business



•

the availability and price of energy commodities



•

the amount of capacity payments and revenues we receive from our energy business



•

regulatory decisions and outcomes



•

outcomes of legal proceedings, including arbitration



•

performance of our counterparties



•

changes in the political environment



•

changes in environmental and other laws and regulations



•

competitive factors in the pipeline and energy sectors



•

construction and completion of capital projects



•

labour, equipment and material costs



•

access to capital markets



•

cybersecurity



•

interest and foreign exchange rates



•

weather



•

technological developments



•

economic conditions in North America as well as globally.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the U.S. Securities and Exchange Commission (SEC).

You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.

5

---

SIGNATURES

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

---

DOCUMENTS FILED AS PART OF THIS REPORT

---

TransCanada Corporation

2012 Annual information form

February 11, 2013

---

Table of Contents

Presentation of information			2
Forward-looking information			2
TransCanada Corporation			3
	Corporate structure		3
	Intercorporate relationships		4
General development of the business			4
	Developments in the Natural Gas Pipelines business		5
	Developments in the Oil Pipelines business		8
	Developments in the Energy business		10
Business of TransCanada			12
	Natural Gas Pipelines business		13
	Oil Pipelines business		14
	Regulation of the Natural Gas and Oil Pipelines businesses		15
	Energy business		16
General			19
	Employees		19
	Health, safety and environmental protection and social policies		19
Risk factors			20
Dividends			20
Description of capital structure			21
	Share capital		21
Credit ratings			23
	DBRS		24
	Moody's		24
	S&P		25
Market for securities			25
	Common shares		25
	Series 1 preferred shares		26
	Series 3 preferred shares		26
	Series 5 preferred shares		27
Directors and officers			27
	Directors		27
	Board committees		29
	Officers		29
	Conflicts of interest		30
Corporate governance			30
Audit committee			31
	Relevant education and experience of members		31
	Pre-approval policies and procedures		32
	External auditor service fees		32
Legal proceedings and regulatory actions			32
Transfer agent and registrar			33
Interest of experts			33
Additional information			33
Glossary			34
Schedule A			35
Schedule B			36

---

Presentation of information

Throughout this Annual Information Form (AIF), the terms, we, us, our, the Company and TransCanada mean TransCanada Corporation and its subsidiaries. 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 in the TransCanada Corporation – Corporate structure section below, such 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, 2012 (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. The Glossary found at the end of this AIF contains certain terms defined throughout this AIF and abbreviations and acronyms that may not otherwise be defined in this document.

Certain portions of TransCanada's Management's Discussion and Analysis dated February 11, 2013 (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.

Financial information is presented in accordance with United States generally accepted accounting principles (U.S. GAAP). Effective January 1, 2012, TransCanada adopted U.S. GAAP for reporting purposes. For more information regarding TransCanada's adoption of U.S. GAAP, refer to the Other information – Critical accounting policies and estimates and Other information – Accounting changes sections of the MD&A.

We use certain financial measures that do not have a standardized meaning under U.S. GAAP because we believe they improve our ability to compare results between reporting periods, and enhance understanding of our operating performance. Known as non-GAAP measures, they may not be comparable to similar measures provided by other companies. Refer to the About our business – Non-GAAP measures section of the MD&A for more information about the non-GAAP measures we use and a reconciliation to their U.S. GAAP equivalents, which section of the MD&A is incorporated by reference herein.

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.

We disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall.

Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements contained or incorporated by reference in this AIF may include information about the following, among other things:

•

anticipated business prospects

•

our financial and operational performance, including the performance of our subsidiaries

•

expectations or projections about strategies and goals for growth and expansion

•

expected cash flows

•

expected costs for planned projects, including projects under construction and in development

•

expected schedules for planned projects (including anticipated construction and completion dates)

•

expected regulatory processes and outcomes

•

expected outcomes with respect to legal proceedings, including arbitration

•

expected capital expenditures and contractual obligations

•

expected operating and financial results

•

the expected impact of future commitments and contingent liabilities

•

expected industry, market and economic conditions.

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this AIF and other disclosure incorporated by reference herein.

---

2 -- TransCanada Corporation

---

Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:

Assumptions

•

inflation rates, commodity prices and capacity prices

•

timing of debt issuances and hedging

•

regulatory decisions and outcomes

•

foreign exchange rates

•

interest rates

•

tax rates

•

planned and unplanned outages and the use of our pipeline and energy assets

•

integrity and reliability of our assets

•

access to capital markets

•

anticipated construction costs, schedules and completion dates

•

acquisitions and divestitures.

Risks and uncertainties

•

our ability to successfully implement our strategic initiatives

•

whether our strategic initiatives will yield the expected benefits

•

the operating performance of our pipeline and energy assets

•

amount of capacity sold and rates achieved in our U.S. pipelines business

•

the availability and price of energy commodities

•

the amount of capacity payments and revenues we receive from our energy business

•

regulatory decisions and outcomes

•

outcomes of legal proceedings, including arbitration

•

performance of our counterparties

•

changes in the political environment

•

changes in environmental and other laws and regulations

•

competitive factors in the pipeline and energy sectors

•

construction and completion of capital projects

•

labour, equipment and material costs

•

access to capital markets

•

cybersecurity

•

interest and foreign exchange rates

•

weather

•

technological developments

•

economic conditions in North America as well as globally.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the U.S. Securities and Exchange Commission (SEC).

You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to 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 the Canada Business Corporations Act (CBCA) on February 25, 2003 in connection with a plan of arrangement which established TransCanada as the parent company of TCPL. The arrangement was approved by TCPL common shareholders on April 25, 2003 and, following court approval and the filing of Articles of Arrangement, the arrangement became effective May 15, 2003. Pursuant to the arrangement, the common shareholders of TCPL exchanged each of their TCPL common shares for one common share of TransCanada. 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 TransCanada and its subsidiaries. TransCanada does not hold any material assets directly, other than the common shares of TCPL and receivables from certain of TransCanada's subsidiaries.

---

2012 Annual information form -- 3

---

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.

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 of TransCanada as at Year End or total consolidated revenues of TransCanada for the year then ended.

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 as well as 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. Refer to the Business of TransCanada section below for further information regarding our Natural Gas Pipelines, Oil Pipelines and Energy businesses.

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

---

DEVELOPMENTS IN THE NATURAL GAS PIPELINES BUSINESS

Date		Description of development
Canadian Mainline
December 2010		TransCanada filed an application with the National Energy Board (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 tolls 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 more closely reflected the Canadian Mainline's costs and throughput for 2011.
September 2011		We filed a comprehensive restructuring proposal (Mainline Restructuring Proposal) with the NEB for the Canadian Mainline. The proposal is intended to enhance the competitiveness of the Canadian Mainline and transportation from the Western Canadian Sedimentary Basin (WCSB), and includes a request for 2012 and 2013 tolls that align with the proposed changes to our business structure and the terms and conditions of service on the Canadian Mainline. The NEB established interim tolls for 2012 based on the approved 2011 final tolls.
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 then 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 Mainline Restructuring Proposal.
May 2012		We received NEB approval to build new pipeline facilities to provide Southern Ontario with additional natural gas supply from the Marcellus shale basin.
May 2012		The additional open season for firm transportation service on the Canadian Mainline, to bring additional Marcellus shale gas into Canada, closed. We were able to accommodate an additional 50 million cubic feet per day (MMcf/d) from the Niagara meter station to Kirkwall, Ontario, effective November 2012, with the potential for an additional 350 MMcf/d of incremental volume for November 2015, subject to finalizing precedent agreements with the interested parties.
June 2012		The NEB hearing on the Mainline Restructuring Proposal began and the hearing concluded in December 2012. A decision is not expected until late first quarter or early second quarter 2013.
November 2012		Natural gas supply from the Marcellus shale basin supply began moving in November 2012.
Alberta System
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		After a public hearing, 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 tolls 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.
March 2011		TransCanada commenced construction of the $275 million Horn River pipeline. In addition, the Company executed an agreement to extend the Horn River pipeline by approximately 100 kilometers (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 mile) extension of the Groundbirch pipeline and construction commenced.

---

2012 Annual information form -- 5

---

Date		Description of development
October 2011		Commercial integration of the Alberta System and ATCO Pipelines systems commenced. Under an agreement, the facilities of the Alberta System and ATCO Pipelines system are commercially operated as a single transmission system and transportation service is provided to customers by TransCanada pursuant to the Alberta System'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 the Alberta System and ATCO Pipelines system.
October 2011		The NEB approved the construction of natural gas pipeline projects for the Alberta System with a capital cost of approximately $910 million.
November – December 2011		The regulatory decisions by which commercial integration of the Alberta System and ATCO Pipelines system was authorized are the subject of appeals to the Federal Court of Appeal. TransCanada continues to work with ATCO to gather information for the final stage of the integration which is to swap assets of equal value and will require approval by both the Alberta Utilities Commission and the NEB.
May 2012		The approximate $250 million Horn River project was completed, extending the Alberta System into the Horn River shale play in British Columbia (B.C.).
June 2012		The NEB approved the Leismer-Kettle River Crossover project, a 77 km (46 mile) pipeline to expand the Alberta System with the intent of increasing capacity to meet demand in northeastern Alberta. The expected cost of the expansion is an estimated $160 million.
Third Quarter 2012		During the first nine months of 2012, TransCanada continued to expand its Alberta System by completing and placing in-service twelve separate pipeline projects at a total cost of approximately $680 million.
December 2012		TransCanada was waiting for approval of approximately $330 million in additional projects, including the $100 million Chinchaga Expansion and the $230 million Komie North project that would extend the Alberta System further into the Horn River area.
December 2012		The current settlements for the Alberta and Foothills systems expired. Final tolls for 2013 will be determined through either new settlements or rate cases and any orders resulting from the NEB's decision on the Mainline Restructuring Proposal.
January 2013		The NEB issued its recommendation to the Governor-in-Council that the proposed Chinchaga Expansion component of the Komie North project be approved, but denied the proposed Komie North Extension component. All applications awaiting approval as of the end of 2012 have now been addressed.
2013		We continue to advance pipeline development projects in B.C. and Alberta to transport new natural gas supply. We have filed applications with the NEB to expand the Alberta System to accommodate requests for additional natural gas transmission service throughout the northwest and northeast portions of the WCSB. In addition, subject to regulatory approvals, we propose to extend the Alberta System in northeast B.C. to connect both to the Prince Rupert Gas Transmission Project (as described below) and to additional North Montney gas supplies. Initial capital cost estimates are approximately $1 billion to $1.5 billion, with an in-service date targeted for the end of 2015. We have incremental firm commitments to transport approximately 3.4 billion cubic feet per day (Bcf/d) from western Alberta and northeastern B.C. by 2014.
Coastal GasLink
June 2012		We were selected by Shell Canada Limited (Shell) and its partners to design, build, own and operate the proposed Coastal GasLink project, an estimated $4 billion pipeline. The liquefied natural gas (LNG) Canada project is a joint venture led by Shell, with partners Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited. The approximate 650 km (404 mile) pipeline is expected to have an initial capacity of more than 1.7 Bcf/d and be placed in-service toward the end of the decade, subject to a final investment decision to be made by LNG Canada subsequent to obtaining final regulatory approvals.
Prince Rupert Gas Transmission Project
January 2013		We were selected by Progress Energy Canada Ltd. (Progress) to, subject to regulatory approvals, design, build, own and operate the proposed $5 billion Prince Rupert Gas Transmission Project. This proposed pipeline will transport natural gas primarily from the North Montney gas-producing region near Fort St John, B.C., to the proposed Pacific Northwest LNG export facility near Prince Rupert, B.C. We expect to finalize definitive agreements in early 2013, leading to an in-service date in late 2018. A final investment decision to construct the project is expected to be made by Progress following final regulatory approvals.
Mexican Pipelines
June 2011		The Guadalajara pipeline was completed. TransCanada and Mexico's Comisión Federal de Electricidad (CFE) have agreed to add a US$60 million compressor station to the pipeline.
February 2012		We signed a contract with the CFE for the approximately $500 million Tamazunchale Pipeline Extension Project. The project, which is supported by a 25-year contract with CFE, is a 30 inch pipeline with a capacity of 630 MMcf/d. Engineering, procurement and construction contracts have all been signed and construction related activities have begun. We expect the pipeline to be in-service in the first quarter of 2014.
November 2012		The CFE awarded us the Topolobampo pipeline. The project, which is supported by a 25-year contract with CFE, is a 30 inch pipeline with a capacity of 670 MMcf/d. We estimate total costs to be US$1 billion, and expect it to be in-service in mid-2016.
November 2012		The CFE awarded us the Mazatlan pipeline, from El Oro to Mazatlan, Mexico. The project, which is supported by a 25-year contract with CFE and interconnects with the Topolobampo project, is a 24 inch pipeline with a capacity of 200 MMcf/d. We estimate total costs to be US$400 million, and expect it to be in-service in 2016.

---

6 -- TransCanada Corporation

---

Date		Description of development
Alaska Pipeline Project
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.
March 2012		The Alaska North Slope producers (Exxon Mobil Corporation, ConocoPhillips and British Petroleum (BP)), along with TransCanada through its participation in the Alaska Pipeline Project, announced the companies have agreed on a work plan aimed at commercializing North Slope natural gas resources through an LNG option. This would involve construction of a natural gas pipeline from the North Slope to Valdez, Alaska where the gas would be liquefied and shipped to international markets.
May 2012		We received approval from the State of Alaska to suspend and preserve our activities on the Alaska/Alberta route and focus on the LNG alternative. This allowed us to defer our obligation to file for a FERC certificate for the Alberta route beyond fall 2012, our original deadline.
July 2012		The Alaska Pipeline Project announced a non-binding public solicitation of interest in securing capacity on a potential new pipeline system to transport Alaska's North Slope gas. The solicitation of interest took place between August 2012 and September 2012. There were a number of non-binding expressions of interest from potential shippers from a broad range of industry sectors in North America and Asia.
ANR Pipeline
June 2012		The FERC issued orders approving ANR's sale of its offshore assets to a newly created wholly owned subsidiary, TC Offshore LLC, allowing TC Offshore LLC to operate these assets as a stand-alone interstate pipeline.
August 2012		The FERC approved ANR Storage Company's settlement with its shippers.
November 2012		TC Offshore LLC began commercial operations.
Gas Transmission Northwest LLC (GTN)
May 2011		TransCanada closed the sale of a 25 per cent interest in each of GTN and Bison Pipeline LLC (Bison) to TC PipeLines, LP for a total transaction value of $605 million, which included US$81 million or 25 percent of GTN's outstanding debt.
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.
Northern Border
January 2013		Northern Border secured a final settlement agreement with its shippers that the FERC approved in December 2012, effective January 2013. The settlement rates for long-haul transportation are approximately 11 per cent lower than 2012 rates and depreciation was lowered from 2.4 to 2.2 per cent. The settlement also includes a three-year moratorium on filing cases or challenging the settlement rates but Northern Border must initiate another rate proceeding within five years.
Great Lakes
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. This settlement requires Great Lakes to file for new rates by November 1, 2013.
Bison
December 2010		Construction of Bison 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 GTN and Bison to TC PipeLines, LP for a total transaction value of $605 million, which included US$81 million or 25 percent of GTN's outstanding debt.

Further information about developments in the Natural Gas Pipelines business can be found in the MD&A in the About our business – A long-term strategy, Natural Gas Pipelines – Results, Natural Gas Pipelines – Outlook, Natural Gas Pipelines – Understanding the Natural Gas Pipelines business and Natural Gas Pipelines – Significant events sections, which sections of the MD&A are incorporated by reference herein.

---

2012 Annual information form -- 7

---

DEVELOPMENTS IN THE OIL PIPELINES BUSINESS

Date		Description of development
Gulf Coast Project
February 2012		We announced that what had previously been the Cushing to U.S. Gulf Coast portion of the Keystone XL Pipeline has its own independent value to the marketplace, and that we plan to build it as the stand-alone Gulf Coast Project, which is not part of the Keystone XL Presidential Permit process. We expect the 36-inch pipeline to have an initial capacity of up to 700,000 barrels per day (Bbl/d), and an ultimate capacity of 830,000 Bbl/d. We estimate the total cost of the project to be US$2.3 billion, and as of Year End, construction was approximately 35 per cent complete. US$300 million of the total cost is expected to be spent on the Houston Lateral pipeline, a 76 km (47 mile) pipeline that will transport crude oil to Houston refineries.
August 2012		Construction on the Gulf Coast Project commenced. We expect to place the pipeline in service at the end of 2013.
Keystone XL Pipeline
March 2010		The NEB approved TransCanada's application to construct and operate the Canadian portion of the Keystone U.S. Gulf Coast expansion.
April 2010		The U.S. Department of State (DOS) issued a Draft Environmental Impact Statement for Keystone XL.
June 2010		Keystone XL commenced operating at a reduced maximum operating pressure as the first section began delivering oil from Hardisty, Alberta to Wood River and Patoka in Illinois (Wood River/Patoka).
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 was achieved, 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 DOS 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.
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.
February 2012		TransCanada sent a letter to the DOS informing the DOS that TransCanada planned to file a Presidential Permit application in near future for Keystone XL. TransCanada also informed the DOS that the Cushing to U.S. Gulf Coast portion of the Keystone XL project would be constructed as the Gulf Coast Project and not as part of the Presidential Permit process.
May 2012		TransCanada filed revised fixed tolls for the Cushing Extension section of the Keystone Pipeline System with both the NEB and the FERC. The revised tolls, which reflect the final project costs of the Keystone Pipeline System, became effective July 1, 2012.
May 2012		We filed a Presidential Permit application (cross-border permit) with the DOS for Keystone XL to transport crude oil from the U.S./Canada border in Montana to Steele City, Nebraska. We continued to work collaboratively with the Nebraska Department of Environmental Quality (NDEQ) and various other stakeholders throughout 2012 to determine an alternative route in Nebraska that would avoid the Nebraska Sandhills. We had proposed an alternative route to the NDEQ in April 2012, and then modified the route in response to comments from the NDEQ and other stakeholders.
September 2012		TransCanada submitted a Supplemental Environmental Report to the NDEQ for the proposed re-route for Keystone XL in Nebraska, and provided an environmental report to the DOS, required as part of the DOS review of our cross-border permit application.
January 2013		The NDEQ issued its final evaluation report on our proposed re-route of Keystone XL to the Governor of Nebraska. The report noted that the proposed re-route avoids the Nebraska Sandhills, and that construction and operation of Keystone XL is expected to have minimal environmental impacts in Nebraska. In January, the Governor of Nebraska approved our proposed re-route. The DOS is now completing their environmental and National Interest Determination review process and we are awaiting their decision on our cross-border permit application. We estimate the total cost of the project to be US$5.3 billion and, as of Year End, had invested US$1.8 billion. We expect the pipeline to be in-service in late 2014 or early 2015, subject to regulatory approvals.

---

8 -- TransCanada Corporation

---

Date		Description of development
Marketlink Projects
November 2010		The open seasons for the Bakken Marketlink and Cushing Marketlink projects, which commenced in September 2010, closed successfully.
October 2012		We have commenced construction on the Cushing Marketlink receipt facilities and expect to begin transporting crude oil supply from the Permian Basin producing region in western Texas to the U.S. Gulf Coast in late 2013 after our Gulf Coast Project is placed in-service. Our Bakken Marketlink project will transport crude oil supply from the Williston Basin producing region in North Dakota and Montana to Cushing, Oklahoma on facilities that form part of Keystone XL which remains subject to regulatory approval.
Keystone Hardisty Terminal
March 2012		We launched and concluded a binding open season to obtain commitments from interested parties for the Keystone Hardisty Terminal.
May 2012		We announced that we had secured binding long-term commitments of more than 500,000 Bbl/d for the Keystone Hardisty Terminal, and are expanding the proposed two million barrel project to a 2.6 million barrel terminal at Hardisty, Alberta, due to strong commercial support. We expect the terminal to be operational in late 2014 and cost approximately $275 million.
Northern Courier Pipeline
August 2012		We announced that we had been selected by Fort Hills Energy Limited Partnership to design, build, own and operate the proposed Northern Courier Pipeline. We estimate total capital costs to be $660 million. The pipeline system is fully subscribed under long-term contract to service the Fort Hills mine, which is jointly owned by Suncor Energy Inc, Total E&P Canada Ltd. and Teck Resources Limited. The project is conditional on the Fort Hills project receiving sanctions by the owners of the Fort Hills mine and is subject to regulatory approval.
Grand Rapids Pipeline
October 2012		We announced that we had entered into binding agreements with Phoenix Energy Holdings Limited (Phoenix) to develop the Grand Rapids Pipeline in northern Alberta. The project, which includes crude oil and diluent lines, will have the capacity to move up to 900,000 Bbl/d of crude oil and 330,000 Bbl/d of diluent. We and Phoenix will each own 50 per cent of the project and we will operate the system, which is expected to cost $3 billion. Phoenix has entered into a long-term commitment to ship crude oil and diluent on this pipeline. We expect the Grand Rapids Pipeline system, subject to regulatory approvals, to be placed in-service in multiple stages, with initial crude oil service by mid-2015 and the complete system in-service by the second half of 2017.
Canadian Mainline Conversion
Third Quarter 2012		We have determined that it is technically and economically feasible to convert a portion of the Canadian Mainline natural gas pipeline system to crude oil service. We are actively pursuing this project and have begun soliciting input from stakeholders and prospective shippers to determine market acceptance.

Further information about developments in the Oil Pipelines business can be found in the MD&A in the About our business – A long-term strategy, Oil Pipelines – Results, Oil Pipelines – Outlook, Oil Pipelines – Understanding the Oil Pipelines business and Oil Pipelines – Significant events sections, which sections of the MD&A are incorporated by reference herein.

