40-F 1 a2218336z40-f.htm 40-F
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U.S. Securities and Exchange Commission
Washington, D.C. 20549
 Form 40-F


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

OR

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

For the fiscal year ended December 31, 2013            Commission File Number 1-31690


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

Canada
(Jurisdiction of incorporation or organization)

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

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

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

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

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

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

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

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

ý Annual Information Form   ý Audited annual financial statements

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

At December 31, 2013, 707,441,314 common shares;
22,000,000 Cumulative Redeemable First Preferred Shares, Series 1;
14,000,000 Cumulative Redeemable First Preferred Shares, Series 3;
14,000,000 Cumulative Redeemable First Preferred Shares, Series 5; and
24,000,000 Cumulative Redeemable First Preferred Shares, Series 7
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 ý    No o

   

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

Form
  Registration No.  

S-8

     333-5916  

S-8

     333-8470  

S-8

     333-9130  

S-8

     333-151736  

S-8

     333-184074  

F-3

     33-13564  

F-3

     333-6132  

F-10

     333-151781  

F-10

     333-161929  

F-10

     333-192561  


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

Except sections specifically referenced below which shall be deemed incorporated by reference herein and filed, no other portion of the TransCanada Corporation 2013 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 164 of the TransCanada Corporation 2013 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 2013 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 2013 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 page 82 of the TransCanada Corporation 2013 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 and Mr. Richard E. Waugh have been designated audit committee financial experts and are 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 and Mr. Waugh as audit committee financial experts does not make Mr. Benson or Mr. Waugh an "expert" for any purpose, impose any duties, obligations or liability on Mr. Benson or Mr. Waugh 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 2013 fiscal year.


PRINCIPAL ACCOUNTANT FEES AND SERVICES

For information on principal accountant fees and services, see "Audit committee — Pre-approval policies and procedures" and "Audit committee — External auditor service fees" on pages 38 and 39 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 26 of the Notes to the 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 72 of the TransCanada Corporation 2013 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:

Chair:
Members:		   K.E. Benson
D.H. Burney
M. P. Salomone
D.M.G. Stewart
R. E. Waugh


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 and future financing options available to us

    •
    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 impact of regulatory 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 accounting changes, 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 the following key assumptions, and subject to the following risks and uncertainties:

Assumptions

    •
    inflation rates, commodity prices and capacity prices

    •
    timing of financings and hedging

    •
    regulatory decisions and outcomes

    •
    foreign exchange rates

    •
    interest rates

4

    •
    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 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

    •
    costs for labour, equipment and materials

    •
    access to capital markets

    •
    interest and foreign exchange rates

    •
    weather

    •
    cyber security

    •
    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).

As actual results could vary significantly from the forward-looking information, 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.

    TRANSCANADA CORPORATION

 
 
Per:
 
/s/ DONALD R. MARCHAND
 DONALD R. MARCHAND
 Executive Vice-President and Chief Financial Officer

 
 
 
 
Date: February 21, 2014

DOCUMENTS FILED AS PART OF THIS REPORT

 

13.1

  

TransCanada Corporation Annual information form for the year ended December 31, 2013.
 

13.2

  

Management's discussion and analysis (included on pages 1 through 96 of the TransCanada Corporation 2013 Annual report to shareholders).
 

13.3

  

2013 Audited consolidated financial statements (included on pages 97 through 164 of the TransCanada Corporation 2013 Annual report to shareholders), including the auditors' report thereon and the Report of Independent Registered Public Accounting Firm on the effectiveness of TransCanada's internal control over financial reporting as of December 31,  2013.
 

EXHIBITS
 

23.1

  

Consent of KPMG LLP, Independent Registered Public Accounting Firm.
 

31.1

  

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 

31.2

  

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 

32.1

  

Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements.
 

32.2

  

Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements.
 

101.INS

  

XBRL Instance Document.
 

101.SCH

  

XBRL Taxonomy Extension Schema Document.
 

101.CAL

  

XBRL Taxonomy Extension Calculation Linkbase Document.
 

101.DEF

  

XBRL Taxonomy Definition Linkbase Document.
 

101.LAB

  

XBRL Taxonomy Extension Label Linkbase Document.
 

101.PRE

  

XBRL Taxonomy Extension Presentation Linkbase Document.

 
 
 
 

TransCanada Corporation

 
 

2013 Annual information form

 
 

February 19, 2014

GRAPHIC

 
 
 
 
 
 


Table of Contents

Presentation of information   2
Forward-looking information   2
TransCanada Corporation   3
  Corporate structure   3
  Intercorporate relationships   3
General development of the business   4
  Developments in the Natural Gas Pipelines business   5
  Developments in the Oil Pipelines business   9
  Developments in the Energy business   12
Business of TransCanada   15
  Natural Gas Pipelines business   16
  Oil Pipelines business   18
  Regulation of the Natural Gas and Oil Pipelines businesses   19
  Energy business   20
General   23
  Employees   23
  Health, safety and environmental protection and social policies   23
Risk factors   24
Dividends   24
Description of capital structure   25
  Share capital   25
Credit ratings   28
  DBRS   29
  Moody's   29
  S&P   30
Market for securities   30
  Common shares   30
  Series 1 Preferred Shares   31
  Series 3 Preferred Shares   31
  Series 5 Preferred Shares   32
  Series 7 Preferred Shares   32
  Series U Preferred Shares and Series Y Preferred Shares   33
Directors and officers   33
  Directors   33
  Board committees   35
  Officers   35
  Conflicts of interest   36
Corporate governance   37
Audit committee   37
  Relevant education and experience of members   37
  Pre-approval policies and procedures   38
  External auditor service fees   39
Legal proceedings and regulatory actions   39
Transfer agent and registrar   39
Interest of experts   39
Additional information   39
Glossary   40
Schedule A   41
Schedule B   42

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 (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, 2013 (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 19, 2014 (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 (GAAP). We use certain financial measures that do not have a standardized meaning under GAAP and therefore they may not be comparable to similar measures presented by other entities. 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 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 and future financing options available to us
•
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 impact of regulatory 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 accounting changes, 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.

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 financings and hedging

2 -- TransCanada Corporation


•
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 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
•
costs for labour, equipment and materials
•
access to capital markets
•
interest and foreign exchange rates
•
weather
•
cyber security
•
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).

As actual results could vary significantly from forward-looking information, 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 the 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. TransCanada does not hold any material assets directly, other than the common shares of TCPL and receivables from certain of TransCanada's subsidiaries.

INTERCORPORATE RELATIONSHIPS
The following diagram presents the name and jurisdiction of incorporation, continuance or formation of TransCanada's principal subsidiaries as at Year End. Each of the subsidiaries shown has total assets that exceeded 10 per cent of the total consolidated assets of TransCanada or revenues that exceeded 10 per cent of the total consolidated revenues of TransCanada as at Year End. TransCanada

2013 Annual information form -- 3


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.

LOGO

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

We operate our business in three segments: Natural Gas Pipelines, Oil Pipelines and Energy. Natural Gas Pipelines and Oil Pipelines are principally comprised of our 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 our power operations and the non-regulated natural gas storage business in Canada.

Summarized below are significant developments that have occurred in our Natural Gas Pipelines, Oil Pipelines and Energy businesses, respectively, and certain acquisitions, dispositions, events or conditions which have had an influence on that development, during the last three financial years and year to date in 2014.