---

2012 Annual information form -- 9

---

DEVELOPMENTS IN THE ENERGY BUSINESS

Date		Description of development
Sundance
Second Quarter 2010		Sundance B Unit 3 experienced an unplanned outage related to mechanical failure of certain generator components and was subject to a force majeure claim by TransAlta Corporation (TransAlta). The ASTC Power Partnership, which holds the Sundance B power purchase agreement (PPA), disputed the claim under the binding dispute resolution process provided in the PPA because we did not believe TransAlta's claim met the test of force majeure. We therefore recorded equity earnings from our 50 per cent ownership interest in ASTC Power Partnership as though this event were a normal plant outage.
December 2010		Sundance A Units 1 and 2 were withdrawn from service.
January 2011		Sundance A Units 1 and 2 were subject to a force majeure claim by TransAlta.
February 2011		TransAlta informed us that it was not economic to replace or repair Units 1 and 2, and that the Sundance A PPA should be terminated. We disputed both the force majeure and the economic destruction claims under the binding dispute resolution process provided in the PPA.
July 2012		An arbitration panel decided that the Sundance A PPA should not be terminated and ordered TransAlta to rebuild Units 1 and 2. The panel also limited TransAlta's force majeure claim from November 20, 2011 until the units can reasonably be returned to service. TransAlta announced that it expects the units to be returned to service in the fall of 2013. Since we considered the outages to be an interruption of supply, we accrued $188 million in pre-tax income between December 2010 and March 2012. The outcome of the decision was that we received approximately $138 million of this amount. We recorded the $50 million difference as a charge to second quarter 2012 earnings, of which $20 million related to amounts accrued in 2011. We will not record further revenue or costs from the PPA until the units are returned to service. The net book value of the Sundance A PPA recorded in Intangibles and Other Assets remains fully recoverable.
November 2012		An arbitration decision was reached with the arbitration panel granting partial force majeure relief to TransAlta with respect to Sundance B Unit, and we reduced our equity earnings by $11 million from the ASTC Power Partnership to reflect the amount that will not be recovered as result of the decision.
Napanee Generating Station
December 2012		We signed a contract with the Ontario Power Authority (OPA), to develop, own and operate a new 900 megawatt (MW) natural gas-fired power plant at Ontario Power Generation's Lennox site in Eastern Ontario in the town of Greater Napanee. The plant will replace the facility that was planned and subsequently cancelled in the community of Oakville, Ontario and will operate under a 20-year Clean Energy Supply contract with the OPA. We were reimbursed for $250 million of costs, mainly related to natural gas turbines that were purchased for the Oakville project, which will now be used at Napanee. We plan to invest approximately $1.0 billion in the Napanee facility.
Cartier Wind
November 2011		The Montagne-Sèche project and phase one of the Gros-Morne wind farm were completed.
November 2012		We placed the second phase of the Gros-Morne wind farm project in-service, completing the 590 MW, five-phase Cartier Wind Project in Québec. All of the power produced by Cartier Wind is sold to Hydro-Québec Distribution (Hydro-Québec) under 20-year PPAs.
Ontario Solar
December 2011		We agreed to buy nine Ontario solar projects (combined capacity of 86 MW) from Canadian Solar Solutions Inc. (Canadian Solar), for approximately $476 million. Under the terms of the agreement, Canadian Solar will develop and build each of the nine solar projects using photovoltaic panels. We will buy each project once construction and acceptance testing are complete and commercial operation begins. All power produced will be sold under 20-year PPAs with the OPA under the Feed-in Tariff program in Ontario. We expect to close the acquisition of the first two projects (combined capacity of 20 MW) in the first half of 2013 for a total cost of approximately $125 million. We expect to acquire the other seven projects in 2013 to late 2014, subject to regulatory approvals.
Bécancour
June 2011		Hydro-Québec notified us 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. We continue to receive capacity payments under the agreement similar to those that would have been received under the normal course of operation.
June 2012		Hydro-Québec notified us that it would exercise its option to extend the agreement to suspend all electricity generation from the Bécancour power plant through 2013. Under the suspension agreement, Hydro-Québec has the option (subject to certain conditions) to extend the suspension every year until regional electricity demand levels recover. We continue to receive capacity payments while generation is suspended.

---

10 -- TransCanada Corporation

---

Date		Description of development
Bruce
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 was subject to spot prices effective June 1, 2012 until the restart of both Units 1 and 2 was 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 then 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.
November 2011		Bruce Power commenced the West Shift Plus outage as part of the life extension strategy for Unit 3.
March 2012		Bruce Power received authorization from the Canadian Nuclear Safety Commission to power up the Unit 2 reactor.
May 2012		An incident occurred within the Unit 2 electrical generator on the non-nuclear side of the plant which delayed the synchronization of Unit 2 to the Ontario electrical grid. As a result, Bruce Power submitted a force majeure claim to the OPA.
June 2012		Bruce Power returned Unit 3 to service after completing the $300 million West Shift Plus life extension outage, which began in 2011. Unit 4 is expected to return to service in late first quarter 2013 after the completion of an expanded outage investment program that began in August 2012. These investments should allow Units 3 and 4 to produce low cost electricity until at least 2021.
August 2012		TransCanada confirmed that Bruce Power's force majeure claim to the OPA related to Unit 2 (Bruce A) had been accepted. The claim was the result of a May 2012 event that delayed the synchronization of this unit to the Ontario power grid. With the acceptance of the force majeure claim, Bruce Power continued to receive the contracted price for power generated from the operating units at Bruce A after July 1, 2012.
October 2012		Unit 1 and 2 were returned to service following the completion of the refurbishment. The incident in May 2012 within the Unit 2 electrical generator on the non-nuclear side of the plant had delayed returning the units to service. Bruce Power's force majeure claim to the OPA was accepted in August, and it continued to receive the contracted price for power generated during the force majeure period.
November 2012		Both Units 1 and 2 have operated at reduced output levels following their return to service, and Bruce Power took Unit 1 offline for an approximate one month maintenance outage. Bruce Power expects the availability percentages for Units 1 and 2 to increase over time, however, these units have not operated for an extended period of time and may experience slightly higher forced outage rates and reduced availability percentages in 2013. Overall plant availability for Bruce A is expected to be approximately 90 per cent in 2013.
Ravenswood
Third and Fourth Quarters 2011		Spot prices for capacity sales in the New York Zone J market were negatively impacted by the manner in which the New York Independent System Operator (NYISO) applied pricing rules for a power plant that had recently began service in this market. We jointly filed two formal complaints with the FERC challenging how the NYISO applied its buy-side mitigation rules affecting bidding criteria associated with two new power plants that began service in the New York Zone J markets during the summer of 2011.
June 2012		The FERC addressed the first complaint, indicating it would take steps to increase transparency and accountability for future mitigation exemption tests (MET) and decisions.
September 2012		The FERC granted an order on the second complaint, directing the NYISO to retest the two new power plants as well as a transmission project currently under construction using an amended set of assumptions to more accurately perform the MET calculations, in accordance with existing rules and tariff provisions. The recalculation was completed in November 2012 and it was determined that one of the plants had been granted an exemption in error. That exemption was revoked and the plant is now required to offer its capacity at a floor price which has put upward pressure on capacity auction prices since December. The order was prospective only and has no impact on capacity prices for prior periods.
CrossAlta
December 2012		We acquired the remaining 40 per cent interests in the Crossfield Gas Storage facility and CrossAlta Gas Storage & Services Ltd. marketing company from BP for approximately $220 million. We now own and operate 100 per cent of the interests of CrossAlta. The acquisition added an additional 27 billion cubic feet (Bcf) of working gas storage capacity to our existing portfolio in Alberta.
Coolidge
May 2011		Coolidge power generating station was completed and placed in-service.
Kibby Wind
October 2010		The 22 turbine, 66 MW second phase of Kibby Wind was completed and placed in service.
Halton Hills
September 2010		The 683 MW Halton Hills power plant was completed and placed in-service.

---

2012 Annual information form -- 11

---

Further information about developments in the Energy business can be found in the MD&A in the About our business – A long-term strategy, Energy – Results, Energy – Outlook, Energy – Understanding the Energy business and Energy – Significant events sections, which sections of the MD&A are incorporated by reference herein.

Business of TransCanada

We are a leading North American energy infrastructure company focused on Natural Gas Pipelines, Oil Pipelines and Energy. At Year End and for the year then ended, Natural Gas Pipelines accounted for approximately 53 per cent of revenues and 48 per cent of TransCanada's total assets, Oil Pipelines accounted for approximately 13 per cent of revenues and 22 per cent of TransCanada's total assets and Energy accounted for approximately 34 per cent of revenues and 27 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, 2012 and 2011.

Revenues from operations (millions of dollars)			2012		2011
Natural Gas Pipelines
	Canada – Domestic		$2,294		$2,180
	Canada – Export(1)		751		786
	United States		1,112		1,207
	Mexico		107		71
			4,264		4,244
Oil Pipelines
	Canada – Domestic		–		–
	Canada – Export(1)		370		300
	United States		669		527
			1,039		827
Energy(2)
	Canada – Domestic		1,233		1,749
	Canada – Export(1)		–		1
	United States		1,471		1,018
			2,704		2,768
Total revenues(3)			$8,007		$7,839

(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.

---

12 -- TransCanada Corporation

---

NATURAL GAS PIPELINES BUSINESS
TransCanada delivers natural gas to local distribution companies, power generation facilities and other businesses across Canada, the U.S. and Mexico. Our Natural Gas Pipelines and related holdings are described below.

We are the operator of all of the following natural gas pipelines and storage assets except for Iroquois.

		Length		Description		Effective ownership
Canadian pipelines
Alberta System		24,337 km (15,122 miles)		Gathers and transports natural gas within Alberta and Northeastern B.C., and connects with the Canadian Mainline, Foothills system and third-party pipelines		100%
Canadian Mainline		14,101 km (8,762 miles)		Transports natural gas from the Alberta/Saskatchewan border to the Québec/Vermont border, and connects with other natural gas pipelines in Canada and the U.S.		100%
Foothills		1,241 km (771 miles)		Transports natural gas from central Alberta to the U.S. border for export to the U.S. Midwest, Pacific northwest, California and Nevada		100%
Trans Québec & Maritimes (TQM)		572 km (355 miles)		Connects with Canadian Mainline near the Ontario/Québec border to transport natural gas to the Montreal to Québec City corridor, and connects with the Portland pipeline system that serves the northeast U.S.		50%
U.S. pipelines
ANR Pipeline		16,656 km (10,350 miles)		Transports natural gas from producing fields in Texas and Oklahoma, from offshore and onshore regions of the Gulf of Mexico and from the U.S. midcontinent, for delivery mainly to Wisconsin, Michigan, Illinois, Indiana and Ohio. Connects with Great Lakes		100%
ANR Storage		250 Bcf		Provides regulated underground natural gas storage service from facilities located in Michigan
Bison		487 km (303 miles)		Transports natural gas from the Powder River Basin in Wyoming to Northern Border in North Dakota. We effectively own 83.3 per cent of the system through the combination of our 75 per cent direct ownership interest and our 33.3 per cent interest in TC PipeLines, LP		83.3%
GTN		2,178 km (1,353 miles)		Transports natural gas from the WCSB and the Rocky Mountain region to Washington, Oregon and California. Connects with Tuscarora and Foothills. We effectively own 83.3 per cent of the system through the combination of our 75 per cent direct ownership interest and our 33.3 per cent interest in TC PipeLines, LP		83.3%
Great Lakes		3,404 km (2,115 miles)		Connects with ANR and the Canadian Mainline near Emerson, Manitoba, to transport natural gas to eastern Canada, and the U.S. upper Midwest. We effectively own 69.0 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 33.3 per cent interest in TC PipeLines, LP		69%
Iroquois		666 km (414 miles)		Connects with Canadian Mainline near Waddington, New York to deliver natural gas to customers in the U.S. northeast		44.5%
North Baja		138 km (86 miles)		Transports natural gas between Ehrenberg, Arizona and Ogilby, California, and connects with a third-party natural gas system on the California/Mexico border. We effectively own 33.3 per cent of the system through our 33.3 per cent interest in TC PipeLines, LP		33.3%
Northern Border		2,265 km (1,407 miles)		Transports natural gas through the U.S. Midwest, and connects with Foothills near Monchy, Saskatchewan. We effectively own 16.7 per cent of the system through our 33.3 per cent interest in TC PipeLines, LP		16.7%
Portland		474 km (295 miles)		Connects with TQM near East Hereford, Québec, to deliver natural gas to customers in the U.S. northeast		61.7%
Tuscarora		491 km (305 miles)		Transports natural gas from GTN at Malin, Oregon to Wadsworth, Nevada, and delivers gas in northeastern California and northwestern Nevada. We effectively own 33.3 per cent of the system through our 33.3 per cent interest in TC PipeLines, LP.		33.3%

---

2012 Annual information form -- 13

---

		Length		Description		Effective ownership
Mexican pipelines
Guadalajara		310 km (193 miles)		Transports natural gas from Manzanillo to Guadalajara in Mexico		100%
Tamazunchale		130 km (81 miles)		Transports natural gas from Naranjos, Veracruz in east central Mexico to Tamazunchale, San Luis Potos, Mexico		100%
Under construction
Mazatlan Pipeline		413 km (257 miles)		To deliver natural gas from El Oro to Mazatlan, Mexico. Connects to the Topolobampo Pipeline Project		100%
Tamazunchale Pipeline Extension		235 km (146 miles)		Extend existing terminus of the Tamazunchale Pipeline to deliver natural gas to power generating facilities in El Sauz, Queretaro, Mexico		100%
Topolobampo Pipeline		530 km (329 miles)		To deliver natural gas from Chihuahua to Topolobampo, Mexico		100%
In development
Alaska Pipeline Project		2,737 km (1,700 miles)		To transport natural gas from Prudhoe Bay to Alberta, or from Prudhoe Bay to LNG facilities in south-central Alaska. We have an agreement with ExxonMobil to jointly advance the projects
Coastal GasLink		650 km* (404 miles)		To deliver natural gas from the Montney gas-producing region near Dawson Creek, B.C. to LNG Canada's proposed LNG facility near Kitimat, B.C.
Prince Rupert Gas Transmission Project		750 km* (466 miles)		To deliver natural gas from North Montney gas producing region near Fort St. John, B.C. to the proposed Pacific Northwest LNG facility near Prince Rupert, B.C.

*

Pipe lengths are estimates as final route is still under design.

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 in the Natural Gas Pipelines – Results, Natural Gas Pipelines – Understanding the Natural Gas Pipelines business and Natural Gas Pipelines – Significant events sections, which sections of the MD&A are incorporated by reference herein.

OIL PIPELINES BUSINESS
TransCanada contracts and delivers North American crude oil supply to key U.S. markets. Our Oil Pipelines and related holdings are described below.

We are the operator of all of the following pipelines and properties.

		Length		Description		Ownership
Oil pipelines
Keystone Pipeline System		3,467 km (2,154 miles)		Transports crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma		100%
Under construction
Cushing Marketlink		Crude oil receipt facilities		To transport crude oil from the Permian Basin producing region in western Texas to the U.S. Gulf Coast refining market on facilities that form part of the Gulf Coast Project		100%
Gulf Coast Project		780 km (485 miles)		To transport crude oil from the hub at Cushing, Oklahoma to the U.S. Gulf Coast refinery market. Includes the 76 km (47 mile) Houston Lateral pipeline		100%
Keystone Hardisty Terminal		Crude oil terminal		Crude oil terminal to be located at Hardisty, Alberta, providing Western Canadian producers with new crude oil batch accumulation tankage and pipeline infrastructure and access to the Keystone Pipeline System		100%

---

14 -- TransCanada Corporation

---

		Length		Description		Ownership
In development
Bakken Marketlink		Crude oil receipt facilities		To transport crude oil from the Williston Basin producing region in North Dakota and Montana to Cushing, Oklahoma on facilities that form part of Keystone XL		100%
Canadian Mainline conversion				Conversion of a portion of the Canadian Mainline natural gas pipeline system to crude oil service, which will transport crude oil between Hardisty, Alberta and markets in eastern Canada		100%
Grand Rapids Pipeline		500 km (300 miles)		To transport crude oil between the producing area northwest of Fort McMurray and the Edmonton/Heartland market region. Project is a partnership with Phoenix		50%
Keystone XL		1,897 km (1,179 miles)		Pipeline from Hardisty, Alberta to Steele City, Nebraska to expand capacity of the Keystone Pipeline System to 1.4 million Bbl/d. Awaiting U.S. Presidential Permit decision		100%
Northern Courier Pipeline		90 km (56 miles)		To transport bitumen and diluent between the Fort Hills mine site and the Voyageur Upgrader located north of Fort McMurray, Alberta		100%

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 in the Oil Pipelines – Results, Oil Pipelines – Understanding the Oil Pipelines business and Oil Pipelines – Significant events sections, which sections of the MD&A are incorporated by reference herein.

REGULATION OF THE NATURAL GAS AND OIL PIPELINES BUSINESSES

Canada

Natural Gas Pipelines
Under the terms of the National Energy Board Act (Canada), the Canadian Mainline, the Alberta System and other Canadian pipelines owned or operated by TransCanada (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 on or associated with the Systems 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.

Natural Gas Pipeline Projects
The Coastal GasLink Pipeline and the Prince Rupert Gas Transmission projects are being proposed and developed primarily under the regulatory regime administered by the B.C. Oil and Gas Commission (BCOGC) and the B.C. Environmental Assessment Office (BCEAO). The BCOGC is responsible for overseeing oil and gas operations in B.C., including exploration, development, pipeline transportation and reclamation. The BCEAO is an agency that manages the review of proposed major projects in B.C., as required by the B.C. Environmental Assessment Act. Both projects are also subject to the provisions of the Canadian Environmental Assessment Act. Pre-application activities are currently underway with the BCOGC and BCEAO as well as the Canadian Environmental Assessment Agency.

Oil Pipelines
The NEB regulates the terms and conditions of service, including rates, and the physical operation of the Canadian portion of the Keystone Pipeline System, including the Keystone Hardisty Terminal. NEB approval is also required for facility additions. The rates for transportation service on the Keystone Pipeline System are calculated in accordance with a methodology agreed to in transportation service agreements between Keystone and its shippers, and approved by the NEB.

Oil Pipeline Projects
The Northern Courier Pipeline and Grand Rapids Pipeline projects are being proposed and developed primarily under the regulatory regime administered by the Alberta Energy Resources Conservation Board (ERCB) and Alberta Environment and Sustainable Resource Development (ESRD). ERCB approval is required to construct and operate the pipelines and associated facilities. ESRD approval is required to construct and operate a tank terminal when the project involves the storage of more than 10,000 cubic meters (62,898 Bbl/d) of refined petroleum products. Pre-application activities are currently underway.

United States

Natural Gas Pipelines
TransCanada's wholly owned and partially owned U.S. pipelines are considered natural gas companies operating under the provisions of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and are subject to the jurisdiction of the FERC. The Natural Gas

---

2012 Annual information form -- 15

---

Act of 1938 grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation and interstate commerce. The ANR System's natural gas storage facilities in Michigan are also regulated by FERC.

Oil Pipelines
The FERC also regulates the terms and conditions of service, including transportation rates, on the U.S. portion of the Keystone Pipeline System. Certain states in which Keystone Pipeline System has rights of way also regulate construction and siting of Keystone Pipeline System. The Keystone XL pipeline remains subject to the DOS decision on TransCanada's Presidential Permit application.

Mexico

Natural Gas Pipelines
TransCanada's pipelines in Mexico are regulated by the Comisión Reguladora de Energía or Energy Regulatory Commission (CRE). The CRE regulates the construction and operation of pipeline facilities including the approval of tariffs, services and related rates. However, the contracts underpinning the facilities in Mexico are long-term negotiated rate contracts and not subject to further regulatory approval.

ENERGY BUSINESS
TransCanada's Energy business includes a portfolio of power generation assets in Canada and the U.S., and unregulated natural gas storage assets in Alberta. This 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 natural gas storage in Alberta. Our Energy assets and related holdings are described below.

We are the operator of all of our Energy assets, except for the Sheerness, Sundance A and Sundance B PPAs, Cartier Wind, Bruce A and B and Portlands Energy.

		Generating capacity (MW)		Type of fuel		Description		Location		Ownership
Canadian Power
8,070 MW of power generation capacity (including facilities in development)
Western Power
2,636 MW of power supply in Alberta and the western U.S.
Bear Creek		80		natural gas		Cogeneration plant		Grand Prairie, Alberta		100%
Cancarb		27		natural gas, waste heat		Facility fuelled by waste heat from an adjacent TransCanada facility that produces thermal carbon black, a by-product of natural gas		Medicine Hat, Alberta		100%
Carseland		80		natural gas		Cogeneration plant		Carseland, Alberta		100%
Coolidge(1)		575		natural gas		Simple-cycle peaking facility		Coolidge, Arizona		100%
Mackay River		165		natural gas		Cogeneration plant		Fort McMurray, Alberta		100%
Redwater		40		natural gas		Cogeneration plant		Redwater, Alberta		100%
Sheerness PPA		756		coal		PPA for entire output of facility		Hanna, Alberta		100%
Sundance A PPA		560		coal		PPA for entire output of facility		Wabamun, Alberta		100%
Sundance B PPA (Owned by ASTC Power Partnership(2))		353(3)		coal		PPA for entire output of facility		Wabamun, Alberta		50%
Eastern Power
2,950 MW of power generation capacity (including facilities in development)
Bécancour		550		natural gas		Cogeneration plant		Trois-Rivières, Québec		100%
Cartier Wind		366(3)		wind		Five wind power projects		Gaspésie, Québec		62%
Grandview		90		natural gas		Cogeneration plant		Saint John, New Brunswick		100%
Halton Hills		683		natural gas		Combined-cycle plant		Halton Hills, Ontario		100%
Portlands Energy		275(3)		natural gas		Combined-cycle plant		Toronto, Ontario		50%

---

16 -- TransCanada Corporation

---

		Generating capacity (MW)		Type of fuel		Description		Location		Ownership
Bruce Power
2,484 MW of power generation capacity through eight nuclear power units
Bruce A		1,4623		nuclear		Four operating reactors		Tiverton, Ontario		48.9%
Bruce B		1,0223		nuclear		Four operating reactors		Tiverton, Ontario		31.6%
U.S. Power
3,755 MW of power generation capacity
Kibby Wind		132		wind		Wind farm		Kibby and Skinner Townships, Maine		100%
Ocean State Power		560		natural gas		Combined-cycle plant		Burrillville, Rhode Island		100%
Ravenswood		2,480		natural gas and oil		Multiple-unit generating facility using dual fuel-capable steam turbine, combined-cycle and combustion turbine technology		Queens, New York		100%
TC Hydro		583		hydro		13 hydroelectric facilities, including stations and associated dams and reservoirs		New Hampshire, Vermont and Massachusetts (on the Connecticut and Deerfield rivers)		100%
Unregulated natural gas storage
118 Bcf of non-regulated natural gas storage capacity
CrossAlta		68 Bcf4				Underground facility connected to Alberta System		Crossfield, Alberta		100%
Edson		50 Bcf				Underground facility connected to Alberta System		Edson, Alberta		100%
In development
Napanee		900		natural gas		Proposed combined-cycle plant		Greater Napanee, Ontario		100%
Ontario Solar		86		solar		Nine solar projects from Canadian Solar Solutions Inc. We expect to acquire the first two projects in the first half of 2013, and the remaining seven projects in 2013 to late 2014		Southern Ontario and New Liskeard, Ontario		100%

(1)

Located in Arizona, results reported in Canadian Power – Western Power.