4 -- TransCanada Corporation

DEVELOPMENTS IN THE NATURAL GAS PIPELINES BUSINESS

Canadian Pipelines

Date   Description of development
NGTL System (formerly known as the Alberta System) and expansion projects
January 2011   We received approval from the National Energy Board (NEB) to construct the Horn River pipeline.
March 2011   We commenced construction of the $275 million Horn River pipeline. We also executed an agreement to extend the Horn River pipeline by approximately 100 kilometres (km) (62 mile). An application requesting approval to construct and operate this extension was filed with the NEB in October 2011.
August 2011   The NEB approved construction of a 24 km (15 mile) extension of the Groundbirch pipeline and construction commenced.
October 2011   Commercial integration of the NGTL System and ATCO Pipelines (ATCO) system commenced. Under an agreement, the facilities of the NGTL System and ATCO system are commercially operated as a single transmission system and transportation service is provided to customers by us pursuant to the NGTL 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 NGTL System and ATCO system.
October 2011   The NEB approved the construction of natural gas pipeline projects for the NGTL System.
November – December 2011   The regulatory decisions by which commercial integration of the NGTL System and ATCO system was authorized were the subject of appeals to the Federal Court of Appeal. We continued 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 Horn River project was completed, extending the NGTL System into the Horn River shale play in British Columbia (B.C.). The total contracted volumes for Horn River, including the extension, are expected to be approximately 900 million cubic feet per day (MMcf/d) by 2020.
June 2012   The NEB approved the Leismer-Kettle River Crossover project, a 77 km (46 mile) pipeline to expand the NGTL System with the intent of increasing capacity to meet demand in northeastern Alberta. The expected cost of the expansion is $160 million.
December 2012   The current settlements for the NGTL System expired. Final tolls for 2013 were to be determined through either new settlements or rate cases and any orders resulting from the NEB's decision on the Canadian 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.
August 2013   We signed agreements for approximately two billion cubic feet per day (Bcf/d) of firm gas transportation services to underpin the development of a major pipeline extension and expansion of the NGTL System to receive and transport natural gas from the North Montney area of B.C. (the North Montney project). The proposed North Montney project will include an interconnection with our proposed PRGT (as defined below) project to provide natural gas supply to the proposed Pacific NorthWest LNG export facility near Prince Rupert, B.C. and is expected to cost approximately $1.7 billion, which includes $100 million for downstream facilities. Under commercial arrangements, receipt volumes are expected to increase between 2016 and 2019 to an aggregate volume of approximately two Bcf/d and delivery volumes to the PRGT project are expected to be approximately 2.1 Bcf/d beginning in 2019. We also entered into arrangements with other parties for transportation services that will utilize the North Montney project facilities.
August 2013   We reached settlement of the NGTL System annual revenue requirement for the years 2013 and 2014 with shippers and other interested parties (the NGTL 2013-2014 Settlement). The settlement fixed the return at 10.1 per cent on a 40 per cent deemed common equity, established an increase in the composite depreciation rate to 3.05 per cent and 3.12 per cent for 2013 and 2014, respectively, and fixed the OM&A costs for 2013 at $190 million and 2014 at $198 million with any variance to our account. We also requested and received approval for changes to existing interim rates to reflect the settlement, effective September 1, 2013, pending a decision on the settlement application.
November 2013   We filed an application with the NEB to construct and operate the North Montney project. The estimated capital cost of the project is $1.7 billion and it consists of approximately 300 km (186 mile) of pipeline.
November 2013   The NEB approved the NGTL 2013-2014 Settlement and final 2013 rates, as filed, in November 2013. We expect the final tolls for 2014 for the NGTL System will be determined on the basis of the NGTL settlement process.

2013 Annual information form -- 5
Date   Description of development
Canadian Mainline
January – February 2011   We received approval for revised interim tolls, effective March 1, 2011 which increased interim tolls from the current interim tolls which were based on 2010 final tolls, to more closely align with tolls calculated in accordance with the 2007-2011 settlement with stakeholders.
September 2011   To respond to the evolving changes in flow patterns on the Canadian Mainline, we developed a comprehensive business and services restructuring proposal. The Canadian Restructuring Proposal application with the NEB culminated from extensive discussion and negotiation with our shippers. The NEB established interim tolls for 2012 based on the approved 2011 final tolls.
November – December 2011   We 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 our 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 Canadian Restructuring Proposal.
May 2012   We received NEB approval to build new pipeline facilities to provide Ontario and Quebec markets with additional gas supplies 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 MMcf/d from the Niagara meter station to Kirkwall, Ontario, effective November 2012.
November 2012   Transportation of natural gas supply from the Marcellus shale basin supply began moving on the Canadian Mainline.
March 2013   We received the NEB decision on our Canadian Restructuring Proposal application to change the business structure and the terms and conditions of service for the Canadian Mainline. The NEB decision established a Toll Stabilization Account (TSA) to capture the surplus or the shortfall between our revenues and our cost of service for each year over the five year term of the decision. The NEB decision also identified certain circumstances that would require a new tolls application prior to the end of the five year term. One of those circumstances is if the TSA balance becomes positive, which occurred in 2013.
May 2013   We filed a compliance filing and an application for a review and variance of the NEB decision regarding the Canadian Restructuring Proposal.
June 2013   The NEB dismissed the review and variance application and set out a process to consider the tariff revisions. Additional changes to the Canadian Mainline's tariff were considered by the NEB as a separate application which was heard in an oral hearing.
July 2013   The NEB released its reasons for the dismissal. We began implementation of the NEB decision related to the Canadian Restructuring Proposal. Since implementation, an additional 1.3 Bcf/d of firm service originating at Empress, Alberta has been contracted for, more than doubling the contracted capacity of this location. The implementation of the NEB decision was a key priority in 2013 and with the ability to price discretionary services at market prices we were able to essentially meet our overall cost of service requirements for 2013.
September 2013   The Canadian Mainline and the three largest Canadian local distribution companies entered into a settlement (LDC Settlement) which was filed with the NEB for approval in December 2013. The LDC Settlement, if approved, will establish new fixed tolls for 2015 to 2020 and maintain tolls for 2014 at the current rates. The LDC Settlement calculates tolls for 2015 on a base ROE of 10.10 per cent on 40 per cent deemed common equity. It also includes an incentive mechanism that requires a $20 million (after tax) annual contribution by us from 2015 to 2020, which could result in a range of ROE outcomes from 8.70 per cent to 11.50 per cent. The LDC Settlement will enable the addition of facilities in the Eastern Triangle to serve immediate market demand for supply diversity and market access. The LDC Settlement is intended to provide a market driven, stable, long-term accommodation of future demand in this region in combination with the anticipated lower demand for transportation on the Prairies Line and the Northern Ontario Line while providing a reasonable opportunity to recover our costs. The LDC Settlement also retains pricing flexibility for discretionary services and implements certain tariff changes and new services as required by the terms of the settlement. The NEB decision remains in effect pending the outcome of the LDC Settlement application.
January 2014   Shippers on the Canadian Mainline elected to renew approximately 2.5 Bcf/d of their contracts through November 2016. This represents a significant amount of volume renewal, especially by Canadian shippers.

6 -- TransCanada Corporation
Date   Description of development
U.S. Pipelines
Gas Transmission Northwest LLC (GTN)
May 2011   We closed the sale of a 25 per cent interest in each of GTN and Bison Pipeline LLC (Bison) to TC PipeLines, LP (TCLP) for a total transaction value of US$605 million, which included US$81 million or 25 percent of GTN's outstanding debt.
November 2011   The Federal Energy Regulatory Commission (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.
July 2013   We sold an additional 45 per cent interest in each of GTN and Bison to TCLP for an aggregate purchase price of US$1.05 billion. We continue to hold a 30 per cent direct ownership interest in both pipelines. We also hold a 28.9 per cent interest in and are the General Partner of, TCLP.
Bison    
January 2011   Bison pipeline was placed into commercial service.
May 2011   We closed the sale of a 25 per cent interest in each of GTN and Bison to TCLP for a total transaction value of US$605 million, which included US$81 million or 25 percent of GTN's outstanding debt.
July 2013   We sold an additional 45 per cent interest in each of GTN and Bison to TCLP for an aggregate purchase price of US$1.05 billion. We continue to hold a 30 per cent direct ownership interest in both pipelines. We also hold a 28.9 per cent interest in and are the General Partner of, TCLP.
Great Lakes
November 2013   Great Lakes received FERC approval for a rate settlement with its shippers resulting in maximum recourse rates increasing by approximately 21 per cent resulting in a modest increase in revenues derived from its recourse rate contracts. The settlement includes a 17 month moratorium through March 2015 and requires us to have new rates in effect by January 1, 2018.
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.
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 (the LLC), allowing the 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   The LLC began commercial operations.
ANR Lebanon Lateral Reversal Project
October 2013   We concluded a successful binding open season. We have executed firm transportation contracts for 350 MMcf/d at maximum tariff rates for 10 years on the ANR Lebanon Lateral Reversal project, which will entail modifications to existing facilities. The facility modifications are expected to be completed in the first quarter 2014. Contracted volumes will increase over the course of 2014 generating incremental earnings. The project will substantially increase our ability to receive gas on ANR's southeast mainstream from the Utica/Marcellus shale areas.
Mexican Pipelines
Topolobampo and Mazatlan Pipeline projects
November 2012   The CFE awarded us with the contract to build, own and operate the Topolobampo pipeline project. The Topolobampo project is a 530 km (329 mile), 30 inch pipeline with a capacity of 670 MMcf/d and an estimated cost of US$1 billion that will deliver gas from El Encino, Chihuahua and interconnects with third party pipelines in El Oro, Sinaloa to Topolobampo, Sinaloa.
November 2012   The CFE awarded us with the contract to build, own and operate the Mazatlan pipeline project, from El Oro to Mazatlan, Mexico. The Mazatlan project is a 413 km (257 mile), 24 inch pipeline running from El Oro to Mazatlan, within the state of Sinaloa with a capacity of 200 MMcf/d and an estimated cost of US$400 million.
First Quarter 2014   Permitting and engineering activities are advancing as planned for these two northwest Mexico pipelines. Both projects are supported by 25 year contracts with the CFE and are expected to be in service mid to late 2016.

2013 Annual information form -- 7
Date   Description of development
Tamazunchale Pipeline Extension project
February 2012   We signed a contract with the CFE for the Tamazunchale Pipeline Extension project. Engineering, procurement and construction contracts were signed and construction related activities began.
First Quarter 2014   The construction of the US$500 million Tamazunchale Pipeline Extension project is proceeding although delays have occurred due to a significant number of archeological finds within the pipeline route. It is expected these findings and related alternative construction will move the project's scheduled in service date to second quarter 2014. As these types of findings are not uncommon in significant infrastructure projects in Mexico, contractual relief for such delays is provided. We continue to work with local, state and federal authorities to minimize and mitigate ground disturbance at the specific sites as well as to minimize impact to the scheduled in service date.
Guadalajara
June 2011   The Guadalajara pipeline was completed. We and CFE agreed to add a US$60 million compressor station to the pipeline.
First Quarter 2013   The compressor station went into service.
LNG Pipeline Projects
Coastal GasLink
June 2012   We were selected to design, build, own and operate the proposed Coastal GasLink project. The estimated $4 billion, 650km (404 mile) pipeline is expected to have an initial capacity of 1.7 Bcf/d and will transport natural gas from the Montney gas producing region near Dawson Creek, B.C. to LNG Canada's proposed LNG export facility near Kitimat, B.C.
January 2014   We filed the Application for an Environmental Assessment Certificate with the B.C. Environmental Assessment Office (BCEAO). We are currently focused on community, landowner, government and First Nations engagement as the project advances through the regulatory process. The pipeline would be placed in service near the end of the decade, subject to a final investment decision to be made by LNG Canada after obtaining final regulatory approvals. We continue to advance this project and all costs would be recoverable should the project not proceed.
Prince Rupert Gas Transmission Project (PRGT)
January 2013   We were selected to design, build, own and operate the proposed $5 billion, 750 km (466 mile) PRGT. The 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 are currently focused on First Nations, community, landowner and government engagement as the PRGT advances through the regulatory process with the BCEAO. We continue to refine our study corridor based on consultation and detailed studies to date. A final investment decision to construct the project, for a planned in service date of late 2018, is expected to be made following final regulatory approvals. We continue to advance this project and all costs would be fully recoverable should the project not proceed.
Alaska LNG Project
March 2012   Three major producers (the Alaska North Slope producers), along with us through participation in the Alaska LNG 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 U.S. FERC certificate for the Alberta route beyond fall 2012, our original deadline.
July 2012   The Alaska LNG 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.
January 2014   The State of Alaska is proposing new legislation that would transition from the Alaska Gasline Inducement Act and enable a new commercial arrangement to be established with us, the Alaska North Slope producers, and the Alaska Gasline Development Corp. It has also been agreed that an LNG export project, rather than a pipeline to Alberta, is the best opportunity to commercialize Alaska North Slope gas resources in current market conditions. It is anticipated that two years of front end engineering will be completed before further commitments to commercialize the project will be made.

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.

8 -- TransCanada Corporation

DEVELOPMENTS IN THE OIL PIPELINES BUSINESS

Date   Description of development
Keystone Pipeline System
January 2011   Required operational modifications were completed on the Canadian conversion section of the Keystone Pipeline System. As a result, the system was capable of operating at the approved design pressure.
February 2011   The commercial in service of the second section of Keystone extending the pipeline from Steele City Nebraska to Cushing, Oklahoma (the Cushing Extension) was achieved, and the Company also commenced recording earnings for the first section of Keystone, which delivers oil from Hardisty, Alberta to Wood River and Patoka in Illinois (Wood River/Patoka).
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. We filed a restart plan with the U.S. Pipeline and Hazardous Material Safety Administration which was approved in June 2011.
February 2012   We announced that what had previously been the Cushing to U.S. Gulf Coast project of the Keystone Pipeline System has its own independent value to the marketplace, and that we plan to build it as the stand-alone pipeline which is not part of the Keystone XL Presidential Permit application.
May 2012   We 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.
January 2014   We finished constructing the 780km (485 mile) 36 inch pipeline of the Gulf Coast project, the Keystone Pipeline System. Crude oil transportation service on the project began January 22, 2014. We are projecting an average pipeline capacity of 520,000 Bbl/d for the first year of operation.
Houston Lateral and Terminal
Fourth Quarter 2013   Construction continued on the US$400 million 77 km (48 mile) Houston Lateral pipeline and tank terminal to transport crude oil to Houston, Texas refineries. We anticipate the capacity of the lateral will be similar to that of the Gulf Coast project and the terminal is expected to have initial storage capacity for 700,000 barrels of crude oil. The pipeline and terminal are expected to be completed in mid-2015.
Cushing Marketlink
October 2012   We commenced construction on the Cushing Marketlink receipt facilities which will facilitate the transportation of crude oil from the market hub at Cushing to the U.S. Gulf Coast refining market on facilities that form part of the Keystone Pipeline System. Construction continues on the Cushing Marketlink receipt facilities at Cushing, Oklahoma, and is expected to be completed in the first half of 2014.
Keystone XL
August 2011   We received a Final Environmental Impact Statement regarding the Keystone XL U.S. Presidential Permit application.
November 2011   The U.S. Department of State (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   We announced that we had 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   We sent a letter to the DOS informing the DOS that we planned to file a Presidential Permit application in near future for Keystone XL. We also informed the DOS that the Cushing to U.S. Gulf Coast portion of the Keystone XL project would be constructed outside of the Presidential Permit process.
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 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 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   We submitted a Supplemental Environmental Report to the NDEQ for the proposed reroute 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 reroute of Keystone XL to the Governor of Nebraska. In January 2013, the Governor of Nebraska approved our proposed reroute. The NDEQ issued its final evaluation report noting that construction and operation of Keystone XL is expected to have minimal environmental impacts in Nebraska.