(2)

We have a 50 per cent interest in ASTC Power Partnership, which has a PPA in place for 100 per cent of the production from the Sundance B power generating facilities.

(3)

Our share of power generation capacity.

(4)

Reflects the acquisition of an additional 27 Bcf of working gas storage capacity in December 2012.

---

2012 Annual information form -- 17

---

We own or have the rights to approximately 2,600 MW of power supply in Alberta and Arizona, through three long-term PPAs, five natural gas-fired cogeneration facilities, and through Coolidge, a simple-cycle, natural gas peaking facility in Arizona.

Power purchased under long-term contracts is as follows:

		Type of contract		With		Expires
Sheerness PPA		Power purchased under a 20-year PPA		ATCO Power and TransAlta Utilities Corporation		2020
Sundance A PPA		Power purchased under a 20-year PPA		TransAlta Utilities Corporation		2017
Sundance B PPA		Power purchased under a 20-year PPA (we own 50% through the ASTC Partnership)		TransAlta Utilities Corporation		2020

Power sold under long-term contracts is as follows:

		Type of contract		With		Expires
Coolidge		Power sold under a 20-year PPA		Salt River Project Agricultural Improvements & Power District		2031

We own or are developing approximately 3,000 MW of power generation capacity in eastern Canada. All of the power produced by these assets is sold under contract. Disciplined maintenance of plant operations is critical to the results of our eastern power assets, where earnings are based on plant availability and performance.

Assets currently operating under long-term contracts are as follows:

		Type of contract		With		Expires
Bécancour1		20-year PPA		Hydro-Québec		2026
		Steam sold to an industrial customer
Cartier Wind		20-year PPA		Hydro-Québec		2032
Grandview		20-year tolling agreement to buy 100 per cent of heat and electricity output		Irving Oil		2025
Halton Hills		20-year Clean Energy Supply contract		OPA		2030
Portlands Energy		20-year Clean Energy Supply contract		OPA		2029

(1)

Power generation has been suspended since 2008.

Assets currently in development are as follows:

		Type of contract		With		Expires
Ontario Solar		20-year Feed-in Tariff (FIT) contracts		OPA		20 years from in-service date
Napanee		20-year Clean Energy Supply contract		OPA		20 years from in-service date

We own approximately 3,800 MW of power generation capacity in New York and New England, including plants powered by natural gas, oil, hydro and wind.

We own or control 156 Bcf of non-regulated natural gas storage capacity in Alberta. This includes contracts for long-term, Alberta-based storage capacity from a third party, which expire in 2030, subject to early termination rights in 2015. This business operates independently from our regulated natural gas transmission business and from ANR's regulated storage business, which are included in our Natural Gas Pipelines segment.

Further information about the Company's Energy holdings and significant developments and opportunities in relation to Energy can be found in the MD&A in the Energy – Results, Energy – Understanding the Energy business and Energy – Significant events sections, which sections of the MD&A are incorporated by reference herein.

---

18 -- TransCanada Corporation

---

General

EMPLOYEES
At Year End, TransCanada's principal operating subsidiary, TCPL, had approximately 4,900 full time active employees, substantially all of whom were employed in Canada and the U.S., as set forth in the following table.

Calgary		2,247
Western Canada (excluding Calgary)		495
Houston		549
U.S. Midwest		468
U.S. Northeast		414
Eastern Canada		268
U.S. Southeast/Gulf Coast		275
U.S. West Coast		80
Mexico and South America		73
Total		4,869

HEALTH, SAFETY AND ENVIRONMENTAL PROTECTION AND SOCIAL POLICIES
The Health, Safety and Environment committee monitors compliance with our health, safety and environment (HSE) corporate policy through regular reporting from management. We have an integrated HSE management system that establishes a framework for managing HSE issues and is used to capture, organize and document our related policies, programs and procedures.

Our management system for HSE is modeled after international standards for environmental management systems, conforms to external industry consensus standards and voluntary regulatory programs, and complies with applicable legislative requirements and various other internal management systems. It follows a continuous improvement cycle organized into four key areas:

•

Planning: risk and regulatory assessment, objectives and targets, and structure and responsibility

•

Implementing: development and implementation of programs, procedures and practices aimed at operational risk management

•

Reporting: document and records management, communication and reporting, and

•

Action: ongoing audit and review of HSE performance.

The committee reviews HSE performance quarterly compared to previously set targets relating thereto, and taking into account incidents and highlights of performance in this regard during the relevant quarter, and reviews program plans and performance targets for subsequent years. It receives detailed reports on our operational risk management, including governance of these risks, operational performance and preventive maintenance, pipeline integrity, operational risk issues and applicable legislative developments. The committee also receives updates on any specific areas of operational risk management review currently being conducted by management.

Environmental policies
TransCanada's facilities are subject to federal, state, provincial, and local environmental statutes and regulations governing environmental protection, including, but not limited to, air emissions and greenhouse gas 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. We have implemented inspection and audit programs designed to keep all of our facilities in compliance with environmental requirements.

Safety and asset integrity
As one of TransCanada's priorities, safety is an integral part of the way our employees work. Since 2008, we have sustained year over year improvement in our safety performance. Overall, TransCanada's incident frequency rates in 2012 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. Our pipeline safety record in 2012 continued to be better than industry benchmarks.

---

2012 Annual information form -- 19

---

TransCanada routinely conducts emergency response field exercises to help ensure effective coordination between the Company, local emergency responders, regulatory agencies and members of the public in the event of an emergency. It also facilitates improving our emergency preparedness and response program and procedures.

Aboriginal, Native American and stakeholder engagement
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.

Risk factors

A discussion of the Company's risk factors can be found in the MD&A in the Natural Gas Pipelines – Business risks, Oil Pipelines – Business risks, Energy – Business risks and Other information – Risks and risk management sections, which sections of the MD&A are incorporated by reference into this AIF.

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 preferential cash 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. The dividend on the Series 1 preferred shares will reset on December 31, 2014 and every five years thereafter to a rate equal to the sum of the then five year Government of Canada bond yield and 1.92 per cent. The holders of Series 1 preferred shares have the right to convert their shares into cumulative redeemable first preferred shares, series 2 (the Series 2 preferred shares) as set out under the heading First preferred shares below.

Holders of cumulative redeemable first preferred shares, series 3 (Series 3 preferred shares) are entitled to receive fixed cumulative preferential cash 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. The dividend on the Series 3 preferred shares will reset on June 30, 2015 and every five years thereafter to a rate equal to the sum of the then five year Government of Canada bond yield and 1.28 per cent. The holders of Series 3 preferred shares have the right to convert their shares into cumulative redeemable first preferred shares, series 4 (the Series 4 preferred shares) as set out under the heading First preferred shares below.

Holders of cumulative redeemable first preferred shares, series 5 (Series 5 preferred shares) are entitled to receive fixed cumulative preferential cash 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. The dividend on the Series 5 preferred shares will reset on January 30, 2016 and every five years thereafter to a rate equal to the sum of the then five year Government of Canada bond yield and 1.54 per cent. The holders of Series 5 preferred shares have the right to convert their shares into cumulative redeemable first preferred shares, series 6 (the Series 6 preferred shares) as set out under the heading First preferred shares below.

---

20 -- TransCanada Corporation

---

The dividends declared on the Series 1, 3 and 5 preferred shares during the past three completed financial years are set out in the following table:

		2012		2011		2010
Dividends declared on Series 1 preferred shares		$1.15		$1.15		$1.15
Dividends declared on Series 3 preferred shares		$1.00		$1.00		$0.80	(1)
Dividends declared on Series 5 preferred shares		$1.10		$1.10		$0.65	(2)

(1)

Reflects dividends declared for the period from issuance on March 11, 2010 to December 31, 2010.

(2)

Reflects dividends declared per share for the period from issuance on June 29, 2010 to December 31, 2010.

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

		2012		2011		2010
Dividends declared on common shares		$1.76		$1.68		$1.60

In February 2013, the Board approved an increase in the quarterly dividend on our outstanding common shares by five per cent to $0.46 per share from $0.44 per share for the quarter ending March 31, 2013.

Description of capital structure

SHARE CAPITAL
TransCanada's authorized share capital consists of an unlimited number of common shares, of which 705,461,386 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 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 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 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 (an acquiring person), 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 plan (a permitted bid). 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 permitted bid, is referred to as a flip-in event. Ten trading days after a flip-in event, each TransCanada right will permit registered holders other than an acquiring person to receive, upon payment of the exercise price, the number of common shares with an aggregate market price equal to twice the exercise price. Continuation of, and amendments to, the Shareholder rights plan will be voted on at the 2013 annual and special meeting of shareholders.

TransCanada has a dividend reinvestment and share purchase plan (DRP) 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, and shares provided in lieu of dividends were issued from treasury. The discount was set at three per cent in 2010, and was reduced to two per cent commencing

---

2012 Annual information form -- 21

---

with the dividends declared in February 2011. 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 DRP.

TransCanada also has stock-based compensation plans that allow some employees to purchase common shares of TransCanada. Option exercise prices are equal to the closing price on the Toronto Stock Exchange (TSX) on the last trading day immediately preceding the grant date. Options granted under the plans are generally fully exercisable after three years and expire seven years after the date of grant. At our 2013 annual and special meeting of shareholders, TransCanada's shareholders will vote on reconfirming our stock option plan and any amendments as described in TransCanada's Management Information Circular dated February 11, 2013.

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 its liquidation, dissolution or winding up.

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

The provisions attaching to the first preferred shares as a class may be modified, amended or varied only with the approval of the holders of the first preferred shares as a class. Any such approval to be given by the holders of the first preferred shares may be given by the affirmative vote of the holders of not less than 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 heading Dividends. The Series 1 preferred shares are redeemable by TransCanada in whole or in part on December 31, 2014, and on December 31 in every fifth year thereafter, 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 in every fifth year thereafter. The holders of Series 2 preferred shares will be entitled to receive quarterly floating rate cumulative preferential cash 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 and have the right to convert their shares into Series 1 preferred shares, subject to certain conditions, on December 31, 2019 and on December 31 in every fifth year thereafter. 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. Other than with respect to redemption rights (as described below), the material characteristics of the Series 2 preferred shares are substantially the same as the Series 1 preferred shares. The Series 2 preferred shares are redeemable by TransCanada in whole or in part on any date after December 31, 2014, by the payment of an amount in cash for each share to be redeemed equal to (i) $25.00 in the case of redemptions on December 31, 2019 and on December 31 in every fifth year thereafter, or (ii) $25.50 in the case of redemptions on any other date, in each case plus all accrued and unpaid dividends thereon.

The Series 3 preferred shares are entitled to the payment of dividends as set out above under the heading Dividends. The rights, privileges, restrictions and conditions attaching to the Series 3 preferred shares are substantially identical to those attaching to the Series 1 preferred shares, except as outlined below. The Series 3 preferred shares are redeemable by TransCanada in whole or in part on June 30, 2015, and on June 30, 2015 and in every fifth year thereafter, 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 in every fifth year thereafter. The holders of Series 4 preferred shares will be entitled to receive quarterly floating rate cumulative preferential cash 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 and have the right to convert their shares into Series 3 preferred shares, subject to certain conditions, on June 30, 2020 and on June 30 in every fifth year thereafter. In the event of liquidation, dissolution or winding up of

---

22 -- TransCanada Corporation

---

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. Other than with respect to redemption rights (as described below), the material characteristics of the Series 4 preferred shares are substantially the same as the Series 3 preferred shares. The Series 4 preferred shares are redeemable by TransCanada in whole or in part on any date after June 30, 2015, by the payment of an amount in cash for each share to be redeemed equal to (i) $25.00 in the case of redemptions on June 30, 2020 and on June 30 in every fifth year thereafter, or (ii) $25.50 in the case of redemptions on any other date, in each case plus all accrued and unpaid dividends thereon.

The Series 5 preferred shares are entitled to the payment of dividends as set out above under the heading Dividends. The rights, privileges, restrictions and conditions attaching to the Series 5 preferred shares are substantially identical to those attaching to the Series 1 preferred shares, except as outlined below. The Series 5 preferred shares are redeemable by TransCanada in whole or in part on January 30, 2016, and on January 30 in every fifth year thereafter, 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 in every fifth year thereafter. The holders of Series 6 preferred shares will be entitled to receive quarterly floating rate cumulative preferential cash 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 and have the right to convert their shares into Series 5 preferred shares, subject to certain conditions, on January 30, 2021 and on January 30 in every fifth year thereafter. 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. Other than with respect to redemption rights (as described below), the material characteristics of the Series 6 preferred shares are substantially the same as the Series 5 preferred shares. The Series 6 preferred shares are redeemable by TransCanada in whole or in part on any date after January 30, 2016, by the payment of an amount in cash for each share to be redeemed equal to (i) $25.00 in the case of redemptions on January 30, 2021 and on January 30 in every fifth year thereafter, or (ii) $25.50 in the case of redemptions on any other date, in each case plus all accrued and unpaid dividends thereon.

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 on such series of preferred shares, 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.

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) and its outstanding preferred shares have also been assigned credit ratings by Moody's, S&P and DBRS Limited (DBRS). 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

---

2012 Annual information form -- 23

---

following table sets out the current credit ratings assigned to those outstanding classes of securities of the Company and TCPL which have been rated by DBRS, Moody's and S&P:

		DBRS		Moody's		S&P
Senior unsecured debt
Debentures		A		A3		A-
Medium-term notes		A		A3		A-
Junior subordinated notes		BBB (high)		Baa1		BBB
Preferred shares		Pfd-2 (low)		Baa2		P-2
Commercial paper		R-1 (low)		–		A-2
Trending/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.

Each of the Company and TCPL paid fees to each of DBRS, Moody's and S&P for the credit ratings rendered their outstanding classes of securities noted above. Other than annual monitoring fees for the Company and TCPL and their rated securities, no additional payments were made to DBRS, Moody's and S&P in respect of any other services provided to us during the past two years.

The information concerning our credit ratings relates to our financing costs, liquidity and operations. The availability of our funding options may be affected by certain factors, including the global capital market environment and outlook as well as our financial performance. Our access to capital markets at competitive rates is dependent on our credit rating and rating outlook, as determined by credit rating agencies such as DBRS, Moody's and S&P, and if our ratings were downgraded TransCanada'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
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 capacity for payment of short-term financial obligations as they fall due is substantial. The overall strength is not as favourable as higher rating categories and may be vulnerable to future events, but any qualifying negative factors that exist are considered manageable. The A rating assigned to TCPL's senior unsecured debt is in the third highest of ten categories for long-term debt. Long-term debt rated A is good credit quality. The capacity for the payment of interest and principal is substantial, but 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 companies whose long-term debt is rated in the A category.

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.

---

24 -- TransCanada Corporation

---

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 eight 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 TSX and the New York Stock Exchange (NYSE) under the symbol TRP. TransCanada's Series 1, 3 and 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 out the reported monthly high, low, and month-end closing trading prices and monthly trading volumes of the common shares of TransCanada on the TSX and the NYSE, and the respective Series 1, 3 and 5 preferred shares on the TSX, for the period indicated:

COMMON SHARES

		TSX (TRP)								NYSE (TRP)
Month		High ($)		Low ($)		Close ($)		Volume Traded		High (US$)		Low (US$)		Close (US$)		Volume Traded
December 2012		$47.44		$45.30		$47.02		22,542,514		$47.78		$45.69		$47.32		8,599,319
November 2012		$45.98		$43.64		$45.98		20,383,391		$46.13		$43.56		$45.99		6,643,142
October 2012		$45.45		$43.16		$44.97		23,049,914		$46.58		$43.54		$45.23		4,749,881
September 2012		$45.61		$44.26		$44.74		23,361,386		$47.02		$44.27		$45.50		4,531,523
August 2012		$46.29		$44.36		$44.40		25,112,761		$46.76		$44.84		$45.07		7,970,340
July 2012		$46.00		$42.73		$45.67		30,066,257		$45.90		$41.68		$45.45		7,591,231
June 2012		$43.30		$41.47		$42.67		27,804,268		$42.56		$39.87		$41.90		8,808,940
May 2012		$43.55		$41.78		$42.33		24,869,200		$44.20		$40.35		$40.92		10,263,574
April 2012		$43.80		$42.10		$43.46		26,627,021		$44.50		$41.93		$43.98		10,157,804
March 2012		$44.60		$42.31		$42.83		30,474,321		$45.07		$42.38		$43.00		14,759,355
February 2012		$43.69		$41.02		$43.57		27,988,166		$44.21		$41.13		$43.98		10,105,156
January 2012		$44.75		$40.34		$41.25		36,915,568		$44.28		$39.74		$41.05		14,839,199

---

2012 Annual information form -- 25

---

SERIES 1 PREFERRED SHARES

		TSX (TRP.PR.A)
Month		High ($)		Low ($)		Close ($)		Volume Traded
December 2012		$25.75		$25.25		$25.69		251,155
November 2012		$25.70		$25.21		$25.33		345,144
October 2012		$25.85		$25.41		$25.50		214,250
September 2012		$25.95		$25.46		$25.81		94,025
August 2012		$26.15		$25.64		$25.77		183,141
July 2012		$26.03		$25.50		$25.80		103,746
June 2012		$25.82		$25.26		$25.70		217,717
May 2012		$26.24		$25.40		$25.50		203,126
April 2012		$26.22		$25.80		$26.18		814,719
March 2012		$26.46		$25.60		$25.80		173,582
February 2012		$27.19		$26.15		$26.20		202,767
January 2012		$27.17		$26.15		$26.57		352,329

SERIES 3 PREFERRED SHARES

		TSX (TRP.PR.B)
Month		High ($)		Low ($)		Close ($)		Volume Traded
December 2012		$24.47		$24.14		$24.43		321,065
November 2012		$24.97		$24.15		$24.23		309,882
October 2012		$25.10		$24.82		$24.96		423,217
September 2012		$25.36		$24.79		$24.90		493,093
August 2012		$25.69		$25.20		$25.33		110,019
July 2012		$25.60		$25.05		$25.39		235,273
June 2012		$25.25		$24.96		$25.12		384,867
May 2012		$25.69		$25.05		$25.20		205,547
April 2012		$25.66		$25.30		$25.43		543,553
March 2012		$25.58		$25.00		$25.35		274,498
February 2012		$26.15		$25.35		$25.36		407,748
January 2012		$25.79		$25.25		$25.63		459,012

---

26 -- TransCanada Corporation

---

SERIES 5 PREFERRED SHARES

		TSX (TRP.PR.C)
Month		High ($)		Low ($)		Close ($)		Volume Traded
December 2012		$26.07		$25.61		$25.95		156,765
November 2012		$25.80		$25.36		$25.59		172,451
October 2012		$25.64		$25.30		$25.43		217,288
September 2012		$25.97		$25.26		$25.40		105,706
August 2012		$25.98		$25.59		$25.85		212,511
July 2012		$25.93		$25.35		$25.59		207,273
June 2012		$25.80		$25.39		$25.48		136,967
May 2012		$26.29		$25.55		$25.65		235,317
April 2012		$25.94		$25.43		$25.80		286,584
March 2012		$26.10		$25.40		$25.54		143,516
February 2012		$26.60		$25.69		$25.99		118,814
January 2012		$26.35		$25.60		$25.91		276,704

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 11, 2013, the directors and officers of TransCanada as a group beneficially owned, or exercised control or direction, directly or indirectly, over an aggregate of 405,905 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 directors who serve on the Board, as of February 11, 2013 (unless otherwise indicated), together with their jurisdictions of residence, all positions and offices held by them with TransCanada, 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 since
Kevin E. Benson DeWinton, Alberta Canada		Corporate director, Director, Calgary Airport Authority. President and Chief Executive Officer, Laidlaw International, Inc. (transportation services) from June 2003 to October 2007.		2005
Derek H. Burney(1), O.C. Ottawa, Ontario Canada		Senior strategic advisor at Norton Rose Canada LLP (law firm). Director, Paradigm Capital Inc. Advisory Board. Chair, Canwest Global Communications Corp. (communications) from August 2006 (director since April 2005) to October 2010.		2005
E. Linn Draper Lampasas, Texas U.S.		Corporate director, Director, Alliance Data Systems Corporation (data processing and services) and Alpha Natural Resources, Inc. (mining). Chair, NorthWestern Corporation (conducting business as NorthWestern Energy) (oil and gas).		2005
The 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 and the Fondation du Musée national des beaux-arts du Québec. Director, Institut Québecois des Hautes Études Internationales, Laval University from August 2002 to June 2009, RBC Dexia Investors Trust until October 2011 and Care Canada from October 2010 to December 2011.		2002

---

2012 Annual information form -- 27

---

Russell K. Girling Calgary, Alberta Canada		President and Chief Executive Officer, TransCanada since July 2010. Chief Operating Officer from July 2009 to June 2010 and President, Pipelines from June 2006 to June 2010. Director, Agrium Inc.		2010
S. Barry Jackson Calgary, Alberta Canada		Corporate director, Chair of the Board, TransCanada since April 2005. Chair, Nexen Inc. (oil and gas) and director, Laricina Energy Ltd. and WestJet Airlines Ltd. Director, Cordero Energy Inc. from April 2005 to September 2008.		2002
Paul L. Joskow New York, New York U.S.		Economist and President of the Alfred P. Sloan Foundation. Professor of Economics, Emeritus, Massachusetts Institute of Technology (MIT). Director, Exelon Corporation (energy), and a trustee of Putnam Mutual Funds.		2004
John A. MacNaughton(2)(3) C.M. Toronto, Ontario Canada		Corporate director. Chair, Business Development Bank of Canada from August 2007 to December 2012 and the Independent Nominating Committee of the Canada Employment Insurance Financing Board from July 2008 to January 2013. Member of the Prime Minister's Advisory Committee on the Public Service from May 2010 to January 2013. Chair, CNSX Markets Inc. (formerly the Canadian Trading and Quotation System Inc.) (stock exchange) from February 2006 to July 2010. Director, Nortel Networks Corporation and Nortel Networks Limited (the principal operating subsidiary of Nortel Networks Corporation) (technology) from June 2005 to September 2010.		2006
Paula Rosput Reynolds Seattle, Washington U.S.		President and Chief Executive Officer of PreferWest, LLC (business advisory group). Director, Anadarko Petroleum Corporation, Delta Air Lines, Inc. and BAE Systems plc. Vice Chair and Chief Restructuring Officer, American International Group Inc. (insurance and financial services) from October 2008 to September 2009. President and Chief Executive Officer, Safeco Corporation (insurance) from January 2006 to February 2008.		2011
Mary Pat Salomone(4)(5) Charlotte, North Carolina, U.S.		Senior Vice-President & Chief Operating Officer of The Babcock & Wilcox Company. Manager of Business Development from 2009 to 2010 and Manager of Strategic Acquisitions from 2008 to 2009, Babcock & Wilcox Nuclear Operations Group, Inc. Director, United States Enrichment Corporation, from December 2011 to October 2012.		2013
W. Thomas Stephens(6) Greenwood Village, Colorado U.S.		Corporate director. Trustee, Putnam Mutual Funds. Chair and Chief Executive Officer, Boise Cascade, LLC (paper, forest products and timberland assets) from November 2004 to November 2008. Director, Boise Inc. from February 2008 to April 2010.		2007(4)
D. Michael G. Stewart Calgary, Alberta Canada		Corporate director. Director, Canadian Energy Services & Technology Corp. (oil and gas) and Pengrowth Energy Corporation (oil & gas). Director, C&C Energia Ltd. from May 2010 to December 2012 and Orleans Energy Ltd. (oil & gas) 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.		2006
Richard E. Waugh Toronto, Ontario Canada		Chief Executive Officer and director of The Bank of Nova Scotia (Scotiabank). Director, Catalyst Inc. and Chair, Catalyst Canada Advisory Board. Director and President, International Monetary Conference. Vice-Chair, 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. MacNaughton resigned from the Board effective January 9, 2013.