2013 Annual information form -- 9
Date   Description of development
March 2013   The DOS released its Draft Supplemental Environmental Impact Statement for Keystone XL. The impact statement reaffirmed construction of the 830,000 Bbl/d Keystone XL project would not result in any significant impact to the environment.
January 2014   The DOS released its Final Supplemental Environmental Impact Statement (FSEIS) for Keystone XL. The results included in the report were consistent with previous environmental reviews of Keystone XL. The FSEIS concluded Keystone XL is unlikely to significantly impact the rate of extraction in the oil sands and that all other alternatives to Keystone XL are less efficient methods of transporting crude oil, and would result in significantly more greenhouse gas (GHG) emissions, oil spills and risks to public safety. The report initiated the National Interest Determination period of up to 90 days which involves consultation with other governmental agencies and provides an opportunity for public comment.
February 2014   A Nebraska district court ruled that the state Public Service Commission, rather than Governor Dave Heineman, has the authority to approve an alternative route through Nebraska for the Keystone XL project. We will now analyze the judgment and decide what next steps may be taken. Nebraska's Attorney General has filed an appeal. We anticipate the pipeline, which will extend from Hardisty, Alberta to Steele City, Nebraska, to be in service approximately two years following the receipt of the Presidential Permit. The US$5.4 billion cost estimate will increase depending on the timing and conditions of the permit. Any capital cost increase above the initial estimated capital cost, up to a specified amount, is shared between us and the shippers such that 75 per cent of the change in capital cost is reflected in the fixed payment received by us. Any capital cost increase above the specified amount is shared equally between us and the shippers. As of December 31, 2013, we have invested US$2.2 billion in the project.
Energy East Pipeline
April 2013   We announced that we were holding an open season to obtain firm commitments for a pipeline to transport crude oil from western receipt points to eastern Canadian markets. The open season followed a successful expression of interest phase and discussions with prospective shippers.
August 2013   We announced we are moving forward with the 1.1 million Bbl/d Energy East Pipeline as it received approximately 900,000 Bbl/d of firm, long-term contracts in its open season to transport crude oil from western Canada to eastern refineries and export terminals. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets. Subject to regulatory approvals, the pipeline is anticipated to commence deliveries in Québec in 2018 with service to New Brunswick to follow in late 2018. We have begun Aboriginal and stakeholder engagement and associated field work as part of our initial design and planning. We intend to file the necessary regulatory applications in mid 2014 for approvals to construct and operate the pipeline project and terminal facilities.
Northern Courier Pipeline
August 2012   We announced that we were selected by Fort Hills Energy Limited Partnership (FHELP) to design, build, own and operate the proposed Northern Courier Pipeline. The pipeline system is fully subscribed under long-term contract to service the Fort Hills mine, which is jointly owned by Suncor Energy Inc. (Suncor) and two other companies.
April 2013   We filed a permit application with the Alberta Energy Regulator (AER) after completing the required Aboriginal and stakeholder engagement and associated field work.
October 2013   Suncor announced that the FHELP is proceeding with the Fort Hills oil sands mining project and that it expects to begin producing crude oil in 2017. Our Northern Courier Pipeline project is expected to cost $800 million and will transport bitumen and diluent between the Fort Hills mine site and Suncor's terminal located north of Fort McMurray, Alberta.
Heartland Pipeline and TC Terminals
May 2013   We announced we had reached binding long-term shipping agreements to build, own and operate the Heartland Pipeline and TC Terminals projects, and filed a permit application for the terminal facility. The projects will include a 200 km (125 mile) crude oil pipeline connecting the Edmonton/Heartland, Alberta market to facilities in Hardisty, Alberta, and a terminal facility in the Heartland industrial area north of Edmonton, Alberta. We anticipate the pipeline could transport up to 900,000 Bbl/d, while the terminal is expected to have storage capacity for up to 1.9 million barrels of crude oil. These projects together have a combined cost estimated at $900 million and are expected to be placed in service in 2016.
October 2013   We filed a permit application for the pipeline with the AER after completing the required Aboriginal and stakeholder engagement and associated field work.
February 2014   The application for the terminal facility was approved.
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.
May 2013   We started construction on the Keystone Hardisty Terminal which we anticipate will have a storage capacity of up to 2.6 million barrels of crude oil. The $300 million crude oil terminal at Hardisty, Alberta is expected to be in service in 2016.

10 -- TransCanada Corporation
Date   Description of development
Grand Rapids Pipeline
October 2012   We announced that we had entered into binding agreements with a partner to develop the Grand Rapids Pipeline in northern Alberta. Along with our partner, we will each own 50 per cent of the project and we will operate the system, which is expected to cost $3 billion. Our partner entered into a long-term commitment to ship crude oil and diluent on this pipeline system.
May 2013   We filed a permit application for the Grand Rapids Pipeline with the AER after completing the required Aboriginal and stakeholder engagement and associated field work. The dual pipeline system could transport up to 900,000Bbl/d of crude oil and 330,000Bbl/d of diluent. Subject to regulatory approvals, the system is expected to be placed in service in multiple stages, with initial crude oil service by mid-2015 and the complete system in service in the second half of 2017.

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.

2013 Annual information form -- 11

DEVELOPMENTS IN THE ENERGY BUSINESS

Date   Description of development
Ontario Solar
December 2011   We agreed to buy nine Ontario solar generation facilities (combined capacity of 86 megawatt (MW)) from Canadian Solar Solutions Inc. (Canadian Solar), for approximately $500 million. Under the terms of the agreement, Canadian Solar will develop and build each of the nine solar facilities using photovoltaic panels. We buy each facility once construction and acceptance testing are complete and commercial operation begins. All power produced by the solar facilities is currently or will be sold under 20 year PPAs with the OPA.
June 2013   We completed the acquisition of the first facility for $55 million.
September 2013   We completed the acquisition of two solar facilities for $99 million.
December 2013   We completed the acquisition of a fourth solar facility for $62 million. We expect the acquisition of the remaining five facilities to close in 2014, subject to satisfactory completion of the related construction activities and regulatory approvals.
Cancarb Limited and Cancarb Waste Heat Facility
January 2014   We announced we had reached an agreement for the sale of Cancarb Limited, our thermal carbon black facility, and its related power generation facility for $190 million subject to closing adjustments. The sale is expected to close in late first quarter 2014.
Bécancour
June 2011   Hydro-Québec Distribution (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 had the option to extend the suspension on an annual basis until such time as regional electricity demand levels recover.
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.
June 2013   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 2014.
December 2013   We entered into an amendment to the original suspension agreement with Hydro-Québec to further extend suspension of generation through to the end of 2017. Under the amendment, Hydro-Québec continues to have the option (subject to certain conditions) to further extend the suspension past 2017. The amendment also includes revised provisions intended to reduce Hydro-Québec's payments to us for Bécancour's natural gas transportation costs during the suspension period, although we retain our ability to recover our full capacity costs under the Electricity Supply Contract with Hydro-Québec while the facility is suspended. Final execution of this amendment is conditional on the pending approval by the Régie de l'énergie.
Sundance
January 2011   The Sundance A Units 1 and 2 were subject to a force majeure claim by the operator.
February 2011   The operator informed us that it was not economic to replace or repair Sundance A 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. Throughout 2011, revenues and costs had been recorded as though the outages were interruptions of supply in accordance with the terms of the PPA.
July 2012   An arbitration panel decided that the Sundance A PPA should not be terminated and ordered the operator to rebuild Units 1 and 2. The panel also limited the operator's force majeure claim from November 20, 2011 until the units could reasonably be returned to service. The operator announced that it expected 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 pretax 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 pre-tax charge to second quarter 2012 earnings, of which $20 million related to amounts accrued in 2011. We did not record further revenue or costs from the PPA until the units were returned to service. The net book value of the Sundance A PPA recorded in Intangibles and Other Assets remained fully recoverable.
November 2012   An arbitration decision was reached with the arbitration panel granting partial force majeure relief to the operator with respect to Sundance B Unit 3, and we reduced our equity earnings by $11 million from the ASTC Power Partnership (ASTC) to reflect the amount that will not be recovered as result of the decision. In 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 the operator. The ASTC, which holds the Sundance B PPA, disputed the claim under the binding dispute resolution process provided in the PPA because we did not believe the operator's claim met the test of force majeure. We therefore recorded equity earnings from our 50 per cent ownership interest in ASTC as though this event were a normal plant outage.
September 2013   Sundance A Unit 1 returned to service.
October 2013   Sundance A Unit 2 returned to service.