(4)

Ms. Salomone joined the Board effective February 12, 2013.

(5)

Ms. Salomone was a director of Crucible Materials Corp. (Crucible) from May 2008 through May 1, 2009. On May 6, 2009, Crucible and one of its affiliates filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware (the Bankruptcy Court). On August 26, 2010, the Bankruptcy Court entered an order confirming Crucible's Second Amended Chapter 11 Plan of Liquidation.

(6)

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

---

28 -- TransCanada Corporation

---

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 11, 2013, are identified below. Mr. MacNaughton was the Chair of the Governance committee and a member of the Audit committee until the date of his resignation effective January 9, 2013. Mr. Burney was appointed as the Chair of the Governance committee effective February 11, 2013.

Director		Audit committee		Governance committee		Health, Safety and Environment committee		Human Resources committee
Kevin E. Benson		Chair		ü
Derek H. Burney		ü		Chair
E. Linn Draper						Chair		ü
Paule Gauthier						ü		ü
S. Barry Jackson				ü				ü
Paul L. Joskow		ü		ü
Paula Rosput Reynolds						ü		ü
W. Thomas Stephens						ü		Chair
D. Michael G. Stewart		ü				ü
Richard E. Waugh				ü

The respective charters of the Audit, Governance, Health, Safety and Environment and Human Resources committees can be found on our website (www.transcanada.com) under Corporate governance – Board committees. Information about the Audit committee can be found in this AIF under the heading Audit committee.

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

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

Executive officers

Name		Present position held		Principal occupation during the five preceding years
Russell K. Girling		President and Chief Executive Officer		Prior to July 2010, Chief Operating Officer since July 2009 and President, Pipelines since June 2006.
Wendy L. Hanrahan		Executive Vice-President, Corporate Services		Prior to May 2011, Vice-President, Human Resources since January 2005.
Karl R. Johannson		Executive Vice-President and President, Natural Gas Pipelines		Senior Vice-President, Canadian and Eastern U.S. Pipelines from January 2011 to October 2012. Senior Vice-President, Power Commercial from January 2006 to December 2010.
Gregory A. Lohnes(1)		Executive Vice-President, Operations and Major Projects		Prior to November 2012, Executive Vice-President and 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, Stakeholder Relations and General Counsel and Chief Compliance Officer		Prior to February 2012, Executive Vice-President, Corporate and 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.

(1)

Mr. Lohnes has held the position of Executive Vice-President, Operations and Major Projects since November 2012, upon the retirement of Mr. Donald Wishart who held the position since July 2009.

---

2012 Annual information form -- 29

---

Corporate officers

Name		Present position held		Principal occupation during the five preceding years
Sean M. Brett		Vice-President and Treasurer		Prior to July 2010, Vice-President, Commercial Operations of TC PipeLines GP, Inc., and Director, LP Operations of TCPL. Prior to 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.
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.
Joel E. Hunter		Vice-President, Finance		Director, Corporate Finance, January 2008 to July 2010.
Christine R. Johnston(1)		Vice-President and Corporate Secretary		Vice-President, Finance Law from January 2010 to March 2012. Vice-President, Corporate Development Law from September 2009 to December 2009. Associate General Counsel, Corporate Development and Finance Law from September 2005 to September 2009.
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.

(1)

Ms. Johnston has held the position of Vice-President and Corporate Secretary since March 2012, upon the retirement of Mr. Donald DeGrandis who had held the position of Corporate Secretary since June 2006.

CONFLICTS OF INTEREST
Directors and officers of TransCanada and its subsidiaries are required to disclose any existing or potential conflicts in accordance with TransCanada policies governing directors and officers and in accordance with the CBCA. The Board believes that it is important for it to be composed of qualified and knowledgeable directors. As a result, due to the specialized nature of the energy infrastructure business, some of the nominated directors are associated with or sit on the boards of companies that ship natural gas or crude oil through our pipeline systems. Transmission services on most of TransCanada's pipeline systems in Canada and the U.S. are subject to regulation and accordingly we generally cannot deny transportation services to a creditworthy shipper. The Governance committee monitors relationships among directors to ensure that business associations do not affect the Board's performance. If a director declares that they have an interest in a material contract or transaction that is being considered by the Board, the director leaves the meeting so the matter can be discussed and voted on.

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 TSX and Canadian Securities Administrators:

•

National Instrument 52-110, Audit committees

•

National Policy 58-201, Corporate Governance Guidelines, and

•

National Instrument 58-101, Disclosure of Corporate Governance Practices.

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 the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Wall Street Reform and Consumer Protection Act.

---

30 -- TransCanada Corporation

---

Further information about TransCanada's corporate governance can be found on our website (www.transcanada.com) under the heading Corporate governance and in the Governance section of TransCanada's Management Information Circular dated February 11, 2013.

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 the Corporate governance – Board committees page.

RELEVANT EDUCATION AND EXPERIENCE OF MEMBERS
The members of the Audit committee as of February 11, 2013 are Kevin E. Benson (Chair), Derek H. Burney, Paul L. Joskow, and D. Michael G. Stewart. Mr. Draper was a member of the Audit committee from May 1, 2009 to April 26, 2012 and became a member of the Human Resources committee effective April 27, 2012. Mr. MacNaughton was a member of the Audit committee from May 1, 2009 to January 9, 2013, the effective date of his retirement as a director of TransCanada. Richard E. Waugh attends the Audit committee meetings as an observer and does not vote on any matters.

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.

Kevin E. Benson
Mr. Benson is a Chartered Accountant (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 most of those boards, including serving as a trustee of Putnam Mutual Funds since October 1997, where he served as the Chair of the audit committee from November 2002 until December 2005.

John A. MacNaughton
Mr. MacNaughton earned a Bachelor of Arts in Economics from the University of Western Ontario. During his term as a member of TransCanada's Audit committee, Mr. MacNaughton was the Chair of the Business Development Bank of Canada. He was Chair of

---

2012 Annual information form -- 31

---

CNSX Markets Inc. (formerly Canadian Trading and Quotation System Inc.) until July 2010. In prior years, Mr. MacNaughton 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 39 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 up to $250,000, approval of the Audit committee Chair is required, and the Audit committee is to be informed of the engagement at the next scheduled Audit committee meeting. For all engagements of $250,000 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 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 table below shows the services KPMG provided during the last two fiscal years and the fees we paid them:

($ millions)		2012		2011
Audit fees •  audit of the annual consolidated financial statements •  services related to statutory and regulatory filings or engagements •  review of interim consolidated financial statements and information contained in various prospectuses and other offering documents		$5.7		$6.9
Audit-related fees •  services related to the audit of the financial statements of certain TransCanada post-retirement and post-employment plans		0.1		0.2
Tax fees •  Canadian and international tax planning and tax compliance matters, including the review of income tax returns and other tax filings		0.5		0.4
All other fees •  review of information system design procedures •  services related to vendor analytics and environmental compliance credits		0.6		0.1
Total fees		$6.9		$7.6

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 outcomes 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. We are not aware of any potential legal proceeding or action that would have a material impact on our consolidated financial position, results of operations or liquidity.

The most significant this year were the TransAlta Sundance A claims, which were resolved through a binding arbitration process that resulted in a decision in July 2012. For further information regarding the Sundance A claims, refer to the General developments of the business – Developments of the Energy business section of this AIF above and the Energy – Significant events section of the MD&A, which section is incorporated by reference herein.

---

32 -- TransCanada Corporation

---

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, Halifax 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

1.

Additional information in relation to TransCanada may be found under TransCanada's profile on SEDAR (www.sedar.com).

2.

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

3.

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

---

2012 Annual information form -- 33

---

Glossary

Units of measure

Bbl/d		Barrel(s) per day
Bcf		Billion cubic feet
Bcf/d		Billion cubic feet per day
GWh		Gigawatt hours
MMcf/d		Million cubic feet per day
MW		Megawatt(s)
MWh		Megawatt hours

General terms and terms related to our operations

bitumen		A thick, heavy oil that must be diluted to flow (also see: diluent). One of the components of the oil sands, along with sand, water and clay.
Canadian Restructuring Proposal		Canadian Mainline business and services restructuring proposal and 2012 and 2013 Mainline final tolls application
cogeneration facilities		Facilities that produce both electricity and useful heat at the same time.
diluent		A thinning agent made up of organic compounds. Used to dilute bitumen so it can be transported through pipelines.
FIT		Feed-in tariff
force majeure		Unforeseeable circumstances that prevent a party to a contract from fulfilling it.
fracking		Hydraulic fracturing. A method of extracting natural gas from shale rock.
GHG		Greenhouse gas
HSE		Health, safety and environment
LNG		Liquefied natural gas
MET		Mitigation exemption tests
OM&A		Operating, maintenance and administration
PJM Interconnection area (PJM)		A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia
PPA		Power purchase arrangement
WCSB		Western Canada Sedimentary Basin

Accounting terms

AFUDC		Allowance for funds used during construction
AOCI		Accumulated other comprehensive (loss)/income
ARO		Asset retirement obligations
ASU		Accounting Standards Updatepension
DRP		Dividend reinvestment plan
EBIT		Earnings before interest and taxes
EBITDA		Earnings before interest, taxes, depreciation and amortization
FASB		Financial Accounting Standards Board (U.S.)
OCI		Other comprehensive (loss)/income
RRA		Rate-regulated accounting
ROE		Rate of return on common equity
U.S. GAAP		U.S. generally accepted accounting principles

Government and regulatory bodies

CFE		Comisión Federal de Electricidad (Mexico)
CRE		Comisión Reguladora de Energia, or Energy Regulatory Commission (Mexico)
DOS		Department of State (U.S.)
FERC		Federal Energy Regulatory Commission (U.S.)
IEA		International Energy Agency
ISO		Independent System Operator
LMCI		Land Matters Consultation Initiative (Canada)
NDEQ		Nebraska Department of Environmental Quality (U.S.)
NEB		National Energy Board (Canada)
OPA		Ontario Power Authority (Canada)
RGGI		Regional Greenhouse Gas Initiative (northeastern U.S.)
SEC		U.S. Securities and Exchange Commission

---

34 -- TransCanada Corporation

---

Schedule A
Metric conversion table

The conversion factors set out below are approximate factors. To convert from Metric to Imperial multiply by the factor indicated. To convert from Imperial to Metric divide by the factor indicated.

Metric		Imperial		Factor
Kilometres (km)		Miles		0.62
Millimetres		Inches		0.04
Gigajoules		Million British thermal units		0.95
Cubic metres*		Cubic feet		35.3
Kilopascals		Pounds per square inch		0.15
Degrees Celsius		Degrees Fahrenheit		to convert to Fahrenheit multiply by 1.8, then add 32 degrees; to convert to Celsius subtract 32 degrees, then divide by 1.8

*

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

---

2012 Annual information form -- 35

---

Schedule B
Charter of the Audit Committee

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

•

Company's financial accounting and reporting process;

•

integrity of the financial statements

•

Company's internal control over financial reporting;

•

external financial audit process;

•

compliance by the Company with legal and regulatory requirements; and

•

independence and performance of the Company's internal and external auditors.

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

2. ROLES AND RESPONSIBILITIES

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

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

II. Oversight in Respect of Financial Disclosure
The Audit Committee, to the extent it deems it necessary or appropriate, shall:

(a)

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

(b)

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

(c)

review and discuss with management and external auditors the use of non-GAAP information and the applicable reconciliation;

(d)

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

(e)

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

---

36 -- TransCanada Corporation

---

(f)

review and discuss quarterly reports from the external auditors on:

(i)

all critical accounting policies and practices to be used;

(ii)

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

(iii)

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

(g)

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

(h)

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

(i)

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

(j)

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

III. Oversight in Respect of Legal and Regulatory Matters

(a)

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

IV. Oversight in Respect of Internal Audit

(a)

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

(b)

review the significant findings prepared by the internal audit department and recommendations issued by it or by any external party relating to internal audit issues, together with management's response thereto;

(c)

review compliance with the Company's policies and avoidance of conflicts of interest;

(d)

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

(e)

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

(i)

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

(ii)

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

(iii)

the internal audit department responsibilities, budget and staffing;

and to report to the Board on such meetings;

V. Insight in Respect of the External Auditors

(a)

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

(b)

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

(c)

receive and review annually the external auditors' formal written statement of independence delineating all relationships between itself and the Company;

---

2012 Annual information form -- 37

---

(d)

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

(i)

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

(ii)

any changes required in the planned scope of the audit;

and to report to the Board on such meetings;

(e)

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

(f)

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

(g)

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

(h)

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

(i)

ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law, but at least every five years;

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

(a)

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

(i)

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

(ii)

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

(iii)

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

(b)

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

(c)

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

(d)

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

VII. Oversight in Respect of Certain Policies

(a)

review and recommend to the Board for approval the implementation and amendments to policies and program initiatives deemed advisable by management or the Audit Committee with respect to the Company's codes of business ethics and Risk Management and Financial Reporting policies;

(b)

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

(c)

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

(d)

annually review and assess the adequacy of the Company's public disclosure policy;

(e)

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

---

38 -- TransCanada Corporation

---

VIII. Oversight in Respect of Financial Aspects of the Company's Canadian Pension Plans (the "Company's pension plans"), specifically:

(a)

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

(b)

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

(c)

receive, review and report to the Board on the actuarial valuation and funding requirements for the Company's pension plans;

(d)

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

(e)

approve the appointment or termination of auditors and investment managers;

IX. U.S. Stock Plans
To review and approve the engagement and related fees of the auditor for any plan of a U.S. subsidiary that offers Company stock to employees as an investment option under the plan.

X. Oversight in Respect of Internal Administration

(a)

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

(b)

oversee the succession planning for the senior management in finance, treasury, tax, risk, internal audit and the controllers' group.

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

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

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

---

2012 Annual information form -- 39

---

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

6. AUDIT COMMITTEE CHAIR
The Board shall appoint a Chair of the Audit Committee who shall:

(a)

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

(b)

preside over meetings of the Audit Committee;

(c)

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

(d)

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

(e)

meet as necessary with the internal and external auditors.

7. ABSENCE OF AUDIT COMMITTEE CHAIR
If the Chair of the Audit Committee is not present at any meeting of the Audit Committee, one of the other members of the Audit Committee present at the meeting shall be chosen by the Audit Committee to preside at the meeting.

8. SECRETARY OF AUDIT COMMITTEE
The Corporate Secretary shall act as Secretary to the Audit Committee.

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

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

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

12. ATTENDANCE OF COMPANY OFFICERS AND EMPLOYEES AT MEETING
At the invitation of the Chair of the Audit Committee, one or more officers or employees of the Company may attend any meeting of the Audit Committee.

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

14. REVIEW OF CHARTER AND EVALUATION OF AUDIT COMMITTEE
The Audit Committee shall review its Charter annually or otherwise, as it deems appropriate and, if necessary, propose changes to the Governance Committee and the Board. The Audit Committee shall annually review the Audit Committee's own performance.

---

40 -- TransCanada Corporation

---

15. OUTSIDE EXPERTS AND ADVISORS
The Audit Committee is authorized, when deemed necessary or desirable, to retain and set and pay the compensation for independent counsel, outside experts and other advisors, at the Company's expense, to advise the Audit Committee or its members independently on any matter.

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

---

2012 Annual information form -- 41

---

Management's discussion and analysis

February 11, 2013

This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the year ended December 31, 2012. Comparative figures, which were previously presented in accordance with Canadian generally accepted accounting principles (as defined in Part V of the Canadian Institute of Chartered Accountants Handbook), have been adjusted as necessary to be compliant with our accounting policies under United States generally accepted accounting principles (U.S. GAAP), which we adopted effective January 1, 2012.

This MD&A should be read with our accompanying December 31, 2012 audited comparative consolidated financial statements and notes for the same period, which have been prepared in accordance with U.S. GAAP.

---

Contents

ABOUT THIS DOCUMENT			2
ABOUT OUR BUSINESS			4
	•  Three Core Businesses		4
	•  A long-term strategy		7
	•  2012 financial highlights		8
	•  Outlook		13
	•  Non-GAAP measures		14
NATURAL GAS PIPELINES			17
OIL PIPELINES			33
ENERGY			43
CORPORATE			64
FINANCIAL CONDITION			65
OTHER INFORMATION			71
	•  Risks and risk management		71
	•  Controls and procedures		77
	•  CEO and CFO certifications		78
	•  Critical accounting policies and estimates		78
	•  Financial instruments		82
	•  Accounting changes		89
	•  Quarterly results		90
GLOSSARY			96

---

2012 Management's discussion and analysis -- 1

---

---

About this document

Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries.

Abbreviations and acronyms that are not defined in the document are defined in the glossary on page 96.

All information is as of February 11, 2013 and all amounts are in Canadian dollars, unless noted otherwise.

FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall.

Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements in this MD&A may include information about the following, among other things:

•

anticipated business prospects

•

our financial and operational performance, including the performance of our subsidiaries

•

expectations or projections about strategies and goals for growth and expansion

•

expected cash flows

•

expected costs for planned projects, including projects under construction and in development

•

expected schedules for planned projects (including anticipated construction and completion dates)

•

expected regulatory processes and outcomes

•

expected outcomes with respect to legal proceedings, including arbitration

•

expected capital expenditures and contractual obligations

•

expected operating and financial results

•

the expected impact of future commitments and contingent liabilities

•

expected industry, market and economic conditions.

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.

Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:

Assumptions

•

inflation rates, commodity prices and capacity prices

•

timing of debt issuances and hedging

•

regulatory decisions and outcomes

•

foreign exchange rates

•

interest rates

•

tax rates

•

planned and unplanned outages and the use of our pipeline and energy assets

•

integrity and reliability of our assets

•

access to capital markets

•

anticipated construction costs, schedules and completion dates

•

acquisitions and divestitures.

---

2 -- TransCanada Corporation

---

Risks and uncertainties

•

our ability to successfully implement our strategic initiatives

•

whether our strategic initiatives will yield the expected benefits

•

the operating performance of our pipeline and energy assets

•

amount of capacity sold and rates achieved in our U.S. pipelines business

•

the availability and price of energy commodities

•

the amount of capacity payments and revenues we receive from our energy business

•

regulatory decisions and outcomes

•

outcomes of legal proceedings, including arbitration

•

performance of our counterparties

•

changes in the political environment

•

changes in environmental and other laws and regulations

•

competitive factors in the pipeline and energy sectors

•

construction and completion of capital projects

•

labour, equipment and material costs

•

access to capital markets

•

cybersecurity

•

interest and foreign exchange rates

•

weather

•

technological developments

•

economic conditions in North America as well as globally.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the U.S. Securities and Exchange Commission (SEC).

You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.

FOR MORE INFORMATION
See Supplementary information beginning on page 181 for other consolidated financial information on TransCanada for the last three years.

You can also find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).

---

2012 Management's discussion and analysis -- 3

---

---

About our business

With over 60 years of 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.

THREE CORE BUSINESSES
We operate our business in three segments – Natural Gas Pipelines, Oil Pipelines and Energy. We also have a non-operational corporate segment consisting of corporate and administrative functions that provide support and governance to our operational business segments.

Our $48 billion portfolio of energy infrastructure assets meets the needs of people who rely on us to deliver their energy safely and reliably every day. We operate in seven Canadian provinces, 31 U.S. states, Mexico and three South American countries.

---

4 -- TransCanada Corporation

---

---

2012 Management's discussion and analysis -- 5

---

at December 31 (millions of $)	2012	2011	% change
Total assets
Natural Gas Pipelines	23,210	23,161	-
Oil Pipelines	10,485	9,440	11%
Energy	13,157	13,269	(1%	)
Corporate	1,481	1,468	(1%	)
Total	48,333	47,338	2%

year ended December 31 (millions of $)	2012	2011	% change
Total revenue
Natural Gas Pipelines	4,264	4,244	1%
Oil Pipelines	1,039	827	26%
Energy	2,704	2,768	(2%	)
Corporate	-	-	-
Total	8,007	7,839	2%

year ended December 31 (millions of $)	2012		2011		% change
Comparable EBIT 1
Natural Gas Pipelines	1,808		1,952		(7%	)
Oil Pipelines	553		457		21%
Energy	620		907		(32%	)
Corporate	(111	)	(100	)	(11%	)
Total	2,870		3,216		(11%	)

1

Comparable EBIT is a non-GAAP measure – see page 14 for details.