12 -- TransCanada Corporation
Date   Description of development
Bruce Power
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 was 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   We 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. All that time, overall plant availability for Bruce A was expected to be approximately 90 per cent in 2013.
April 2013   Bruce Power announced that it had reached an agreement with the OPA to extend the Bruce B floor price through to the end of the decade, which is expected to coincide with the 2019 and 2020 end of life dates for the Bruce B units.
April 2013   Bruce Power returned Bruce A Unit 4 to service after completing an expanded life extension outage investment program, which began in August 2012. It is anticipated that this investment will allow Unit 4 to operate until at least 2021.
January 2014   Cameco Corporation announced it had agreed to sell its 31.6 per cent limited partnership interest in Bruce B to BPC Generation Infrastructure Trust. We are considering our option to increase our Bruce B ownership percentage.
Napanee
December 2012   We signed a contract with the OPA to develop, own and operate a new 900 MW natural gas-fired power plant at Ontario Power Generation's Lennox site in eastern Ontario in the town of Greater Napanee. Currently, the project is on schedule and we expect to complete the permitting process in late 2014. We expect to invest approximately $1.0 billion in the Napanee facility during construction and commercial operations are expected to begin in late 2017 or early 2018.
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 under 20 year PPAs.

2013 Annual information form -- 13
Date   Description of development
CrossAlta
December 2012   We acquired the remaining 40 per cent interests in the Crossfield Gas Storage facility and CrossAlta Gas Storage & Services Ltd. (CrossAlta) marketing company from our partner for approximately $214 million cash, net of cash acquired. We now own and operate 100 per cent of the interests of CrossAlta. The acquisition added an additional 27 billion cubic feet of working gas storage capacity to our existing portfolio in Alberta.
Coolidge
May 2011   Coolidge power generating station was completed and placed in-service.
U.S. Power
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.
January 2014   Capacity prices in the New York market are established through a series of forward auctions and utilize a demand curve administered price for purposes of setting the monthly spot price. The demand curve, among other inputs, uses assumptions with respect to the expected cost of the most likely peaking generation technology applicable to new entrants to the market. In January 2014, the FERC accepted a new rate for the demand curve that was filed by NYISO as part of its triennial Demand Curve Reset (DCR) process. The filing changed the generation technology used in the DCR versus that used during the last reset process for New York City Zone J where Ravenswood operates. We do not expect this change to impact Zone J capacity prices in 2014, however, this new assumption does have the potential to negatively affect these capacity prices in 2015 and 2016. Additionally, another recent FERC decision affecting future capacity auctions in New England Power Pool (NEPOOL) may potentially improve capacity price conditions in 2018 and beyond for our assets that are located in NEPOOL.

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.

14 -- TransCanada Corporation

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 51 per cent of revenues and 47 per cent of our total assets, Oil Pipelines accounted for approximately 13 per cent of revenues and 25 per cent of our total assets' and Energy accounted for approximately 36 per cent of revenues and 25 per cent of our total assets. The following table shows our revenues from operations by segment, classified geographically, for the years ended December 31, 2013 and 2012.

Revenues from operations (millions of dollars)   2013   2012
Natural Gas Pipelines        
  Canada – Domestic   $2,718   $2,294
  Canada – Export(1)   598   751
  United States   1,069   1,112
  Mexico   112   107
    4,497   4,264
Oil Pipelines        
  Canada – Domestic   –   –
  Canada – Export(1)   399   370
  United States   725   669
    1,124   1,039
Energy(2)        
  Canada – Domestic   1,941   1,233
  Canada – Export(1)   –   –
  United States   1,235   1,471
    3,176   2,704
Total revenues(3)   $8,797   $8,007
(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.

2013 Annual information form -- 15

NATURAL GAS PIPELINES BUSINESS
Our natural gas pipeline network transports natural gas to local distribution companies, power generation facilities and other businesses across Canada, the U.S. and Mexico. We also have regulated natural gas storage facilities in Michigan.

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

   
Length		  
Description		   Effective
Ownership
Canadian pipelines            
NGTL System   24,522 km
(15,237 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   14,114 km
(8,770 miles)		   Transports natural gas from the Alberta/Saskatchewan border to serve eastern Canada and the U.S. northeast markets   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 Montréal to Québec City corridor, and connects with the Portland pipeline system that serves the northeast U.S.   50%
U.S. pipelines            
ANR           100%
   Pipeline   16,121 km
(10,017 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 to the Gulf Coast region as well as Wisconsin, Michigan, Illinois, Indiana and Ohio. Connects with Great Lakes    
   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 50.2 per cent of the system through the combination of our 30 per cent direct ownership interest and our 28.9 per cent interest in TCLP   50.2%
GTN   2,178 km
(1,353 miles)		   Transports natural gas from the WCSB and the Rocky Mountains to Washington, Oregon and California. Connects with Tuscarora and Foothills. We effectively own 50.2 per cent of the system through the combination of our 30 per cent direct ownership interest and our 28.9 per cent interest in TCLP   50.2%
Great Lakes   3,404 km
(2,115 miles)		   Connects with the Canadian Mainline near Emerson, Manitoba and St Clair, Ontario, plus interconnects with ANR at Crystal Falls and Farwell in Michigan, to transport natural gas to eastern Canada, and the U.S. upper Midwest. We effectively own 67 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 28.9 per cent interest in TCLP   67%
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 Arizona and California, and connects with another third-party system on the California/Mexico border. We effectively own 28.9 per cent of the system through our interest in TCLP   28.9%
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 14.5 per cent of the system through our 28.9 per cent interest in TCLP   14.5%
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 Nevada, and delivers gas in northeastern California and northwestern Nevada. We effectively own 28.9 per cent of the system through our interest in TCLP   28.9%

16 -- TransCanada Corporation
   
Length		  
Description		   Effective
Ownership
Mexican pipelines            
Guadalajara   310 km
(193 miles)		   Transports natural gas from Manzanillo, Colima to Guadalajara, Jalisco   100%
Tamazunchale   130 km
(81 miles)		   Transports natural gas from Naranjos, Veracruz in east central Mexico to Tamazunchale, San Luis Potosi   100%
Under construction            
Mazatlan Pipeline   413 km
(257 miles)		   To deliver natural gas from El Oro to Mazatlan, Sinaloa in Mexico. Will connect to the Topolobampo Pipeline at El Oro.   100%
Tamazunchale Pipeline Extension   235 km
(146 miles)		   To extend existing terminus of the Tamazunchale Pipeline to deliver natural gas to power generating facilities in El Sauz, Queretaro and other parts of central Mexico   100%
Topolobampo Pipeline   530 km
(329 miles)		   To deliver natural gas to Topolobampo, Sinaloa, from interconnects with third party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico   100%
In development            
Alaska LNG Pipeline   1,448 km*
(900 miles)		   To transport natural gas from Prudhoe Bay to LNG facilities in Nikiski, Alaska    
Coastal GasLink   650 km*
(404 miles)		   To deliver natural gas from the Montney gas producing region at an expected interconnect on NGTL near Dawson Creek, B.C. to LNG Canada's proposed LNG facility near Kitimat, B.C.   100%
Prince Rupert Gas Transmission   750 km*
(466 miles)		   To deliver natural gas from North Montney gas producing region at a NGTL interconnect near Fort St. John, B.C. to the proposed Pacific Northwest LNG facility near Prince Rupert, B.C.   100%
North Montney Mainline   306 km*
(190 miles)		   To deliver natural gas from the North Montney gas producing region and connect to NGTL's existing Groundbirch Mainline   100%
*
Pipe lengths are estimates as final route is still under design.