Share price of our common shares
at December 31

Common shares outstanding – average

(millions)
2012		705
2011		702
2010		691

as at February 6, 2013 Common shares	Issued and outstanding
	706 million

Preferred shares	Issued and outstanding	Convertible to
Series 1	22 million	22 million Series 2 preferred shares
Series 3	14 million	14 million Series 4 preferred shares
Series 5	14 million	14 million Series 6 preferred shares

Options to buy common shares	Outstanding	Exercisable
	7 million	4 million

---

6 -- TransCanada Corporation

---

A LONG-TERM STRATEGY
Our energy infrastructure business is made up of pipeline and power generation assets that gather, transport, produce, store or deliver natural gas, crude oil and other petroleum products and electricity to support businesses and communities in North America.

TransCanada's vision is to be the leading energy infrastructure company in North America, focusing on pipeline and power generation opportunities in regions where we have or can develop a significant competitive advantage.

Key components of our strategy

1 Maximize the full-life value of our infrastructure assets and commercial positions
	Our strategy at a glance
	•  Long-life infrastructure assets and long-term commercial arrangements are the cornerstones of our low-risk business model. •  Our 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, efficient, large-scale power generation facilities supply power markets through long-term power purchase and sale agreements and low-volatility shorter-term commercial arrangements. Our growing investment in natural gas, nuclear, wind, hydro and solar generating facilities demonstrate our commitment to clean, sustainable energy.
2 Commercially develop and build new asset investment programs
	Our strategy at a glance
	•  We are developing quality projects under our current $12 billion capital program. These will contribute incremental earnings as our investments are placed in service. •  Our expertise in managing construction risks and maximizing capital productivity ensures a disciplined approach to quality, cost and schedule, resulting in superior service for our customers and quality returns to shareholders. •  As part of our growth strategy, we rely on this expertise and our regulatory, legal and operational expertise to successfully build and integrate new energy and pipeline facilities.
3 Cultivate a focused portfolio of high quality development options
	Our strategy at a glance
	•  We focus on pipelines and energy growth initiatives in core regions of North America. •  We are assessing opportunities to acquire energy infrastructure that complements our existing pipeline network and provides access to new supply and market regions. •  We will advance selected opportunities to full development and construction when market conditions are appropriate and project risks are acceptable.
4 Maximize our competitive strengths
	Our strategy at a glance
	•  We are continually developing competitive strengths in areas that directly drive long-term shareholder value.

A competitive advantage
Years of experience in the energy infrastructure business and a disciplined approach to project and operational management and capital investment give TransCanada our competitive edge.

•  Strong leadership: scale, presence, operating capabilities, strategy development; expertise in regulatory, legal and financing support.

•  High quality portfolio: a low-risk business model that maximizes the full-life value of our long-life assets and commercial positions.

•  Disciplined operations: highly skilled in designing, building and operating energy infrastructure; focus on operational excellence; and a commitment to health, safety and the environment are paramount parts of our core values.

•  Financial expertise: excellent reputation for consistent financial performance and long-term financial stability and profitability; disciplined approach to capital investment; ability to access sizeable amounts of competitively priced capital to support our growth.

•  Long-term relationships: long-term, transparent relationships with key customers and stakeholders; clear communication of our value to equity and debt investors – both the upside and the risks – to build trust and support.

---

2012 Management's discussion and analysis -- 7

---

2012 FINANCIAL HIGHLIGHTS
We use certain financial measures that do not have a standardized meaning under U.S. GAAP because we believe they improve our ability to compare results between reporting periods, and enhance understanding of our operating performance. Known as non-GAAP measures, they may not be comparable to similar measures provided by other companies.

See page 14 for more information about the non-GAAP measures we use and a reconciliation to their GAAP equivalents.

Highlights
Comparable EBITDA (earnings before interest, taxes, depreciation and amortization), comparable EBIT (earnings before interest and taxes), comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See page 14 for more information.

year ended December 31 (millions of $, except per share amounts)			2012		2011		2010
Income
Revenue			8,007		7,839		6,852
Comparable EBITDA			4,245		4,544		3,686
Net income attributable to common shares			1,299		1,526		1,233
	per common share – basic		$1.84		$2.17		$1.79
	per common share – diluted		$1.84		$2.17		$1.78
Comparable earnings			1,330		1,559		1,357
	per common share		$1.89		$2.22		$1.97
Operating cash flow
Funds generated from operations			3,284		3,451		3,161
Decrease/(increase) in working capital			287		235		(285)
Net cash provided by operations			3,571		3,686		2,876
Investing activities
Capital expenditures			2,595		2,513		4,376
Equity investments			652		633		597
Acquisitions, net of cash acquired			214		-		-
Balance sheet
Total assets			48,333		47,338		45,249
Long-term debt			18,913		18,659		18,016
Junior subordinated notes			994		1,016		993
Preferred shares			1,224		1,224		1,224
Common shareholders' equity			15,687		15,570		15,133
Dividends
	per common share		1.76		1.68		1.60
	per Series 1 preferred share		1.15		1.15		1.15
	per Series 3 preferred share		1.00		1.00		0.80
	per Series 5 preferred share		1.10		1.10		0.65

---

8 -- TransCanada Corporation

---

Comparable earnings and net income

Comparable earnings
Comparable earnings in 2012 were $229 million lower than 2011, a decrease of $0.33 per share.

The decrease in comparable earnings was the result of:

•

lower earnings from Western Power reflecting a full year of the Sundance A PPA force majeure

•

lower equity income from Bruce Power because of increased outage days

•

recording lower Canadian Mainline net income in 2012 which excluded incentive earnings and reflected a lower investment base

•

lower earnings from Great Lakes which reflected lower revenues as a result of lower rates and uncontracted capacity

•

lower earnings from ANR because of lower transportation and storage revenues, lower incidental commodity sales and higher operating costs

•

lower earnings from U.S. Power due to lower realized prices, higher load serving costs and reduced water flows at the hydro facilities

•

higher comparable interest expense, mainly because of new debt issuances in November 2011, March 2012 and August 2012

These decreases were partially offset by:

•

a full year of revenue from Guadalajara pipeline

•

higher Keystone Pipeline System revenues primarily due to higher contracted volumes and a full year of earnings being recorded in 2012 compared to 11 months in 2011

•

incremental earnings from Cartier Wind and Coolidge

•

higher comparable interest income and other, mainly because we realized higher gains on derivatives used to manage our exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•

lower comparable income taxes due to lower pre-tax earnings.

---

2012 Management's discussion and analysis -- 9

---

2011 comparable earnings were $202 million higher than 2010, an increase of $0.26 per share and comparable EBIT was $690 million higher than 2010 resulting from:

•

higher Natural Gas Pipelines comparable EBIT increased because we placed Bison in service in January and Guadalajara in service in June 2011, general, administrative and support costs were lower, and business development spending was lower. This was partly offset by lower revenues from certain U.S. pipelines and the negative impact of a weaker U.S. dollar.

•

higher Oil Pipelines comparable EBIT as we began recording earnings from the Keystone Pipeline System in February 2011

•

higher Energy comparable EBIT because realized power prices at Western Power were higher, combined with a full year of earnings from Halton Hills and the start up of Coolidge. This was partly offset by lower contributions from Bruce B, Natural Gas Storage and U.S. Power

•

higher comparable interest expense, mainly because:

•

we placed the Keystone Pipeline System and other new assets in service, which reduced capitalized interest

•

we issued U.S. dollar-denominated debt in June and September 2010, which increased interest expense

•

partly offset by the realization of gains on derivatives used to manage our exposure to rising interest rates

•

and a weaker U.S. dollar reduced our U.S. dollar-denominated interest expense

•

lower comparable interest income and other, mainly due to reduced gains on the derivatives we used to manage our exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•

higher comparable income taxes, because pre-tax earnings were higher and higher positive income tax adjustments in 2010 compared to 2011.

Net income attributable to common shares
Net income attributable to common shares in 2012 was $1,299 million (2011 – $1,526 million; 2010 – $1,233 million).

Net income includes comparable earnings discussed above as well as other specific items which are excluded from comparable earnings. The following specific items were recognized in net income in 2010 to 2012:

•

a negative after-tax charge of $15 million ($20 million pre-tax) was included in net income following the Sundance A power purchase arrangement (PPA) arbitration decision. This charge was recorded in second quarter 2012 but related to amounts originally recorded in fourth quarter 2011

•

a negative after-tax charge of $127 million ($146 million pre-tax) was included in net income after we recorded a valuation provision against the loan to the Aboriginal Pipeline Group (APG) relating to the Mackenzie Gas Project (MGP). This charge was recorded in fourth quarter 2010.

•

the impact of certain risk management activities each year. See page 14 for explanation of specific items in Non-GAAP measures.

Cash flow

Funds generated from operations
Funds generated from operations was five per cent lower this year primarily for the same reasons comparable earnings were lower, as described above.

---

10 -- TransCanada Corporation

---

Funds used in investing

Capital expenditures
We invested $2.6 billion in capital projects this year as part of our ongoing capital program. This program is a key part of our strategy to optimize the value of our existing assets and develop new, complementary assets in high demand areas.

Capital expenditures

year ended December 31, 2012 (millions of $)
Natural Gas Pipelines		1,389
Oil Pipelines		1,145
Energy		24
Corporate		37

Equity investments and acquisitions
In 2012, we invested $0.7 billion into Bruce Power for capital projects which included the restart of Units 1 and 2 and the West Shift Plus life extension outage on Unit 3. We also spent $0.2 billion on the acquisition of the remaining 40 per cent interest in CrossAlta.

Balance sheet
We maintained a strong balance sheet while growing our total assets by over $3 billion since 2010. At December 31, 2012, common equity represented 42 per cent of our capital structure.

Dividends
We increased the quarterly dividend on our outstanding common shares by five per cent to $0.46 per share for the quarter ending March 31, 2013. This equates to an annual dividend of $1.84 per share. This is the 13th consecutive year we have increased the dividend on our common shares. Our dividend has increased at a compound average growth rate of seven per cent since 2000.

---

2012 Management's discussion and analysis -- 11

---

Dividend reinvestment plan
Under our dividend reinvestment plan (DRP), eligible holders of TransCanada common or preferred shares and preferred shares of TCPL, can reinvest their dividends and make optional cash payments to buy TransCanada common shares.

Before April 28, 2011, 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. Beginning with the dividends declared in April 2011, common shares purchased with reinvested cash dividends are satisfied with shares acquired on the open market without discount. The increase in dividends paid on common shares (see below) is, in part, the result of this change combined with the impact of an annual five per cent increase in the dividend rate between 2010 and 2012 from $1.60 to $1.76 per share.

Quarterly dividend on our common shares
$0.46 per share (for the quarter ending March 31, 2013)

Quarterly dividends on our preferred shares
Series 1 $0.2875 (for the quarter ending March 31, 2013)

Series 3 $0.25 (for the quarter ending March 31, 2013)

Series 5 $0.275 (for the three month period ending April 30, 2013)

Cash dividends year ended December 31 (millions of $)		2012		2011		2010
Common shares		1,226		961		710
Preferred shares		55		55		44

Refer to the Results section in each business segment and the Financial Condition section of this MD&A for further discussion of these highlights.

---

12 -- TransCanada Corporation

---

OUTLOOK

Earnings
We anticipate earnings in 2013 to be higher than 2012, mainly due to the following:

•

incremental earnings from Bruce A Units 1 and 2 and fewer planned outage days at Bruce A

•

higher New York capacity prices as a result of a September 2012 Federal Energy Regulatory Commission (FERC) order

•

higher earnings from the Alberta System due to a higher investment base

•

return to service of Sundance A in fall 2013

•

acquisition of several Ontario Solar assets over the course of 2013 and 2014

A favourable decision by the National Energy Board (NEB) on the Canadian Mainline Business and Services Restructuring Proposal and 2012 and 2013 Mainline Final Tolls Application (Canadian Restructuring Proposal) would have a positive impact on 2013 earnings.

These increases in earnings will be partially offset by higher operating, maintenance and administration (OM&A), general and administrative and corporate and governance costs, lower EBIT from U.S. Pipelines and higher outage days at Bruce B.

EBIT

Natural Gas Pipelines
EBIT from the Natural Gas Pipelines segment in 2013 will be affected by regulatory decisions and the timing of those decisions, including decisions about the Canadian Restructuring Proposal. Earnings will also be affected by market conditions, which drive the level of demand and rates we are able to secure for our services. Today's North American natural gas market is characterized by strong natural gas production, low natural gas prices and low values for storage and transportation services, which we expect to have a negative impact on U.S. Pipelines revenue in 2013.

Until we receive the NEB's decision with respect to the Canadian Restructuring Proposal, earnings from the Canadian Mainline will continue to 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. If the 2012 and 2013 tolls are approved as filed, earnings in 2013 will reflect a higher ROE equivalent to an ROE of 12 per cent on deemed common equity of 40 per cent for 2012 and 2013. We also expect higher earnings from the Alberta System because of continued growth in the investment base.

Oil Pipelines
We expect 2013 EBIT from the Oil Pipelines segment to be consistent with 2012 as the Gulf Coast Project, currently under construction, is expected to be placed in service at the end of 2013.

Energy
We expect 2013 EBIT from the Energy segment to be higher than 2012, mainly due to the following:

•

incremental earnings from Bruce A Units 1 and 2 and lower planned outage days at Bruce A

•

a full year of operations from the Gros-Morne Wind farm, which was placed in service in fourth quarter 2012

•

higher New York capacity prices as a result of the September 2012 FERC order affecting pricing rules for new entrants

•

the return to service of Sundance A in fall 2013

•

the acquisition of several Ontario Solar assets in 2013

•

incremental earnings from acquiring the remaining 40 per cent interest in CrossAlta in late December 2012.

We expect these increases to be partially offset by higher outage days at Bruce B and higher Bruce A and B pension and staff costs.

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 affected by fluctuations in commodity prices.

Consolidated capital expenditures, equity investments and acquisitions
We spent $3.5 billion on capital expenditures, equity investments and acquisitions in 2012 and expect to spend approximately $6.4 billion in 2013 primarily related to Keystone XL, Gulf Coast Project, Alberta System expansions, the Tamazunchale Extension project, the Topolobampo and Mazatlan pipelines in Mexico and maintenance projects on our natural gas pipelines.

---

2012 Management's discussion and analysis -- 13

---

NON-GAAP MEASURES
We use the following non-GAAP measures:

•

EBITDA

•

EBIT

•

comparable earnings

•

comparable earnings per common share

•

comparable EBITDA

•

comparable EBIT

•

comparable interest expense

•

comparable interest income and other

•

comparable income taxes

•

funds generated from operations.

These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar measures presented by other entities.

EBITDA and EBIT
We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is a better measure of our performance and an effective tool for evaluating trends in each segment. It is calculated in the same way as EBITDA, less depreciation and amortization.

Funds generated from operations
Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a better measure of our consolidated operating cashflow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period. See page 8 for a reconciliation to net cash provided by operations.

Comparable measures
We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period.

Comparable measure		Original measure
comparable earnings		net income attributable to common shares
comparable earnings per common share		net income per common share
comparable EBITDA		EBITDA
comparable EBIT		EBIT
comparable interest expense		interest expense
comparable interest income and other		interest income and other
comparable income taxes		income tax expense/(recovery)

Our decision not to include a specific item is subjective and made after careful consideration. These may include:

•

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.

We calculate comparable earnings by excluding the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.

---

14 -- TransCanada Corporation

---

Reconciliation of non-GAAP measures

year ended December 31 (millions of $, except per share amounts)			2012		2011		2010
Comparable EBITDA			4,245		4,544		3,686
Depreciation and amortization			(1,375)		(1,328)		(1,160)
Comparable EBIT			2,870		3,216		2,526
Other income statement items
Comparable interest expense			(976)		(939)		(701)
Comparable interest income and other			86		60		94
Comparable income taxes			(477)		(594)		(402)
Net income attributable to non-controlling interests			(118)		(129)		(115)
Preferred share dividends			(55)		(55)		(45)
Comparable earnings			1,330		1,559		1,357
Specific items (net of tax)
	Sundance A PPA arbitration decision		(15)		-		-
	Risk management activities1		(16)		(33)		3
	Valuation provision for MGP		-		-		(127)
Net income attributable to common shares			1,299		1,526		1,233
Comparable interest expense			(976)		(939)		(701)
Specific item:
	Risk management activities1		-		2		-
Interest expense			(976)		(937)		(701)
Comparable interest income and other			86		60		94
Specific item:
	Risk management activities1		(1)		(5)		-
Interest income and other			85		55		94
Comparable income taxes			(477)		(594)		(402)
Specific item:
	Sundance A PPA arbitration decision		5		-		-
	Risk management activities1		6		19		(4)
	Valuation provision for MGP		-		-		19
Income taxes expense			(466)		(575)		(387)
Comparable earnings per common share			$1.89		$2.22		$1.97
Specific item (net of tax):
	Sundance A PPA arbitration decision		(0.02)		-		-
	Risk management activities1		(0.03)		(0.05)		-
	Valuation provision for MGP		-		-		(0.18)
Net income per common share			$1.84		$2.17		$1.79

1

year ended December 31 (millions of $)		2012		2011		2010
Canadian Power		4		1		-
U.S. Power		(1)		(48)		2
Natural Gas Storage		(24)		(2)		5
Interest rate		-		2		-
Foreign exchange		(1)		(5)		-
Income taxes attributable to risk management activities		6		19		(4)
Total gains (losses) from risk management activities		(16)		(33)		3

---

2012 Management's discussion and analysis -- 15

---

EBITDA and EBIT by business segment

year ended December 31, 2012 (millions of $)		Natural Gas Pipelines		Oil Pipelines		Energy		Corporate		Total
Comparable EBITDA		2,741		698		903		(97)		4,245
Depreciation and amortization		(933)		(145)		(283)		(14)		(1,375)
Comparable EBIT		1,808		553		620		(111)		2,870

year ended December 31, 2011 (millions of $)
Comparable EBITDA		2,875		587		1,168		(86)		4,544
Depreciation and amortization		(923)		(130)		(261)		(14)		(1,328)
Comparable EBIT		1,952		457		907		(100)		3,216

year ended December 31, 2010 (millions of $)
Comparable EBITDA		2,816		-		969		(99)		3,686
Depreciation and amortization		(913)		-		(247)		-		(1,160)
Comparable EBIT		1,903		-		722		(99)		2,526

---

16 -- TransCanada Corporation

---

---

Natural Gas Pipelines

Our natural gas pipeline network transports natural gas to local distribution companies, power generation facitilities and other businesses across Canada, the U.S. and Mexico. We serve approximately 15 per cent of the U.S. demand and more than 80 per cent of the Canadian demand on a daily basis by connecting major natural gas supply basins and markets through:

•

wholly owned natural gas pipelines – 57,000 km (35,500 miles), and

•

partially owned natural gas pipelines – 11,500 km (7,000 miles).

We have regulated natural gas storage facilities in Michigan with a total capacity of 250 Bcf, making us one of the largest providers of natural gas storage and related services in North America.

Strategy at a glance Optimizing the value of our existing natural gas pipelines systems, while responding to the changing flow patterns of natural gas in North America, is a top priority. We are also pursuing new pipeline projects to add incremental value to our business. Our key areas of focus include greenfield development opportunities, such as infrastructure for liquefied natural gas (LNG) exports and within Mexico, as well as other opportunities that connect natural gas pipelines to emerging Canadian and U.S. shale gas and other supplies to market and play a critical role in meeting the increasing demand for natural gas in North America.