Further information about our 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.

2013 Annual information form -- 17

OIL PIPELINES BUSINESS
Our existing crude oil pipeline infrastructure connects Alberta crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas, as well as connecting U.S. crude oil supplies from the Cushing, Oklahoma hub to refining markets in the U.S. Gulf Coast.

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

    Length   Description   Ownership
Oil pipelines            
Keystone Pipeline System (includes Gulf Coast project)   4,247 km
(2,639 miles)		   Transports crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka in Illinois, Cushing, Oklahoma, and to the U.S. Gulf Coast refining market   100%
Under construction            
Cushing Marketlink Receipt Facility   Crude oil receipt facilities   To facilitate the transportation of crude oil from the market hub at Cushing, Oklahoma to the U.S. Gulf Coast refining market on facilities that form part of the Keystone Pipeline System   100%
Houston Lateral and Terminal   77 km (48 miles)   To transport crude oil from the Keystone Pipeline System to Houston, Texas   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 access to the Keystone Pipeline System   100%
In development            
Bakken Marketlink Receipt Facility   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%
Grand Rapids Pipeline   500 km
(300 miles)		   To transport crude oil and diluent between the producing area northwest of Fort McMurray, Alberta and the Edmonton/Heartland market region   50%
Keystone XL   1,897 km
(1,179 miles)		   Crude oil pipeline from Hardisty, Alberta to Steele City, Nebraska to expand capacity of the Keystone Pipeline System   100%
Northern Courier Pipeline   90 km
(56 miles)		   To transport bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal located north of Fort McMurray, Alberta   100%
Heartland Pipeline and TC Terminals   200 km
(125 miles)		   Terminal and pipeline facilities to transport crude oil from the Edmonton/Heartland, Alberta region to facilities in Hardisty, Alberta   100%
Energy East Pipeline   4,500 km
(2,700 miles)		       100%

Further information about our 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.

18 -- TransCanada Corporation

REGULATION OF THE NATURAL GAS AND OIL PIPELINES BUSINESSES

Canada

Natural Gas Pipelines
The Canadian Mainline, NGTL System and most of the other Canadian pipelines owned or operated by TransCanada (collectively, the Systems) are regulated by the NEB under the National Energy Board Act (Canada). The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems.

The NEB generally 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. The decision of the NEB in March 2013 in respect of the Canadian Mainline approved the 2011 revenue requirement as filed, approved tolls charged in 2012 as final with any variance between revenues and costs deferred for recovery in future years, and set tolls for 2013 through 2017 at competitive levels, fixing tolls for some services and providing unlimited pricing discretion for others. Further information relating to the decision from the NEB regarding the Canadian Restructuring Proposal as well as the LDC Settlement can be found in the General Developments of the business – Developments in the Natural Gas Pipelines business – Canadian Mainline section above.

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 Pipelines Projects
The Coastal GasLink Pipeline and the PRGT projects are being proposed and developed primarily under the regulatory regime administered by the B.C. Oil and Gas Commission (BCOGC) and the 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.

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 Pipelines Projects
The Northern Courier Pipeline and Grand Rapids Pipeline are being proposed and developed primarily under the regulatory regime administered by the AER and Alberta Environment and Sustainable Resource Development (ESRD). AER 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 barrels) of 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 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 project 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 who approve construction of new pipeline facilities and ongoing operations of the infrastructure. Our Mexican pipelines have approved tariffs, services and related rates, however the contracts underpinning the construction and operation of the facilities are long-term negotiated fixed rate contracts. These rates are only subject to change under specific circumstances such as certain types of force majeure events or changes in law.

2013 Annual information form -- 19

ENERGY BUSINESS
Our 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 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 unregulated natural gas storage capacity in Alberta and regulated natural gas storage in Michigan (part of the Natural Gas Pipelines segment).

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%
Cancarb1   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%
Coolidge2   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 ASTC3)   3533   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   3664   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   2754   natural gas   Combined-cycle plant   Toronto, Ontario   50%
Ontario Solar   36   solar   Four solar facilities   Southern Ontario   100%

20 -- 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   1,4624   nuclear   Four operating reactors   Tiverton, Ontario   48.9%
Bruce B   1,0224   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 Bcf       Underground facility connected to the NGTL System   Crossfield,
Alberta		   100%
Edson   50 Bcf       Underground facility connected to the NGTL System   Edson, Alberta   100%
In development        
Napanee   900   natural gas   Proposed combined-cycle plant   Greater Napanee, Ontario   100%
Ontario Solar   50   solar   Acquisition of five remaining solar facilities from Canadian Solar in 2014   Southern Ontario and New Liskeard, Ontario   100%
(1)
As at December 31, 2013 both the Cancarb waste heat and thermal carbon black plant were classified as Assets Held for Sale. For further information, refer to the Energy – Significant Events section of the MD&A which is incorporated by reference herein.

(2)
Located in Arizona, results reported in Canadian Power — Western Power.

(3)
We have a 50 per cent interest in ASTC, which has a PPA in place for 100 per cent of the production from the Sundance B power generating facilities.

(4)
Our share of power generation capacity.

We own or have the rights to 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.

2013 Annual information form -- 21

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 per cent through ASTC)		   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 power generation capacity in eastern Canada. All of the power produced by these assets is sold under contract.

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
Ontario Solar2   20-year Feed-in Tariff (FIT) contracts   OPA   2033
(1)
Power generation has been suspended since 2008.

(2)
We acquired four facilities in 2013 and expect to acquire the remaining five facilities in 2014.

Assets currently in development are as follows:

    Type of contract   With   Expires
Ontario Solar1   20-year FIT contracts   OPA   20 years from in-service date
Napanee   20-year Clean Energy Supply contract   OPA   20 years from in-service date
(1)
We acquired four facilities in 2013 and expect to acquire the remaining five facilities in 2014.

Further information about our 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.

22 -- TransCanada Corporation


General

EMPLOYEES
At Year End, TransCanada's principal operating subsidiary, TCPL, had 5,551 full time active employees, substantially all of whom were employed in Canada and the U.S., as set forth in the following table.

Calgary   2,736
Western Canada (excluding Calgary)   531
Eastern Canada   287
Houston   569
U.S. Midwest   477
U.S. Northeast   437
U.S. Southeast/Gulf Coast (excluding Houston)   304
U.S. West Coast   81
Mexico and South America   129
Total   5,551

HEALTH, SAFETY AND ENVIRONMENTAL PROTECTION AND SOCIAL POLICIES
The Health, Safety and Environment committee of TransCanada's Board of Directors (the Board) 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, conforms to external industry consensus standards and voluntary 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, plans, 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 with comparison to previously set targets and takes into account incidents and highlights of performance during the relevant quarter, and reviews programs, 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, asset integrity, operational risk issues, personnel security and applicable legislative developments. The committee also receives updates on any specific areas of operational risk management review 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 GHG emissions, water quality, wastewater discharges and waste management. Such laws and regulations generally require facilities to obtain or comply with a wide variety of environmental registrations, licences, permits and other approvals and requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements and/or 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 2013 continued to be better than most industry benchmarks.

2013 Annual information form -- 23

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 safety record in 2013 continued to exceed industry benchmarks.

TransCanada routinely conducts emergency response 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.

Social Policies
TransCanada has a number of policies, guiding principles and practices in place to help manage Aboriginal and other stakeholder relations. We have adopted a Code of business ethics (Code) which applies to all employees, officers and directors as well as contract workers of TransCanada and its wholly-owned subsidiaries and operated entities in countries where we conduct business. The Code 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 contractors, and serve as a standard for us in our dealings with all stakeholders.