---

2012 Management's discussion and analysis -- 17

---

---

18 -- TransCanada Corporation

---

We are the operator of all of the following natural gas pipelines and storage assets except for Iroquois.

			length		description		effective ownership
	Canadian pipelines
1	Alberta System		24,337 km (15,122 miles)		Gathers and transports natural gas within Alberta and Northeastern B.C., and connects with Canadian Mainline, Foothills system and third-party pipelines		100%
2	Canadian Mainline		14,101 km (8,762 miles)		Transports natural gas from the Alberta/Saskatchewan border to the Québec/Vermont border, and connects with other natural gas pipelines in Canada and the U.S.		100%
3	Foothills		1,241 km (771 miles)		Transports natural gas from central Alberta to the U.S. border for export to the U.S. midwest, Pacific northwest, California and Nevada		100%
4	Trans Québec & Maritimes (TQM)		572 km (355 miles)		Connects with Canadian Mainline near the Ontario/Québec border to transport natural gas to the Montreal to Québec City corridor, and connects with the Portland pipeline system that serves the northeast U.S.		50%
	U.S. pipelines
	ANR
5	Pipeline		16,656 km (10,350 miles)		Transports natural gas from producing fields in Texas and Oklahoma, from offshore and onshore regions of the Gulf of Mexico and from the U.S. midcontinent, for delivery mainly to Wisconsin, Michigan, Illinois, Indiana and Ohio. Connects with Great Lakes		100%
5a	Storage		250 billion cubic feet		Provides regulated underground natural gas storage service from facilities located in Michigan
6	Bison		487 km (303 miles)		Transports natural gas from the Powder River Basin in Wyoming to Northern Border in North Dakota. We effectively own 83.3 per cent of the system through the combination of our 75 per cent direct ownership interest and our 33.3 per cent interest in TC PipeLines, LP		83.3%
7	Gas Transmission Northwest (GTN)		2,178 km (1,353 miles)		Transports natural gas from the Western Canada Sedimentary Basin (WCSB) and the Rocky Mountains to Washington, Oregon and California. Connects with Tuscarora and Foothills. We effectively own 83.3 per cent of the system through the combination of our 75 per cent direct ownership interest and our 33.3 per cent interest in TC PipeLines, LP		83.3%
8	Great Lakes		3,404 km (2,115 miles)		Connects with ANR and the Canadian Mainline near Emerson, Manitoba, to transport natural gas to eastern Canada, and the U.S. upper Midwest. We effectively own 69.0 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 33.3 per cent interest in TC PipeLines, LP		69%
9	Iroquois		666 km (414 miles)		Connects with Canadian Mainline near Waddington, New York to deliver natural gas to customers in the U.S. northeast		44.5%

---

2012 Management's discussion and analysis -- 19

---

			length		description		effective ownership
	U.S. pipelines
10	North Baja		138 km (86 miles)		Transports natural gas between Ehrenberg, Arizona and Ogilby, California, and connects with a third-party natural gas system on the California/Mexico border. We effectively own 33.3 per cent of the system through our 33.3 per cent interest in TC PipeLines, LP		33.3%
11	Northern Border		2,265 km (1,407 miles)		Transports natural gas through the U.S. Midwest, and connects with Foothills near Monchy, Saskatchewan. We effectively own 16.7 per cent of the system through our 33.3 per cent interest in TC PipeLines, LP		16.7%
12	Portland		474 km (295 miles)		Connects with TQM near East Hereford, Québec, to deliver natural gas to customers in the U.S. northeast		61.7%
13	Tuscarora		491 km (305 miles)		Transports natural gas from GTN at Malin, Oregon to Wadsworth, Nevada, and delivers gas in northeastern California and northwestern Nevada. We effectively own 33.3 per cent of the system through our 33.3 per cent interest in TC PipeLines, LP		33.3%
	Mexican pipelines
14	Guadalajara		310 km (193 miles)		Transports natural gas from Manzanillo to Guadalajara in Mexico		100%
15	Tamazunchale		130 km (81 miles)		Transports natural gas from Naranjos, Veracruz in east central Mexico to Tamazunchale, San Luis Potos, Mexico		100%
	Under construction
16	Mazatlan Pipeline		413 km (257 miles)		To deliver natural gas from El Oro to Mazatlan, Mexico. Connects to the Topolobampo Pipeline Project		100%
17	Tamazunchale Pipeline Extension		235 km (146 miles)		Extend existing terminus of the Tamazunchale Pipeline to deliver natural gas to power generating facilities in El Sauz, Queretaro, Mexico		100%
18	Topolobampo Pipeline		530 km (329 miles)		To deliver natural gas from Chihuahua to Topolobampo, Mexico		100%
	In development
19	Alaska Pipeline Project		2,737 km (1,700 miles)		To transport natural gas from Prudhoe Bay to Alberta, or from Prudhoe Bay to LNG facilities in south-central Alaska. We have an agreement with ExxonMobil to jointly advance the projects
20	Coastal GasLink		650 km* (404 miles)		To deliver natural gas from the Montney gas-producing region near Dawson Creek, B.C. to LNG Canada's proposed LNG facility near Kitimat, B.C.
21	Prince Rupert Gas Transmission Project		750 km* (466 miles)		To deliver natural gas from North Montney gas producing region near Fort St. John, B.C. to the proposed Pacific Northwest LNG facility near Prince Rupert, B.C.
*	Pipe lengths are estimates as final route is still under design

---

20 -- TransCanada Corporation

---

RESULTS

Natural Gas Pipelines results
Comparable EBITDA, comparable EBIT and EBIT are all non-GAAP measures. See page 14 for more information.

year ended December 31 (millions of $)			2012		2011		2010
Canadian Pipelines
Canadian Mainline			994		1,058		1,054
Alberta System			749		742		742
Foothills			120		127		135
Other Canadian (TQM1, Ventures LP)			29		34		33
Canadian Pipelines – comparable EBITDA			1,892		1,961		1,964
Depreciation and amortization2			(715)		(711)		(704)
Canadian Pipelines – comparable EBIT			1,177		1,250		1,260
U.S. and International (in US$)
ANR			254		306		309
GTN3			112		131		171
Great Lakes4			62		101		109
TC PipeLines, LP1,5			74		85		81
Other U.S. pipelines (Iroquois1, Bison6, Portland7)			111		111		61
International (Gas Pacifico/INNERGY1, Guadalajara8, Tamazunchale, TransGas1)			112		77		42
General, administrative and support costs9			(8)		(9)		(31)
Non-controlling interests10			161		173		144
U.S. Pipelines and International – comparable EBITDA			878		975		886
Depreciation and amortization2			(218)		(214)		(203)
U.S. Pipelines and International – comparable EBIT			660		761		683
Foreign exchange			-		(7)		22
U.S. Pipelines and International – comparable EBIT (Cdn$)			660		754		705
Business Development comparable EBITDA and EBIT			(29)		(52)		(62)
Natural Gas Pipelines – comparable EBIT			1,808		1,952		1,903
Summary
Natural Gas Pipelines – comparable EBITDA			2,741		2,875		2,816
Depreciation and amortization2			(933)		(923)		(913)
Natural Gas Pipelines – comparable EBIT			1,808		1,952		1,903
Specific items:
	Valuation provision for MGP11		-		-		(146)
Natural Gas Pipelines – EBIT			1,808		1,952		1,757

1

Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments.

2

Does not include depreciation and amortization from equity investments as these are already reflected in equity income.

3

Reflects our direct ownership interest of 75 per cent starting in May 2011 and 100 per cent prior to that date.

4

Represents our 53.6 per cent direct ownership interest. The remaining 46.4 percent is held by TC PipeLines, LP.

5

Our ownership interest in TC PipeLines, LP went from 38.2 per cent to 33.3 per cent starting in May 2011. The TC PipeLines, LP results include our effective ownership since May 2011 of 8.3 per cent of both GTN and Bison.

6

Reflects our direct ownership of 75 per cent of Bison starting in May 2011 when 25 per cent was sold to TC PipeLines, LP, and 100 per cent since January 2011 when Bison was placed in service.

7

Represents our 61.7 per cent ownership interest.

8

Included as of June 2011.

9

General, administrative and support costs associated with some of our pipelines, including $17 million for the start up of Keystone in 2010.

10

Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

11

We recorded a valuation provision of $146 million in 2010 for our advances to the APG for MGP.

---

2012 Management's discussion and analysis -- 21

---

Canadian Pipelines
Comparable EBITDA and net income for our rate-regulated Canadian Pipelines are affected by our ROE, our investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and taxes also impact comparable EBITDA but do not impact net income as they are recovered in revenue on a flow-through basis.

Net income for the Canadian Mainline this year was $59 million lower than 2011 because there was no incentive earnings mechanism in place in 2012 and the average investment base was lower as annual depreciation outpaced our capital investment. Despite higher incentive earnings, 2011 net income was $21 million lower than 2010 because ROE was higher in 2010 (8.08 per cent in 2011 compared to 8.52 per cent in 2010), and the average investment base was also lower in 2011.

Net income for the Alberta System was $8 million higher than 2011 because of a growing investment base, as new natural gas supply in northeastern B.C. and western Alberta was developed and connected to the Alberta System. This was partially offset by lower incentive earnings. Net income in 2011 was $2 million higher than 2010, mainly due to a growing investment base.

Comparable EBITDA and EBIT for the Canadian pipelines reflect the net income variances discussed above as well as variances in depreciation, financial charges and income taxes which are recovered in revenue on a flow-through basis and, therefore, do not impact net income.

Net income Year ended December 31 (millions of $)		Average investment base Year ended December 31 (millions of $)

U.S. Pipelines and International
EBITDA for our U.S. operations is affected by contracted volume levels, volumes delivered and the rates charged, as well as by the cost of providing services, including OM&A and other costs, and property taxes.

ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales. ANR's pipeline and storage volumes and revenues are generally higher in the winter months because of the seasonal nature of its business.

Comparable EBITDA for the U.S. and international pipelines was US$878 million in 2012, or US$97 million lower than 2011. This reflects the net effect of:

•

lower revenue at Great Lakes because of lower rates and uncontracted capacity

•

lower transportation and storage revenues at ANR, along with lower incidental commodity sales

•

higher OM&A and other costs at ANR

•

incremental earnings from the Guadalajara pipeline which started operations in June 2011.

---

22 -- TransCanada Corporation

---

Comparable EBITDA for U.S. and international pipelines was $975 million in 2011 which was $89 million higher than 2010. This was due to the net effect of:

•

Bison starting operations in January 2011

•

Guadalajara starting operations in June 2011

•

lower general, administrative support costs in 2011

•

lower revenues at Great Lakes and GTN in 2011.

Depreciation and amortization
Depreciation and amortization was $10 million higher in 2012 than in 2011, and was $10 million higher in 2011 than in 2010, mainly because Bison began operations in January 2011 and Guadalajara began operations in June 2011.

Business development
Business development expenses in 2012 were $23 million lower than last year because of lower expenses associated with the Alaska Pipeline Project. Expenses were $10 million lower in 2011 compared to 2010 mainly because the State of Alaska increased its business development reimbursement from 50 per cent to 90 per cent as of July 31, 2010.

OUTLOOK

Canadian Pipelines

Earnings
Earnings are affected most significantly by changes in investment base, ROE and capital structure, and also by the terms of toll settlements or other toll proposals approved by the NEB.

Until we receive the NEB's decision with respect to the Canadian Restructuring Proposal, earnings from the Canadian Mainline will continue to reflect the last approved ROE of 8.08 per cent on deemed common equity of 40 per cent, and will exclude the opportunity for incentive earnings that have enhanced Canadian Mainline's earnings in recent years as no incentive arrangement is currently in place. If the 2012 and 2013 tolls are approved as filed, earnings in 2013 will reflect a higher ROE equivalent to an ROE of 12 per cent on deemed common equity of 40 per cent for 2012 and 2013.

We expect the Alberta System's investment base to continue to grow as new natural gas supply in northeastern B.C. and western Alberta continues to be developed and is connected to it. We expect the growing investment base to have a positive impact on earnings in 2013.

We also anticipate a modest level of investment in our other Canadian rate-regulated natural gas pipelines, but expect the average investment bases of these pipelines to continue to decline as annual depreciation outpaces capital investment, reducing their year-over-year earnings.

Under the current regulatory model, earnings from Canadian rate-regulated natural gas pipelines are not affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contracted capacity levels.

U.S. Pipelines

Earnings
Earnings are affected by the level of contracted capacity and the rates charged to customers. Our ability to recontract or sell capacity at favourable rates is influenced by prevailing market conditions and competitive factors, including alternatives available to end use customers in the form of competing natural gas pipelines and supply sources, in addition to broader macroeconomic conditions that might impact demand from certain customers or market segments. Currently, the North American natural gas market is characterized by low natural gas prices and low values for storage and transportation services, which we expect to have a negative impact on U.S. Pipelines revenue in 2013.

---

2012 Management's discussion and analysis -- 23

---

Earnings are also affected by the level of OM&A and other costs, which includes the impact of safety, environmental and other regulators decisions.

Mexico Pipelines
2013 earnings are expected to be consistent with 2012 due to the nature of the long-term contracts applicable to our Mexican pipeline systems.

Capital expenditures
We spent a total of $1.4 billion in 2012 for our natural gas pipelines in Canada, the U.S. and Mexico, and expect to spend $1.9 billion in 2013 primarily on Alberta System expansion projects, the Tamazunchale Pipeline Extension, the Topolobampo and Mazatlan pipelines in Mexico, and maintenance projects on our natural gas pipelines. We fund capital expenditures through existing cash flows and access to capital markets. See page 65 for further discussion on liquidity risk.

UNDERSTANDING THE NATURAL GAS PIPELINES BUSINESS
Natural gas pipelines move natural gas from major sources of supply to locations or markets that use natural gas to meet their energy needs.

Our natural gas pipeline business builds, owns and operates a network of natural gas pipelines in North America that connects locations where gas is produced or interconnects with other pipelines connected to end customers such as local distribution companies, power generation facilities and other users. The network includes meter stations that record how much natural gas comes on the network and how much comes off at the delivery locations, compressor stations that act like pumps to move the large volumes of natural gas along the pipeline, and the pipelines themselves that transport natural gas under high pressure.

Regulation, tolls and cost recovery
We are regulated in Canada by the NEB, in the U.S. by the FERC and in Mexico by the Comisión Reguladora de Energía or Energy Regulatory Commission (CRE). The regulators approve construction of new pipeline facilities and ongoing operations of the infrastructure.

Regulators in Canada, the U.S. and Mexico allow recovery of costs to operate the network by collecting tolls, or payments, for services. These costs include OM&A costs, income and property taxes, interest on debt, depreciation expense to recover invested capital, and a return on the capital invested. The regulator reviews our costs to ensure they are prudent, and approves the tolls based on recovering these costs.

Within their respective jurisdictions, the FERC and CRE approve maximum transportation rates. These rates are cost based and are designed to recover the pipeline's investment, operating expenses and a reasonable return for investors. The pipeline may negotiate these rates with shippers.

Sometimes we and our shippers enter into agreements, or settlements, for tolls and cost recovery, which may include mutually beneficial performance incentives. The regulator must approve a settlement for it to be put into effect.

Generally, the Canadian natural gas pipelines request the NEB to approve the pipeline's cost of service and tolls once a year, and recover the variance between actual and expected revenues and costs in future years. The FERC does not require U.S. interstate pipelines to calculate rates annually, nor do they allow for the collection of the variance between actual and expected revenue and costs into future years. This difference in U.S. regulation puts our U.S. pipelines at risk for the difference in expected and actual costs and revenues between rate cases. If revenues no longer provide a reasonable opportunity to recover costs, we can file with the FERC for a new determination of rates, subject to any moratorium in effect. Similarly, the FERC may institute proceedings to lower tolls if they consider returns to be too high. Our Mexico pipelines are also regulated and have approved tariffs, services and related rates. However, the contracts underpinning the facilities in Mexico are long-term negotiated rate contracts and not subject to further regulatory approval.

---

24 -- TransCanada Corporation

---

Business environment and strategic priorities
In this section, we discuss the environment in which we conduct our natural gas pipelines business, including our strategic priorities for our natural gas pipelines business.

The North American natural gas pipeline network has been developed to connect supply to market. Use and growth of this infrastructure is affected by changes in the location and relative cost of natural gas supplies and changing demand.

We have a significant pipeline footprint in the WCSB and transport approximately 70 per cent of its production to markets within and outside of Alberta. Our pipelines also source natural gas, to a less significant degree, from the other major basins including the Appalachian, Rockies, Williston, Haynesville, Fayetteville, and Gulf of Mexico.

Increasing supply
The WCSB spans almost all of Alberta and extends into B.C., Saskatchewan, Yukon and Northwest Territories and is Canada's primary source of natural gas. The WCSB is currently estimated to have 125 trillion cubic feet of remaining conventional resources and a technically accessible unconventional resource base of almost 200 trillion cubic feet. The total WCSB resource base has more than doubled in the recent past with the advent of technology that can economically access unconventional gas plays in the basin. We expect production from the WCSB to decrease slightly in 2013 and then grow over the next decade.

The Montney and Horn River shale play formations in northeastern B.C. are also part of the WCSB and have recently become a significant source of natural gas. We expect production from these sources, currently 1.5 Bcf/d, to grow to approximately 5 Bcf/d by 2020, depending on natural gas prices and the economics of exploration and production.

---

2012 Management's discussion and analysis -- 25

---

The primary sources of natural gas in the U.S. are the U.S. shale plays, Gulf of Mexico and the Rockies. The U.S. shales are the biggest area of growth which we estimate will meet almost 50 per cent of the overall North American gas supply by 2020. Of the shale plays in the U.S, the Marcellus, Haynesville, Barnett, Eagle Ford and Fayetteville shale plays are the major supply sources.

The supply of natural gas in North America is forecast to increase significantly over the next decade (by approximately 15 Bcf/d by 2020), and is expected to continue to increase over the long term for several reasons:

•

New technology, such as horizontal drilling in combination with multi-stage hydraulic fracturing or fracking, is allowing companies to access unconventional resources economically. This is increasing the technically accessible resource base of existing basins and opening up new producing regions, such as the Marcellus and Utica shale in the U.S. northeast, and the Montney and Horn River shale areas in northeastern B.C.

•

These new technologies are also being applied to existing oil fields where further recovery of the resource is now possible. High oil prices, particularly compared to North American natural gas prices, has resulted in an increase in exploration and production of liquid-rich hydrocarbon basins. There is often associated gas in these plays (for example, the Bakken oil fields) which increases the overall gas supply for North America.

The development of shale gas basins that are located close to traditional existing markets, particularly in the U.S., has led to an increase in the number of supply choices and is changing traditional gas pipeline flow patterns. On some of our pipelines, such as the Canadian Mainline, ANR, and Great Lakes, there has been a reduction in long-haul, long-term firm contracted capacity and a shift to shorter-distance, shorter-term contracts.

While the increase in supply, particularly in northeastern B.C., has created opportunities for us to build new pipeline infrastructure to move the natural gas to markets, the development of alternative supply sources in the U.S., and particularly in the U.S. northeast, has caused pipelines that have traditionally served markets in this area (including ours), to reconfigure their flow patterns from continental routes to more regional ones.

Changing demand
The growing supply of natural gas has resulted in relatively low natural gas prices in North America, which have supported increasing demand and is expected to continue. Examples include:

•

the use of natural gas in the development of the Alberta oil sands

•

increased natural gas-fired power generation driven by conversion from coal

•

industrial growth in both Canada and the U.S.

•

increased exports to Mexico to fuel new power generation facilities

•

increased use of natural gas used in petrochemical and industrial facilities in both Canada and the U.S.

Natural gas producers are also looking to sell natural gas to global markets, which would involve connecting natural gas supplies to new LNG export terminals proposed primarily along the west coast of B.C., and on the U.S. Gulf of Mexico coast. Assuming the receipt of all necessary regulatory and other approvals, these facilities are expected to become operational in the second half of this decade. The addition of these new markets creates opportunities for us to build new pipeline infrastructure and to increase throughput on our existing pipelines.

More competition
Changes in supply and demand have resulted in growing pipeline infrastructure and increased competition for transportation services throughout North America. More pipeline capacity was added to the continental pipeline network between 2008 and 2011 than in any comparable time period in industry history, and gas supply areas that were once constrained, like the U.S. Rockies and east Texas, now have several paths to reach markets.

Strategic priorities
We are focused on capturing opportunities resulting from growing natural gas supply, as well as opportunities to connect new markets, while satisfying increasing demand for natural gas within existing markets.

---

26 -- TransCanada Corporation

---

We are also focused on adapting our existing assets to the changing gas flow dynamics.

The Canadian Mainline has traditionally sourced its natural gas primarily from the WCSB and delivered it to eastern markets. New supply located closer to the eastern markets has reduced demand for gas from the WCSB that, in turn, has reduced revenues from long haul transportation. As a result, overall tolls on the Mainline have increased and caused a reduction in the Canadian Mainline's competitive position. We are looking for opportunities to increase its market share in Canadian domestic markets, however, we expect to continue to face competition for both the eastern Canada and U.S. northeast markets. Our current application with the NEB seeks to restructure tolls on the Canadian Mainline to correspond with pipeline flow and usage patterns resulting from new supply and demand dynamics. The hearing on our application concluded in December 2012 and a decision is expected in late first quarter or early second quarter of 2013.

The Alberta System is the major natural gas gathering and transportation system for the WCSB, connecting most of the natural gas production in Western Canada to domestic and export markets. It faces competition for connection to supply, particularly in northeastern B.C., where the largest new source of natural gas has access to two existing competing pipelines. Connections to new supply and new or growing demand supports new capital expansions of the Alberta System. We expect supply in the WCSB to grow from its current level of approximately 14 Bcf/d to approximately 17 Bcf/d by 2020. The WCSB has an enormous remaining supply potential, but how much is produced, and how quickly, will be influenced by many factors, including transportation costs, the extent of the demand and local market price and basin-on-basin price differentials.

ANR has a very broad geographical footprint, with diverse market and supply access that includes 250 Bcf of natural gas storage, which is a major driver of ANR's revenues. ANR's supply of natural gas comes from many sources including the Gulf of Mexico, Mid-Continent, Rockies, Marcellus/Utica and the WCSB. Demand served by this pipeline includes markets in Michigan, Wisconsin, Illinois, Indiana and Ohio. Many of ANR's supply and market regions are also served by competing interstate and intrastate natural gas pipelines.

ANR has demonstrated its adaptability to changing market dynamics by identifying opportunities and investing in its system to accommodate the market's demands for services that are counter to traditional flow patterns. This has resulted in increased bi-directional flows and shorter haul services in some of its supply and market areas. Although the unseasonably warm winter weather and lack of storage demand negatively impacted ANR in 2012, we expect an increased demand for pipeline transportation broadly in the U.S. resulting in a positive impact to ANR because of the following factors:

•

a return to average weather conditions

•

the increase in gas-fired power generation due to coal switching to gas and coal plant retirements

•

LNG exports from the Gulf of Mexico and growth in the industrial sector such as petrochemicals.

GTN is supplied with natural gas from the WCSB and the Rockies. It 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. GTN has significant long term contracts and is currently operating under a rate settlement which started in January 2012 and expires at the end of December 2015. As a result, GTN's revenues are subject to variation primarily as a result of capacity sold above its current contracted amount.

Great Lakes competes for natural gas transportation customers with pipelines that transport gas from the WCSB and natural gas sourced in the U.S. Great Lakes has experienced significant non-renewals of its long haul capacity in the past few years and its contracts are for shorter terms than in the past. Great Lakes revenues were also negatively impacted in 2012 by a warm winter and historically high storage levels that decreased its throughput. Demand for Great Lakes capacity changes with seasonal market conditions and we expect a return to average winter weather will increase throughput due to storage demand. Great Lakes is required to file a rate case no later than November 1, 2013, and this provides the opportunity for rate and tariff changes in response to current market conditions.

---

2012 Management's discussion and analysis -- 27

---

We are continually assessing our existing natural gas pipelines assets, and have reviewed the possibility of converting existing infrastructure from gas service to crude oil. We received NEB approval in 2007 to convert one of our Canadian Mainline gas pipelines to crude oil service for the original Keystone project. We have determined that a further conversion of portions of the Canadian Mainline from natural gas to crude oil to serve eastern markets is both technically and economically feasible. The oil pipeline group is assessing the commercial interest in such a conversion.

We are also focused on capturing new opportunities resulting from the changing supply and demand dynamics. In 2012, we undertook the following new projects:

•

we completed and placed in service approximately $650 million in pipeline projects to expand the Alberta System.

•

we reached an agreement with Shell to build and operate the proposed $4 billion Coastal GasLink pipeline to move WCSB gas to Shell Canada Limited's proposed west coast LNG project near Kitimat, B.C.

•

we were awarded $1.9 billion for new pipeline infrastructure projects to meet the growing demand for natural gas in Mexico

•

we proposed a $1.0 billion to $1.5 billion expansion to the Alberta System in northeast B.C. to connect to both the Prince Rupert Gas Transmission Project and to additional North Montney supplies.