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. Our stakeholder relations framework provides the structure to guide our teams' behavior and actions, so they understand their responsibility and extend respect, courtesy and the opportunity to respond to every stakeholder.

We strive for continuous improvement in how we navigate the interconnections and complexity of environmental, social and economic issues related to our business. These issues are of great importance to our stakeholders, and have an impact on our ability to build and operate energy infrastructure.

Risk factors

A discussion of our 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

Our 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, our 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 our 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 (the 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 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 (the 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 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 (the 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 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.

24 -- TransCanada Corporation

Holders of cumulative redeemable first preferred shares, series 7 (the Series 7 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 period ending April 30, 2019. The dividend on the Series 7 preferred shares will reset on April 30, 2019 and every five years thereafter to a rate equal to the sum of the then five year Government of Canada bond yield and 2.38 per cent. The holders of Series 7 preferred shares have the right to convert their shares into cumulative redeemable first preferred shares, series 8 (the Series 8 preferred shares) as set out under the heading First preferred shares below.

Holders of cumulative redeemable first preferred shares, series 9 (the Series 9 preferred shares) are entitled to receive fixed cumulative preferential cash dividends, at an annual rate of $1.0625 per share, payable quarterly, as and when declared by the Board, for the initial period ending October 30, 2019. The dividend on the Series 9 preferred shares will reset on October 30, 2019 and every five years thereafter to a rate equal to the sum of the then five year Government of Canada bond yield and 2.35 per cent. The holders of Series 9 preferred shares have the right to convert their shares into cumulative redeemable first preferred shares, series 10 (the Series 10 preferred shares) as set out under the heading First preferred shares below.

The dividends declared on the our preferred shares during the past three completed financial years are set out in the following table:

    2013   2012   2011
Dividends declared on Series 1 preferred shares   $1.15   $1.15   $1.15
Dividends declared on Series 3 preferred shares   $1.00   $1.00   $1.00
Dividends declared on Series 5 preferred shares   $1.10   $1.10   $1.10
Dividends declared on Series 7 preferred shares(1)   $1.00   –   –
Dividends declared on Series 9 preferred shares(2)   –   –   –
(1)
Issued March 4, 2013.

(2)
Issued January 20, 2014.

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

    2013   2012   2011
Dividends declared on common shares   $1.84   $1.76   $1.68

We increased the quarterly dividend on our outstanding common shares by four per cent to $0.48 per share for the quarter ending March 31, 2014 which equates to $1.92 per share on an annualized basis.

Description of capital structure

SHARE CAPITAL
TransCanada's authorized share capital consists of an unlimited number of common shares, of which 707,441,314 were issued and outstanding at Year End, and an unlimited number of first preferred shares and second preferred shares, issuable in series, of which the following were issued and outstanding as at Year End, or as otherwise indicated below.

Preferred Shares   Issued and Outstanding   Convertible to
Series 1   22,000,000   22 million Series 2 preferred shares
Series 3   14,000,000   14 million Series 4 preferred shares
Series 5   14,000,000   14 million Series 6 preferred shares
Series 7   24,000,000   24 million Series 8 preferred shares
Series 9(1)   18,000,000   18 million Series 10 preferred shares
(1)
Issued January 20, 2014.

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

2013 Annual information form -- 25


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.

We have 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 an 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 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.

TransCanada has a dividend reinvestment and share purchase plan (DRP) which permits eligible holders of TransCanada common or preferred shares and preferred shares of TCPL to elect to reinvest their dividends and make optional cash payments to buy TransCanada common shares acquired on the open market at 100 per cent of the weighted average purchase price. 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.

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 an annualized 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

26 -- TransCanada Corporation


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 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 an annualized 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 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 an annualized 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.

The Series 7 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 7 preferred shares are substantially identical to those attaching to the Series 1 preferred shares, except as outlined below. The Series 7 preferred shares are redeemable by TransCanada in whole or in part on April 30, 2019, and on April 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 7 preferred shares have the right to convert their shares into cumulative redeemable Series 8 preferred shares, subject to certain conditions, on April 30, 2019 and on April 30 in every fifth year thereafter. The holders of Series 8 preferred shares will be entitled to receive quarterly floating rate cumulative preferential cash dividends, as and when declared by the Board, at an annualized rate equal to the sum of the then 90 day Government of Canada treasury bill rate and 2.38 per cent and have the right to convert their shares into Series 8 preferred shares, subject to certain conditions, on April 30, 2024 and on April 30 in every fifth year thereafter. In the event of liquidation, dissolution or winding up of TransCanada, the holders of Series 7 preferred shares shall be entitled to receive $25.00 per Series 7 preferred share plus all accrued and unpaid dividends thereon in preference over the common shares or any other shares ranking junior to the Series 7 preferred shares. Other than with respect to redemption rights (as described below), the material characteristics of the Series 8 preferred shares

2013 Annual information form -- 27


are substantially the same as the Series 7 preferred shares. The Series 8 preferred shares are redeemable by TransCanada in whole or in part on any date after April 30, 2019, 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 April 30, 2024 and on April 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 9 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 9 preferred shares are substantially identical to those attaching to the Series 1 preferred shares, except as outlined below. The Series 9 preferred shares are redeemable by TransCanada in whole or in part on October 30, 2019, and on October 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 9 preferred shares have the right to convert their shares into cumulative redeemable Series 10 preferred shares, subject to certain conditions, on October 30, 2019 and on October 30 in every fifth year thereafter. The holders of Series 10 preferred shares will be entitled to receive quarterly floating rate cumulative preferential cash dividends, as and when declared by the Board, at an annualized rate equal to the sum of the then 90 day Government of Canada treasury bill rate and 2.35 per cent and have the right to convert their shares into Series 9 preferred shares, subject to certain conditions, on October 30, 2024 and on October 30 in every fifth year thereafter. In the event of liquidation, dissolution or winding up of TransCanada, the holders of Series 9 preferred shares shall be entitled to receive $25.00 per Series 9 preferred share plus all accrued and unpaid dividends thereon in preference over the common shares or any other shares ranking junior to the Series 9 preferred shares. Other than with respect to redemption rights (as described below), the material characteristics of the Series 10 preferred shares are substantially the same as the Series 9 preferred shares. The Series 10 preferred shares are redeemable by TransCanada in whole or in part on any date after October 30, 2019, 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 October 30, 2024 and on October 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 first preferred shares of each series 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 holders of the first preferred shares of such series 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 of the first preferred share of such series, until all arrears of dividends have been paid. Subject to the CBCA, the series provisions attaching to the first 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.

28 -- TransCanada Corporation


The 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 (low)   A3   A–
Medium-term notes   A (low)   A3   A–
Junior subordinated notes   BBB   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 and other than in respect of DBRS' ratings of commercial paper and short-term debt, which utilize high, middle and low subcategories for its R-1 and R-2 rating categories. In respect of long-term debt and preferred share ratings, 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 qualifying negative factors are considered manageable. The A (low) 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 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.