In January 2013, we were selected by Progress Energy Canada Ltd, to design, build, own and operate the proposed $5 billion Prince Rupert Gas Transmission Project that will transport natural gas from northeastern B.C. to the proposed Pacific Northwest LNG export facility near Prince Rupert, B.C.

SIGNIFICANT EVENTS

Canadian Pipelines

Alberta System
This year we completed and placed in service approximately $650 million in pipeline projects to expand the Alberta System. This included completing the Horn River project in May, which extended the Alberta System into the Horn River shale play in B.C.

In 2012, the NEB approved approximately $640 million in additional expansions, including the Leismer-Kettle River Crossover project, a 30-inch, 77 km (46 mile) pipeline. This project will cost an estimated $160 million and is intended to increase capacity to meet demand in northeastern Alberta. As of December 31, approximately $330 million in additional projects were awaiting approval, including the $100 million Chinchaga Expansion and the $230 million Komie North project that would extend the Alberta System further into the Horn River area. On January 30, 2013, the NEB issued its recommendation to the Governor-in-Council that the proposed Chinchaga Expansion component of that project be approved, but denied the proposed Komie North Extension component. All applications awaiting approval as of the end of 2012 have now been addressed.

Canadian Mainline
An NEB hearing began in June 2012 to address our application to change the business structure and the terms and conditions of service for the Canadian Mainline, including tolls for 2012 and 2013. The hearing concluded in December 2012 and a decision is not expected until late first quarter or early second quarter 2013.

We received NEB approval in May to build new pipeline facilities to provide Southern Ontario with additional natural gas supply from the Marcellus shale basin. Supply began moving on November 1, 2012.

---

28 -- TransCanada Corporation

---

In response to requests to bring additional Marcellus shale gas into Canada, we held an additional open season for firm transportation service on the Canadian Mainline that ended in May 2012. We were able to accommodate an additional 50 MMcf/d from the Niagara meter station to Kirkwall effective November 1, 2012 with the potential for an additional 350 MMcf/d of incremental volumes for November 1, 2015 subject to finalizing precedent agreements with the interested parties.

Projects

Coastal GasLink
We were selected in June by Shell and its partners to design, build, own and operate the proposed Coastal GasLink project. The estimated $4 billion pipeline will transport natural gas from the Montney gas-producing region near Dawson Creek, B.C. to LNG Canada's recently announced LNG export facility near Kitimat, B.C. The LNG Canada project is a joint venture led by Shell, with partners Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited. The approximate 650 km (404 mile) pipeline is expected to have an initial capacity of more than 1.7 Bcf/d and be placed in service toward the end of the decade, subject to a final investment decision to be made by LNG Canada subsequent to obtaining final regulatory approvals.

Prince Rupert Gas Transmission Project
We have been selected by Progress Energy Canada Ltd (Progress), to design, build, own and operate the proposed $5 billion Prince Rupert Gas Transmission Project. This proposed pipeline will transport natural gas primarily from the North Montney gas-producing region near Fort St John, B.C., to the proposed Pacific Northwest LNG export facility near Prince Rupert, B.C. We expect to finalize definitive agreements with Progress in early 2013 leading to an in-service date in late 2018. A final investment decision to construct the project is expected to be made by Progress following final regulatory approvals.

Alberta System expansion projects
We continue to advance pipeline development projects in B.C. and Alberta to transport new natural gas supply. We have filed applications with the NEB to expand the Alberta System to accommodate requests for additional natural gas transmission service throughout the northwest and northeast portions of the WCSB. In addition, we propose to further extend the Alberta System in northeast B.C. to connect both to the Prince Rupert Gas Transmission Project and to additional North Montney gas supplies. This new infrastructure will allow the Pacific Northwest LNG export facility, located on the west coast of B.C., to access both the North Montney supplies as well as other WCSB gas supply. Initial capital cost estimates are approximately $1 billion to $1.5 billion, with an initial in-service date targeted for the end of 2015. We have incremental firm commitments to transport approximately 3.4 Bcf/d from western Alberta and northeastern B.C. by 2015.

Tamazunchale Pipeline Extension Project
In February 2012, we signed a contract with Mexico's Comisión Federal de Electricidad (CFE) for the approximately $500 million Tamazunchale Pipeline Extension Project. The project, which is supported by a 25-year contract with CFE, is a 235 km (146 mile) 30 inch pipeline with a capacity of 630 MMcf/d. Engineering, procurement and construction contracts have all been signed and construction related activities have begun. We expect the pipeline to be in service in the first quarter of 2014.

Topolobampo Pipeline Project
In November, CFE also awarded us the Topolobampo pipeline, from Chihuahua to Topolobampo, Mexico. The project, which is supported by a 25 year contract with CFE, is a 530 km (329 mile) 30 inch pipeline with a capacity of 670 MMcf/d. We estimate total costs to be US$1 billion, and expect it to be in service in mid-2016.

Mazatlan Pipeline Project
In November, CFE also awarded us the Mazatlan pipeline, from El Oro to Mazatlan, Mexico. The project, which is also supported by a 25 year contract with CFE and interconnects with the Topolobampo project, is a 413 km (257 mile) 24 inch pipeline with a capacity of 200 MMcf/d. We estimate total costs to be US$400 million, and expect it to be in service in fourth quarter 2016.

---

2012 Management's discussion and analysis -- 29

---

Alaska Pipeline Project
We and the Alaska North Slope producers have agreed on a work plan to evaluate options to commercialize North Slope natural gas resources through an LNG option. We received approval in May from the State of Alaska to suspend and preserve our activities on the Alaska/Alberta route and focus on the LNG alternative, which allowed us to defer our obligation to file for a FERC certificate for the Alberta route beyond fall 2012 (our original deadline). In September 2012, we solicited interest in a natural gas pipeline as part of the LNG option and there were a number of non-binding expressions of interest from potential shippers from a broad range of industry sectors in North America and Asia.

Regulatory filings

Canadian Pipelines
We filed a comprehensive restructuring proposal with the NEB in September 2011 for the Canadian Mainline. The proposal is intended to enhance the competitiveness of the Canadian Mainline and transportation from the WCSB, and includes a request for 2012 and 2013 tolls that align with the proposed changes to our business structure and the terms and conditions of service on the Canadian Mainline.

The NEB established interim tolls for 2012 based on the approved 2011 final tolls. We do not expect a decision on the Canadian Restructuring Proposal until late first quarter or early second quarter  2013.

The current settlements for the Alberta and Foothills systems expired at the end of 2012. Final tolls for 2013 will be determined through either new settlements or rate cases and any orders resulting from the NEB's decision on the Canadian Restructuring Proposal.

U.S. Pipelines
ANR Pipeline Company rates were established at the beginning of 1997. ANR can, but is not required to, file for new rates. The FERC issued orders in 2012 approving ANR's sale of its offshore assets to a newly created wholly owned subsidiary, TC Offshore LLC, allowing TC Offshore LLC to operate these assets as a stand-alone interstate pipeline. TC Offshore LLC began commercial operations on November 1, 2012. ANR Storage Company secured a settlement with its shippers that the FERC approved on August 20, 2012. ANR Storage Company owns 56 Bcf of the total ANR storage capacity.

GTN has a FERC-approved settlement agreement for transportation rates that is effective from January 2012 to the end of December 2015. The GTN settlement includes a moratorium on the filing of future rate proceedings until December 2015. GTN is required to file for new rates to go into effect January 1, 2016.

Northern Border secured a final settlement agreement with its shippers that the FERC approved with an effective date of January 1, 2013. The settlement rates for long-haul transportation are approximately 11 per cent lower than 2012 rates and depreciation was lowered from 2.4 to 2.2 per cent. The settlement also includes a three-year moratorium on filing cases or challenging the settlement rates but Northern Border must initiate another rate proceeding within five years.

Great Lakes has a FERC-approved settlement agreement in place. It can file for new rates at any time, but must file no later than November 1, 2013.

BUSINESS RISKS
The following are risks specific to our natural gas pipelines business. See page 71 for information about general risks that affect the company as a whole.

WCSB supply for downstream connecting pipelines
Although we have diversified our sources of natural gas supply, many of our North American natural gas pipelines and transmission infrastructure assets depend on supply from the WCSB. There is competition for this supply from several downstream pipelines, demand within Alberta, and in the future, demand for proposed pipelines for LNG exports from the west coast of B.C. The WCSB has considerable reserves, but how

---

30 -- TransCanada Corporation

---

much of it is actually produced will depend on many variables, including the price of gas, basin-on-basin competition, downstream pipeline tolls, demand within Alberta and the overall value of the reserves, including liquids content.

Market access to other supply
We compete for market share with other natural gas pipelines. New supply areas being developed closer to traditional markets have reduced the competitiveness of our long haul pipelines, and may continue to do so. The long-term competitiveness of our pipeline systems will depend on our ability to adapt to changing flow patterns by offering alternative transportation services at prices that are acceptable to the market.

Competition
We face competition from other pipeline companies seeking to connect similar supply and/or access to market. Most, if not all, long haul natural gas pipelines in North America are affected by the fundamental changes in flow dynamics resulting from new shale supply developments. The future success of new projects, such as connecting pipelines to LNG export facilities or development of Mexico gas pipeline infrastructure, is anticipated to be highly competitive.

Demand for pipeline capacity
Demand for a pipeline's capacity is ultimately the key driver that enables transportation services to be sold. Demand 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 the utilization of existing assets. For example, the proposed LNG 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. Our natural gas pipelines may be challenged to sell available transportation capacity as transportation contracts expire on our existing pipeline assets, as they have, for example, on the Great Lakes system. We expect our 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.

Several factors influence demand for pipeline capacity:

•

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 which in turn diminishes production levels, particularly in dry gas fields where the extra revenue generated from the entrained liquids is not available.

•

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. Basin-on-basin competition impacts the extent and timing of a resource play's development, which in turn drives changes in demand for pipeline capacity.

•

there is growing regulatory and public scrutiny over the environmental impacts of fracking. Changes in regulations that apply to fracking could impact the costs and pace of development of natural gas plays.

•

growing pipeline infrastructure, changes in supply sources, and unutilized capacity on many pipelines have led to a 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.

---

2012 Management's discussion and analysis -- 31

---

Regulatory risk
Decisions by regulators can have an impact on the approval, construction, operation and financial performance of our natural gas pipelines. We manage these risks through rate and facility applications and negotiated settlements, where possible. Public opinion about natural gas pipeline development can also have an impact on the regulatory approval process for new gas pipeline assets. We continuously monitor regulatory developments and decisions to determine the possible impact on our gas pipelines business and work closely with our stakeholders in the development of the assets.

Operational
Keeping our pipelines operating is essential to the success of our business. Interruptions in our pipeline operations impact our throughput capacity and may result in reduced revenue. We manage this by investing in a highly skilled workforce, operating prudently, using risk-based preventive maintenance programs and making effective capital investments. We use internal inspection equipment to check our pipelines regularly, and repair or replace them whenever necessary. We also calibrate the meters regularly to ensure accuracy, and continuously maintain compression equipment to ensure safe and reliable operation.

---

32 -- TransCanada Corporation

---

---

Oil Pipelines

TransCanada's Keystone Pipeline System connects Alberta crude oil supplies to significant U.S. refining markets in Illinois and Oklahoma. The system has a nominal design capacity of 591,000 Bbl/d and is 3,467 km (2,154 miles) long.

Our plan for Keystone XL creates an opportunity for us to transport growing North American crude oil supplies to market. Keystone XL will increase the total capacity of the Keystone Pipeline System to approximately 1.4 million Bbl/d and we have secured long-term, firm contracts in excess of 1.1 million Bbl/d.

The current construction of the Gulf Coast Project will connect the crude oil hub at Cushing, Oklahoma to the U.S. Gulf Coast with an initial capacity of up to 700,000 Bbl/d.

We recently announced the Grand Rapids Pipeline and Northern Courier Pipeline and our expansion of the Keystone Hardisty Terminal. These projects are giving us a competitive position in the growing intra-Alberta crude oil transportation market.

Strategy at a glance
	With the increasing production of crude oil in Alberta, new crude oil discoveries in the U.S. and the growing demand for secure, reliable sources of energy, developing new crude oil pipeline capacity is essential.
	We continue to focus on contracting and delivering growing North American crude oil supply to key U.S. markets, and are planning to expand our oil pipeline infrastructure by:
	•  building a new crude oil pipeline from Cushing, Oklahoma to the U.S. Gulf Coast (the Gulf Coast Project)
	•  adding batch accumulation and pipeline infrastructure at Hardisty, Alberta (Keystone Hardisty Terminal)
	•  building a new crude oil pipeline from Hardisty, Alberta to Steele City, Nebraska (Keystone XL)
	•  building the Grand Rapids Pipeline to transport crude oil and diluent between the producing area in northern Alberta and the Edmonton/Heartland region and
	•  building the Northern Courier Pipeline to transport bitumen and diluent between the Fort Hills mine site and proposed Voyageur Upgrader, north of Fort McMurray, Alberta.
	Our proposed conversion of a portion of the Canadian Mainline from natural gas to crude oil service would connect the eastern Canadian refining market to our oil pipeline infrastructure (Canadian Mainline conversion) and also gives us additional opportunities to expand our oil pipelines business.

---

2012 Management's discussion and analysis -- 33

---

---

34 -- TransCanada Corporation

---

We are the operator of all of the following pipelines and properties.

			length		description		ownership
	Oil pipelines
22	Keystone Pipeline System		3,467 km (2,154 miles)		Transports crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma		100%
	Under construction
23	Cushing Marketlink		Crude oil receipt facilities		To transport crude oil from the Permian Basin producing region in western Texas to the U.S. Gulf Coast refining market on facilities that form part of the Gulf Coast Project		100%
24	Gulf Coast Project		780 km (485 miles)		To transport crude oil from the hub at Cushing, Oklahoma to the U.S. Gulf Coast refinery market. Includes the 76 km (47 mile) Houston Lateral pipeline		100%
25	Keystone Hardisty Terminal		Crude oil terminal		Crude oil terminal to be located at Hardisty, Alberta, providing Western Canadian producers with new crude oil batch accumulation tankage and pipeline infrastructure and access to the Keystone Pipeline System		100%
	In development
26	Bakken Marketlink		Crude oil receipt facilities		To transport crude oil from the Williston Basin producing region in North Dakota and Montana to Cushing, Oklahoma on facilities that form part of Keystone XL		100%
*	Canadian Mainline Conversion				Conversion of a portion of the Canadian Mainline natural gas pipeline system to crude oil service, which will transport crude oil between Hardisty, Alberta and markets in eastern Canada		100%
27	Grand Rapids Pipeline		500 km (300 miles)		To transport crude oil between the producing area northwest of Fort McMurray and the Edmonton/Heartland market region. Project is a partnership with Phoenix Energy Holdings Limited (Phoenix)		50%
28	Keystone XL		1,897 km (1,179 miles)		Pipeline from Hardisty, Alberta to Steele City, Nebraska to expand capacity of the Keystone Pipeline System to 1.4 million Bbl/d. Awaiting U.S. Presidential Permit decision		100%
29	Northern Courier Pipeline		90 km (56 miles)		To transport bitumen and diluent between the Fort Hills mine site and the Voyageur Upgrader located north of Fort McMurray, Alberta.		100%

*

Not shown on map

---

2012 Management's discussion and analysis -- 35

---

RESULTS
Comparable EBITDA, comparable EBIT and EBIT are all non-GAAP measures. See page 14 for more information.

year ended December 31 (millions of $)		2012		20111
Keystone Pipeline System		712		589
Oil Pipeline Business Development		(14)		(2)
Oil Pipelines – comparable EBITDA		698		587
Depreciation and amortization		(145)		(130)
Oil Pipelines – comparable EBIT		553		457
Comparable EBIT denominated as follows
Canadian dollars		191		159
U.S. dollars		363		301
Foreign exchange		(1)		(3)
Oil Pipelines – comparable EBIT		553		457

1

Results in 2011 are for 11 months.

Comparable EBITDA
Comparable EBITDA for the Keystone Pipeline System was $123 million higher this year than in 2011. This increase reflected higher revenues primarily resulting from:

•

higher contracted volumes

•

the impact of higher final fixed tolls on committed pipeline capacity to Wood River and Patoka, in Illinois, which came into effect in May 2011

•

the impact of higher final fixed tolls on committed pipeline capacity to Cushing, Oklahoma, which came into effect in July 2012

•

twelve months of earnings being recorded in 2012 compared to eleven months in 2011.

The Keystone Pipeline System began commercial operations in June 2010, when we began delivering crude oil to Wood River and Patoka in Illinois. We capitalized all cash flows except general, administrative and support costs until February 2011. The NEB initially restricted the operating pressure on the Canadian conversion segment of the pipeline. As a result, we could not operate it at design pressure and throughput capacity was much lower than the initial nominal capacity of 435,000 Bbl/d. The NEB removed the restriction in December 2010 and we made operational modifications in late January 2011 which allowed us to operate at higher pressure and increase throughput capacity.

We began recording EBITDA for the Keystone Pipeline System in February 2011, when we began delivering crude oil to Cushing, Oklahoma.

---

36 -- TransCanada Corporation

---

Business development
Business development expenses this year were $12 million higher than 2011 mainly because of increased business development activity on various development projects.

Depreciation and amortization
Depreciation and amortization was $15 million higher this year than in 2011 because 12 months of depreciation was recorded in 2012 compared to 11 months in 2011.

OUTLOOK

Earnings
We expect 2013 earnings to be consistent with 2012. Earnings are expected to increase over time as projects currently in development are placed in service.

Capital expenditures
We spent a total of $1.1 billion in 2012, and expect to spend $4.1 billion in 2013, mainly related to Keystone XL and the Gulf Coast Project. We fund capital expenditures through existing cash flows and access to capital markets. See page 65 for further discussion on liquidity risk.

UNDERSTANDING THE OIL PIPELINES BUSINESS
Oil pipelines move crude oil from major sources of supply to refinery markets so the crude oil can be refined into various petroleum products.

Our Keystone Pipeline System connects Alberta crude oil supplies to significant U.S. refining markets in Illinois and Oklahoma. It generates earnings mainly by providing pipeline capacity to shippers on a take-or-pay basis in exchange for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and, when capacity is available, provides opportunities to generate incremental earnings.

The terms of service and fixed monthly payments are determined by long-term transportation service arrangements negotiated with shippers. These arrangements average 18 years, and provide for the recovery of costs we incur to operate the system.

---

2012 Management's discussion and analysis -- 37

---

Business environment
Increasing crude oil supply production in Canada and the U.S. has increased the demand for new crude oil pipeline infrastructure and, as a result, we are pursuing opportunities to connect growing North American crude oil supplies to key markets.

Alberta produces the majority of the crude oil in the WCSB which is the primary source of crude oil supply for the Keystone Pipeline System.

In 2011, the WCSB produced an estimated 1.1 million Bbl/d of conventional crude oil and condensate, and 1.6 million Bbl/d of Alberta oil sands crude oil – a total of approximately 2.7 million Bbl/d. The production of conventional crude oil in western Canada grew for the first time after years of decline.

In its 2012 report, the Alberta Energy Resources Conservation Board estimates there are approximately 170 billion barrels of remaining established conventional and oil sands reserves in Alberta. In June 2012, the Canadian Association of Petroleum Producers forecasted WCSB crude oil supply would increase to 3.6 million Bbl/d by 2015 and to 4.5 million Bbl/d by 2020. Its 2012 forecast for western Canadian production of conventional and unconventional crude oil in 2025 is 885,000 Bbl/d higher than its forecast in 2011.

Oil sands production
Despite increases in production from conventional sources, and new shale oil production (including the Bakken and Cardium formations), the oil sands will continue to make up most of the crude oil production from the WCSB. The Alberta Energy Resources Conservation Board's 2012 report estimates that oil sands capital expenditures increased $2.7 billion in 2011, to $19.9 billion, and predicts that investment will be $21.5 billion in 2012 and $24.7 billion in 2015.

Oil sands projects have very long lives: conservative estimates are 40 years for mining sites and 25 years for in-situ production, and some estimates are considerably higher. That means producers need to secure

---

38 -- TransCanada Corporation

---

long-term connectivity to market. The Keystone Pipeline System, including Keystone XL, provides producers with needed pipeline capacity and is largely contracted for an average term of 18 years.

Demand for infrastructure within Alberta
Growth in oil sands production is also driving the need for new intra-Alberta pipelines, like our Grand Rapids Pipeline, that can move crude oil production from the source to market hubs at Edmonton/Heartland and Hardisty, where they can connect with the Keystone Pipeline System, and other pipelines that transport crude oil outside of Alberta, and move diluent from the Edmonton/Heartland region to the producing area in northern Alberta.

Growth in U.S. production
According to the International Energy Agency (IEA) World Energy Outlook report, the U.S. is set to overtake Saudi Arabia as the world's largest oil producer. The IEA projects approximately three million Bbl/d of U.S. shale oil production growth, peaking in approximately 2020 and starting to decline by around 2025.

The Williston Basin, located mainly in North Dakota and Montana, produced more than 600,000 Bbl/d in 2012, and production levels are expected to reach approximately one million Bbl/d by 2014 because of rapid growth in Bakken shale oil production. The Williston Basin is the primary source of crude oil supply for the Bakken Marketlink project.

According to BENTEK Energy, the Permian Basin, located mainly in western Texas, currently produces 1.3 million Bbl/d and will reach 1.8 million Bbl/d by the end of 2016. The Permian Basin is the primary source of crude oil for the Cushing Marketlink project.

Growing U.S. production has contributed to increased crude oil supply at the Cushing, Oklahoma market hub and resulted in increased demand for additional pipeline capacity between Cushing and the U.S. Gulf Coast refining market. Our Gulf Coast Project will provide needed pipeline capacity to transport growing crude oil supply at Cushing to the U.S. Gulf Coast.

Even with growth in U.S. crude oil production, the IEA report predicts the U.S. will remain a net importer of crude oil, importing 3.4 million Bbl/d into 2035. Growing production in the west Texas Permian and south Texas Eagle Ford basins, which is primarily light crude oil, is expected to compete with Williston Basin light crude oil production volumes but generally will not compete with Canadian volumes. Gulf Coast refiners will continue to prefer Canadian heavy oil because their refineries are mainly set up to run heavy crude oil and cannot easily switch to running the new light shale oil in large quantities.

Refineries in eastern Canada currently import light crude oil from west Africa and the Middle East, so are better able to handle light shale oil. Many of these refineries have recently begun transporting domestic light crude oil in small quantities by rail, at a cost typically higher than the cost to ship by pipeline. This has created a significant demand for pipelines to connect eastern Canada with growing Bakken and WCSB light crude oil production. We are positioned to meet this need by potentially converting portions of our Canadian Mainline natural gas pipeline system between Alberta and eastern Canada.

SIGNIFICANT EVENTS

Tolls
We filed revised fixed tolls with the NEB and the FERC this year for committed pipeline capacity to Cushing, Oklahoma. The new tolls went into effect on July 1, 2012, and represent the final project costs of the Keystone Pipeline System.

Gulf Coast Project
We announced in February 2012 that what had previously been the Cushing to U.S. Gulf Coast portion of the Keystone XL Pipeline has its own independent value to the marketplace, and that we plan to build it as the stand-alone Gulf Coast Project, which is not part of the Keystone XL Presidential Permit process.

---

2012 Management's discussion and analysis -- 39

---

The 36-inch pipeline will extend from Cushing, Oklahoma to the U.S. Gulf Coast. We expect it to have an initial capacity of up to 700,000 Bbl/d, and an ultimate capacity of 830,000 Bbl/d. We estimate the total cost of the project to be US$2.3 billion, and as of December 31, 2012, construction was approximately 35 per cent complete. US$300 million of the total cost is expected to be spent on the Houston Lateral pipeline, a 76 km (47 mile) pipeline that will transport crude oil to Houston refineries.

Construction began in August 2012 and we expect to place the pipeline in service at the end of 2013.

Keystone XL Pipeline
In May 2012, we filed a Presidential Permit application (cross-border permit) with the U.S. Department of State (DOS) for Keystone XL to transport crude oil from the U.S./Canada border in Montana to Steele City, Nebraska. We continued to work collaboratively with the Nebraska Department of Environmental Quality (NDEQ) and various other stakeholders throughout 2012 to determine an alternative route in Nebraska that would avoid the Nebraska Sandhills. We had proposed an alternative route to the NDEQ in April 2012, and then modified the route in response to comments from the NDEQ and other stakeholders.

In September 2012, we submitted a Supplemental Environmental Report to the NDEQ for the proposed re-route, and provided an environmental report to the DOS, required as part of the DOS review of our cross-border permit application.

In January 2013, the NDEQ issued its final evaluation report on our proposed re-route to the Governor of Nebraska. The report noted that the proposed re-route avoids the Nebraska Sandhills, and that construction and operation of Keystone XL is expected to have minimal environmental impacts in Nebraska. On January 22, 2013, the Governor of Nebraska approved our proposed re-route.

The DOS is now completing their environmental and National Interest Determination review process and we are awaiting their decision on our cross-border permit application.

The pipeline will extend from Hardisty, Alberta to Steele City, Nebraska. We estimate the total cost of the project to be US$5.3 billion and, as of December 31, 2012, had invested US$1.8 billion.

We expect the pipeline to be in service in late 2014 or early 2015, subject to regulatory approvals.

Marketlink Projects
We have commenced construction on the Cushing Marketlink receipt facilities and expect to begin transporting crude oil supply from the Permian Basin producing region in western Texas to the U.S. Gulf Coast in late 2013 after our Gulf Coast Project is placed in service. Our Bakken Marketlink project will transport crude oil supply from the Williston Basin producing region in North Dakota and Montana to Cushing, Oklahoma on facilities that form part of Keystone XL which remains subject to regulatory approval.

Keystone Hardisty Terminal
We announced in May 2012 that we had secured binding long-term commitments of more than 500,000 Bbl/d for the Keystone Hardisty Terminal, and are expanding the proposed two million barrel project to a 2.6 million barrel terminal at Hardisty, Alberta, due to strong commercial support.

The terminal will provide new crude oil batch accumulation tankage and pipeline infrastructure for western Canadian producers, and access to the Keystone Pipeline System.

We expect the terminal to be operational in late 2014 and cost approximately $275 million.

Northern Courier Pipeline
We announced in August 2012 that we had been selected by Fort Hills Energy Limited Partnership to design, build, own and operate the proposed Northern Courier Pipeline.

The 90 km (54 mile) pipeline system will transport bitumen and diluent between the Fort Hills mine site and the Voyageur Upgrader, north of Fort McMurray, Alberta. We estimate total capital costs to be $660 million.

---

40 -- TransCanada Corporation

---

The pipeline is fully subscribed under long-term contract to service the Fort Hills mine, which is jointly owned by Suncor Energy Inc, Total E&P Canada Ltd. and Teck Resources Limited.

The project is conditional on the Fort Hills project receiving sanctions by the owners of the Fort Hills mine and is subject to regulatory approval.

Grand Rapids Pipeline
We announced in October 2012 that we had entered into binding agreements with Phoenix to develop the Grand Rapids Pipeline in northern Alberta.

The project includes crude oil and diluent lines to transport volumes approximately 500 km (300 miles), between the producing area northwest of Fort McMurray and the Edmonton/Heartland region. It will have the capacity to move up to 900,000 Bbl/d of crude oil and 330,000 Bbl/d of diluent.

We and Phoenix will each own 50 per cent of the project and we will operate the system, which is expected to cost $3 billion. Phoenix has entered into a long-term commitment to ship crude oil and diluent.

The Grand Rapids Pipeline system, subject to regulatory approvals, is expected to be placed in service in multiple stages, with initial crude oil service by mid-2015 and the complete system in service by the second half of 2017.

Canadian Mainline conversion
We have determined that it is technically and economically feasible to convert a portion of the Canadian Mainline natural gas pipeline system to crude oil service. The proposed pipeline will deliver crude oil between Hardisty, Alberta and markets in eastern Canada through a combination of converted natural gas pipelines and new construction. We are actively pursuing this project and have begun soliciting input from stakeholders and prospective shippers to determine market acceptance.

BUSINESS RISKS
The following are risks specific to our oil pipelines business. See page 71 for information about general risks that affect the company as a whole, including other operational risks, health, safety and environment (HSE) risks, and financial risks.

Operational
Optimizing and maintaining availability of our oil pipeline is essential to the success of our oil pipelines business. Interruptions in our pipeline operations impact our throughput capacity and may result in reduced capacity payment revenues and spot volume opportunities. We manage this by investing in a highly skilled workforce, operating prudently, using risk-based preventive maintenance programs and making effective capital investments. We use internal inspection equipment to check our pipelines regularly and repair them whenever necessary.

Regulatory
Decisions by Canadian and U.S. regulators can have a significant impact on the approval, construction, operation and financial performance of our oil pipelines. Public opinion about crude oil development and production also has an impact on the regulatory process. There are some individuals and interest groups that are expressing their opposition to crude oil production by opposing the construction of oil pipelines. We manage this risk by continuously monitoring regulatory developments and decisions to determine their possible impact on our oil pipelines business and by working closely with our stakeholders in the development and operation of the assets.

Execution, capital costs and permitting
Investing in large infrastructure projects involves substantial capital commitments, based on the assumption that the new assets will offer an attractive return on investment in the future. Under some contracts, we share the cost of these risks with customers. While we carefully consider the expected cost of our capital projects,

---

2012 Management's discussion and analysis -- 41

---

under some contracts we bear capital cost risk which may impact our return on these projects. Our capital projects are also subject to permitting risk which may result in construction delays and potentially reduced investment returns.

Crude oil supply and demand for pipeline capacity
Demand for crude oil pipeline capacity is dependent on the level of crude oil supply and demand for refined crude oil products. New producing technologies such as steam assisted gravity drainage and horizontal drilling in combination with fracking are allowing producers to economically increase development of unconventional resources, such as oil sands and shale oil at current crude oil prices, and have resulted in increased demand for new crude oil pipeline infrastructure. A decrease in demand for refined crude oil products could adversely impact the price of oil producers receive for their product. Lower margins for crude oil could mean producers curtail their investment in the development of crude oil supplies. Depending on their severity, these factors would negatively impact the opportunities we have to expand our crude oil pipeline infrastructure and, in the longer term, contract with shippers as current agreements expire.

Competition
As we continue to develop a competitive position in the North American crude oil transportation market to transport growing WCSB, Williston Basin and Permian Basin crude oil supplies to key U.S. refining markets, we face competition from other pipeline companies and to a lesser extent, rail companies which also seek to transport these crude oil supplies to market. Our success is dependant on our ability to offer and contract transportation services on terms that are market competitive.

---

42 -- TransCanada Corporation

---

---

Energy

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

We own, control or are developing more than 11,800 MW of generation capacity powered by natural gas, nuclear, coal, hydro, wind and solar assets. Our power business in Canada is mainly located in Alberta, Ontario and Québec. Our U.S. power business is located in New York, New England, and Arizona. The assets are largely supported by long-term contracts and some represent low-cost baseload generation, while others are critically located, essential capacity.

We conduct wholesale and retail electricity marketing and trading throughout North America from our offices in Alberta, Ontario and Massachusetts to actively manage our commodity exposure and provide higher returns.

We own or control approximately 156 Bcf of unregulated natural gas storage capacity in Alberta, accounting for approximately one-third of all storage capacity in the province. When combined with the regulated natural gas storage in Michigan (part of the Natural Gas Pipelines segment), we provide approximately 407 Bcf of natural gas storage and related services.

Strategy at a glance We are focusing on low-cost, long-life electrical infrastructure and natural gas storage assets supported by strong market fundamentals, and the opportunity for long-term contracts with reputable and creditworthy counterparties. Our investment in natural gas, nuclear, wind, hydro-power and solar generating facilities demonstrates our commitment to clean, sustainable energy. The growth in demand for power in North America is expected to provide the opportunity to participate in new generation and other power infrastructure projects. Current low natural gas prices make natural gas generation a very cost-competitive option to meet the growing demand in the markets we serve. Natural gas storage will continue to serve market needs and will play an important role in balancing supply and demand as additional gas supplies are connected to North American and world markets.

1    Includes facilities under development.

---

2012 Management's discussion and analysis -- 43

---

---

44 -- TransCanada Corporation

---

We are the operator of all of our Energy assets, except for the Sheerness, Sundance A and Sundance B PPAs, Cartier Wind, Bruce A and B and Portlands Energy.

	generating                       capacity (MW)				type of fuel		description		location		ownership
	Canadian Power 8,070 MW of power generation capacity (including facilities in development)
	Western Power 2,636 MW of power supply in Alberta and the western U.S.
30	Bear Creek		80		natural gas		Cogeneration plant		Grand Prairie, Alberta		100%
31	Cancarb		27		natural gas, waste heat		Facility fuelled by waste heat from an adjacent TransCanada facility that produces thermal carbon black, a by-product of natural gas		Medicine Hat, Alberta		100%
32	Carseland		80		natural gas		Cogeneration plant		Carseland, Alberta		100%
33	Coolidge1		575		natural gas		Simple-cycle peaking facility		Coolidge, Arizona		100%
34	Mackay River		165		natural gas		Cogeneration plant		Fort McMurray, Alberta		100%
35	Redwater		40		natural gas		Cogeneration plant		Redwater, Alberta		100%
36	Sheerness PPA		756		coal		PPA for entire output of facility		Hanna, Alberta		100%
37	Sundance A PPA		560		coal		PPA for entire output of facility		Wabamun, Alberta		100%
37	Sundance B PPA (Owned by ASTC Power Partnership2)		3533		coal		PPA for entire output of facility		Wabamun, Alberta		50%
	Eastern Power 2,950 MW of power generation capacity (including facilities in development)
38	Bécancour		550		natural gas		Cogeneration plant		Trois-Rivières, Québec		100%
39	Cartier Wind		3663		wind		Five wind power projects		Gaspésie, Québec		62%
40	Grandview		90		natural gas		Cogeneration plant		Saint John, New Brunswick		100%
41	Halton Hills		683		natural gas		Combined-cycle plant		Halton Hills, Ontario		100%
42	Portlands Energy		2753		natural gas		Combined-cycle plant		Toronto, Ontario		50%

---

2012 Management's discussion and analysis -- 45

---

	generating                  capacity (MW)				type of fuel		description		location		ownership
	Bruce Power 2,484 MW of power generation capacity through eight nuclear power units
43	Bruce A		1,4623		nuclear		Four operating reactors		Tiverton, Ontario		48.9%
43	Bruce B		1,0223		nuclear		Four operating reactors		Tiverton, Ontario		31.6%
	U.S. Power 3,755 MW of power generation capacity
44	Kibby Wind		132		wind		Wind farm		Kibby and Skinner Townships, Maine		100%
45	Ocean State Power		560		natural gas		Combined-cycle plant		Burrillville, Rhode Island		100%
46	Ravenswood		2,480		natural gas and oil		Multiple-unit generating facility using dual fuel-capable steam turbine, combined-cycle and combustion turbine technology		Queens, New York		100%
47	TC Hydro		583		hydro		13 hydroelectric facilities, including stations and associated dams and reservoirs		New Hampshire, Vermont and Massachusetts (on the Connecticut and Deerfield rivers)		100%
	Unregulated natural gas storage 118 Bcf of non-regulated natural gas storage capacity
48	CrossAlta		68 Bcf4				Underground facility connected to Alberta System		Crossfield, Alberta		100%
49	Edson		50 Bcf				Underground facility connected to Alberta System		Edson, Alberta		100%
	In development
50	Napanee		900		natural gas		Proposed combined-cycle plant		Greater Napanee, Ontario		100%
51	Ontario Solar		86		solar		Nine solar projects from Canadian Solar Solutions Inc. We expect to acquire the first two projects in the first half of 2013, and the remaining seven projects in 2013 to late 2014		Southern Ontario and New Liskeard, Ontario		100%

1

Located in Arizona, results reported in Canadian Power – Western Power.

2

We have a 50 per cent interest in ASTC Power Partnership, which has a PPA in place for 100 per cent of the production from the Sundance B power generating facilities.

3

Our share of power generation capacity.

4

Reflects the acquisition of an additional 27 Bcf of working gas storage capacity in December 2012.

---

46 -- TransCanada Corporation

---

RESULTS
Comparable EBITDA, and comparable EBIT are non-GAAP measures. See page 14 for more information.

year ended December 31 (millions of $)		2012		2011		2010
Canadian Power
Western Power1		335		483		212
Eastern Power2		345		297		212
Bruce Power		14		110		173
General, administrative and support costs		(48)		(43)		(38)
Canadian Power – comparable EBITDA3		646		847		559
Depreciation and amortization4		(152)		(141)		(114)
Canadian Power – comparable EBIT3		494		706		445
U.S. Power (US$)
Northeast Power5		257		314		335
General, administrative and support costs		(48)		(41)		(32)
U.S. Power – comparable EBITDA		209		273		303
Depreciation and amortization		(121)		(109)		(116)
U.S. Power – comparable EBIT		88		164		187
Foreign exchange		-		(4)		7
U.S. Power – comparable EBIT (Cdn$)		88		160		194
Natural Gas Storage
Alberta Storage		77		84		136
General, administrative and support costs		(10)		(6)		(8)
Natural Gas Storage – comparable EBITDA 3		67		78		128
Depreciation and amortization4		(10)		(12)		(13)
Natural Gas Storage – comparable EBIT 3		57		66		115
Business development comparable EBITDA and EBIT		(19)		(25)		(32)
Energy – comparable EBIT 3		620		907		722
Summary
Energy – comparable EBITDA 3		903		1,168		969
Depreciation and amortization4		(283)		(261)		(247)
Energy – comparable EBIT 3		620		907		722

1

Includes Coolidge starting in May 2011.

2

Includes Cartier phase two of Gros-Morne starting in November 2012, phase one of Gros-Morne starting in November 2011 and Montagne- Sèche starting in November 2011; Halton Hills starting in September 2010.

3

Includes our share of equity income from our equity accounted for investments in ASTC Power Partnership, Portlands Energy, Bruce Power and CrossAlta up to December 18, 2012. On December 18, 2012, we acquired the remaining 40 per cent interest in CrossAlta, bringing our ownership interest to 100 per cent.

4

Does not include depreciation and amortization of equity investments.

5

Includes phase two of Kibby Wind starting in October 2010.

Comparable EBITDA for Energy was $903 million in 2012, or $265 million lower than 2011. This reflected the net effect of:

•

decreased Western Power earnings due to the Sundance A PPA force majeure

•

incremental earnings from Cartier Wind in Eastern Power and Coolidge in Western Power

•

lower equity income from Bruce Power due to increased planned outage days

•

decreased U.S. Power earnings because of lower realized power prices, higher load serving costs and reduced water flows at the TC Hydro facilities.

---

2012 Management's discussion and analysis -- 47

---

OUTLOOK

Earnings
We expect 2013 earnings from the Energy segment to be higher than 2012, mainly due to the following:

•

incremental earnings from Bruce A Units 1 and 2 and fewer planned outage days at Bruce A

•

a full year of operations from Gros-Morne which was placed in service in fourth quarter 2012

•

higher New York capacity prices as a result of the September 2012 FERC order affecting pricing rules for new entrants

•

the acquisition of several of the Ontario Solar assets beginning in early 2013

•

we acquired the remaining 40 per cent interests in CrossAlta in December 2012

•

the return to service of Sundance A in fall 2013

•

offset by higher outage days at Bruce B and higher pension and staff costs at Bruce A and B.

Although a significant portion of Energy's output is sold under long-term contracts, power that is sold under shorter-term forward arrangements or at spot prices will continue to be affected by fluctuations in commodity prices. Fluctuations in Alberta, New England and New York power prices will affect Energy's earnings in 2013, and winter/summer natural gas price spreads will affect earnings in Gas Storage. Timing of the return of the Sundance A units may also have an impact on Western Power's earnings in late 2013.

Weather, unplanned outages, regulatory changes and the overall stability of the energy industry may also affect earnings in 2013.

Western Power
Alberta power market fundamentals are strong and new power capacity and transmission projects are being developed to meet the significant growth in demand. Consumption has been growing since 2009, mirroring economic growth since the recession. The outlook for forward oil prices supports ongoing investment in the oil sands and the associated development is expected to underpin continuing economic growth and increased power demand. Average Alberta power demand in 2012 was almost three per cent higher than 2011. The Alberta Electric System Operator is forecasting that demand will continue to grow at a similar rate over the next 10 years, and estimates that about 6,000 MW of new generation will be required. We expect to participate in new generation additions and other power infrastructure projects to meet Alberta's growing demand. Despite this rising demand, average power prices in Alberta in 2012 ($64/MWh) were lower than 2011 ($77/MWh). Spot market power prices are a function of many factors, including supply/demand conditions and natural gas prices. The supply of power is for the most part dictated by the performance of the coal fleet and wind availability, while power demand is highly influenced by the weather and seasonal factors. Natural gas prices, which at times were below $2/GJ, contributed to the low power prices, especially in offpeak and windy onpeak periods. The return of the Sundance A units in late 2013, the addition of a power transmission line to Montana in 2013 and a large combined cycle plant under construction for 2015 could have a negative effect on Alberta power prices in the near and medium term.

Eastern Power

Our existing energy assets in Ontario are largely insulated from changes in the market price of power through contracts with the Ontario Power Authority (OPA). The Ontario Independent Electricity System Operator forecasts growth in the demand for power will be flat in 2013 as conservation programs and time of use pricing temper demand. Ontario's remaining coal power stations will be retired by the end of 2013. Within the next decade, Ontario's aging nuclear units will require significant investments to extend their lives or will otherwise face retirement, which may provide development opportunities for us in the future.

U.S. Power
In New England, average power demand fell one per cent this year partly due to warm winter weather and there was a net increase of 240 MW of power supply (approximately 400 MW of new power supply was added and 160 MW retired). These supply/demand conditions, combined with low natural gas prices, resulted in a reduction in the average New England ISO power price to US$36/MWh in 2012 from US$47/MWh in

---

48 -- TransCanada Corporation

---

2011. The New England ISO forecasts growth in the demand for power of about one per cent per year in the coming years, based on modest economic growth.

Average power demand in New York fell one per cent in 2012 because of the economic situation, warm winter weather and the loss of demand associated with Superstorm Sandy. There was also a net reduction of 100 MW in power supply (approximately 500 MW of new power supply was added and 600 MW was retired). This supply/demand environment, combined with low natural gas prices, reduced the average New York ISO power price for New York City to US$39/MWh in 2012, from about US$51/MWh in 2011. The New York ISO forecasts power demand will grow one per cent per year over the next decade, based on modest growth in the population and the economy.

Capital expenditures
We spent a total of $24 million in 2012, and expect to spend $130 million on capital expenditures in Energy in 2013. We fund capital expenditures through existing cash flows and access to capital markets. See page 65 for further discussion on liquidity risk.

Equity investments and acquisitions
In 2012, we also invested $0.7 billion in Bruce Power for capital projects which included the restart of Units 1 and 2 and the West Shift Plus life extension outage on Unit 3 as well as $0.2 billion for the acquisition of the remaining 40 per cent interest in CrossAlta. We expect to spend approximately $0.3 billion on the acquisition of Ontario solar assets and Bruce Power investments in 2013.

UNDERSTANDING THE ENERGY BUSINESS
Our Energy business is made up of three groups:

•

Canadian Power

•

U.S. Power

•

Natural Gas Storage

Energy comparable EBIT – contribution by group, excluding business development expenses
Year ended December 31, 2012

         

Power generation capacity – contribution by group
Year ended December 31, 2012

---

2012 Management's discussion and analysis -- 49

---

Canadian Power

Western Power
We own or have the rights to approximately 2,600 MW of power supply in Alberta and Arizona, through three long-term PPAs, five natural gas-fired cogeneration facilities, and through Coolidge, a simple-cycle, natural gas peaking facility in Arizona.

Power purchased under long-term contracts is as follows:

		Type of contract		With		Expires
Sheerness PPA		Power purchased under a 20-year PPA		ATCO Power and TransAlta Utilities Corporation		2020
Sundance A PPA		Power purchased under a 20-year PPA		TransAlta Utilities Corporation		2017
Sundance B PPA		Power purchased under a 20-year PPA (own 50% through the ASTC Partnership)		TransAlta Utilities Corporation		2020

Power sold under long-term contracts is as follows:

		Type of contract		With		Expires