2013 Annual information form -- 29

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 somewhat 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 issuers. Short-term debt issuers rated A-2 have satisfactory capacity to meet their financial commitments, however they are somewhat more susceptible to adverse effects of changes in circumstances and economic conditions than obligors in the highest rating category; 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. Our Series 1, 3, 5, 7 and 9 preferred shares have been listed for trading on the TSX since September 30, 2009, March 11, 2010, June 29, 2010, March 4, 2013 and January 20, 2014 under the symbols TRP.PR.A, TRP.PR.B, TRP.PR.C, TRP.PR.D, and TRP.PR.E, 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, 5 and 7 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 2013   $48.93   $46.10   $48.54   22,141,189   $46.02   $43.32   $45.66   10,823,386
November 2013   $48.48   $46.61   $46.85   25,329,959   $46.45   $44.17   $44.39   8,847,429
October 2013   $47.24   $43.94   $46.99   21,425,127   $45.25   $42.41   $45.11   8,263,822
September 2013   $46.51   $44.89   $45.25   20,209,858   $44.94   $43.06   $43.94   7,668,690
August 2013   $48.48   $44.75   $45.91   20,421,616   $46.79   $42.59   $43.62   9,854,808
July 2013   $47.79   $45.10   $46.93   23,656,071   $46.12   $42.83   $45.72   12,784,623
June 2013   $47.94   $44.62   $45.28   33,556,916   $46.97   $42.39   $43.11   16,760,131
May 2013   $51.21   $47.07   $47.56   26,146,463   $49.65   $45.54   $45.85   8,960,677
April 2013   $50.26   $47.65   $49.94   26,052,153   $49.60   $46.58   $49.51   12,440,623
March 2013   $50.08   $47.40   $48.50   25,384,945   $48.90   $46.05   $47.89   12,382,311
February 2013   $48.87   $46.80   $48.04   25,462,009   $48.87   $45.80   $46.51   9,828,080
January 2013   $49.44   $46.82   $47.21   26,082,774   $49.64   $47.16   $47.37   11,080,878

30 -- TransCanada Corporation

SERIES 1 PREFERRED SHARES

    TSX (TRP.PR.A)
   
Month   High
($)		   Low
($)		   Close
($)		   Volume
Traded
December 2013   $24.54   $23.10   $23.72   336,208
November 2013   $24.80   $23.58   $24.55   278,223
October 2013   $24.67   $23.26   $24.11   287,790
September 2013   $25.14   $24.19   $24.65   379,661
August 2013   $24.90   $23.20   $24.70   307,979
July 2013   $25.24   $24.41   $24.43   289,147
June 2013   $25.29   $23.12   $24.76   299,266
May 2013   $25.59   $25.16   $25.19   677,235
April 2013   $25.79   $25.22   $25.45   514,560
March 2013   $25.75   $25.35   $25.66   405,750
February 2013   $26.00   $25.33   $25.49   413,651
January 2013   $26.00   $25.50   $25.75   444,889

SERIES 3 PREFERRED SHARES

    TSX (TRP.PR.B)
   
Month   High
($)		   Low
($)		   Close
($)		   Volume
Traded
December 2013   $20.63   $20.03   $20.37   998,882
November 2013   $21.16   $19.98   $20.68   517,633
October 2013   $20.64   $19.94   $20.03   290,469
September 2013   $22.09   $19.91   $20.14   922,863
August 2013   $22.96   $20.27   $21.72   312,075
July 2013   $23.94   $22.81   $22.86   349,059
June 2013   $24.90   $22.60   $23.19   263,285
May 2013   $24.97   $24.55   $24.76   448,999
April 2013   $24.90   $24.37   $24.65   571,040
March 2013   $25.04   $24.32   $24.93   508,121
February 2013   $24.90   $24.34   $24.56   621,184
January 2013   $25.00   $24.39   $24.80   555,279

2013 Annual information form -- 31

SERIES 5 PREFERRED SHARES

    TSX (TRP.PR.C)
   
Month   High
($)		   Low
($)		   Close
($)		   Volume
Traded
December 2013   $22.90   $21.26   $21.75   387,442
November 2013   $23.19   $22.26   $23.09   770,771
October 2013   $23.74   $22.00   $22.75   251,607
September 2013   $23.97   $22.50   $23.34   450,168
August 2013   $23.73   $21.25   $23.10   270,842
July 2013   $24.75   $23.00   $23.30   329,537
June 2013   $25.65   $24.25   $24.74   177,521
May 2013   $25.75   $25.39   $25.60   235,352
April 2013   $25.79   $25.40   $25.50   292,516
March 2013   $26.08   $25.41   $25.59   321,154
February 2013   $25.87   $25.44   $25.62   285,166
January 2013   $25.95   $25.30   $25.70   282,832

SERIES 7 PREFERRED SHARES

    TSX (TRP.PR.D)
   
Month   High
($)		   Low
($)		   Close
($)		   Volume
Traded
December 2013   $25.50   $25.00   $25.11   686,593
November 2013   $25.48   $24.50   $25.45   528,477
October 2013   $25.12   $24.50   $25.05   765,889
September 2013   $25.05   $23.85   $24.84   383,697
August 2013   $25.12   $23.80   $24.87   478,375
July 2013   $25.61   $24.95   $25.18   639,196
June 2013   $25.87   $24.72   $25.16   912,786
May 2013   $26.10   $25.70   $25.75   640,573
April 2013   $26.15   $25.82   $26.00   1,990,847
March 2013   $26.15   $25.25   $26.00   3,292,039

In addition, TransCanada's subsidiary, TCPL, has cumulative redeemable first preferred shares, series Y listed on the TSX under the symbol TCA.PR.Y, which will be redeemed on March 5, 2014 at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends. TCPL's cumulative redeemable first preferred shares, series U, were listed on the TSX under the symbol TCA.PR.X until their redemption on October 15, 2013.

32 -- TransCanada Corporation


SERIES U PREFERRED SHARES AND SERIES Y PREFERRED SHARES

    Series U (TCA.PR.X)   Series Y (TCA.PR.Y)
   
Month   High
($)		   Low
($)		   Close
($)		   Volume
Traded		   High
($)		   Low
($)		   Close
($)		   Volume
Traded
December 2013   —   —   —   —   $50.50   $49.71   $49.85   83,846
November 2013   —   —   —   —   $50.47   $50.12   $50.26   54,495
October 2013   $50.60   $50.54   $50.56   23,177   $50.32   $49.66   $50.20   55,215
September 2013   $50.60   $48.59   $50.53   900,300   $50.69   $48.85   $49.86   54,314
August 2013   $50.29   $47.02   $49.10   54,733   $50.45   $48.10   $49.15   49,888
July 2013   $50.22   $49.49   $50.19   36,528   $50.23   $49.90   $50.02   107,214
June 2013   $50.80   $49.70   $49.90   42,967   $51.03   $49.85   $49.98   54,370
May 2013   $51.06   $50.54   $50.70   47,008   $51.48   $50.74   $50.95   63,103
April 2013   $51.05   $50.46   $50.90   40,609   $51.85   $50.79   $51.20   37,508
March 2013   $51.79   $50.55   $51.01   43,088   $52.48   $51.51   $51.94   49,268
February 2013   $52.04   $50.61   $51.15   89,555   $52.94   $52.05   $52.20   82,717
January 2013   $52.19   $51.58   $51.71   38,797   $52.90   $52.25   $52.90   128,629

Directors and officers

As of February 19, 2014, the directors and officers of TransCanada as a group beneficially owned, or exercised control or direction, directly or indirectly, over an aggregate of 452,965 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 19, 2014 (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
Calgary, Alberta
Canada		   Corporate director, Director, Calgary Airport Authority from January 2010 to December 2013. President and Chief Executive Officer, Laidlaw International, Inc. from June 2003 to October 2007.   2005
Derek H. Burney(1), O.C.
Ottawa, Ontario
Canada		   Senior strategic advisor at Norton Rose Fulbright (law firm). Chairman, Gardaworld International's (risk management and security services) Advisory Board since April 2008. Advisory Board member, Paradigm Capital Inc. (investment dealer) since 2011. Chair, Canwest Global Communications Corp. (media and communications) from August 2006 (director since April 2005) to October 2010.   2002
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. (food retail) since January 2001, Royal Bank of Canada (chartered bank) since October 1991 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
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. (agricultural) since May 2006.   2010
S. Barry Jackson
Calgary, Alberta
Canada		   Corporate director, Chair of the Board, TransCanada since April 2005. Director, WestJet Airlines Ltd. (airline) since February 2009 and Laricina Energy Ltd. (oil and gas, exploration and production) since December 2005. Director, Nexen Inc. (Nexen) (oil and gas, exploration and production) from 2001 to June 2013, Chair of the board, Nexen from 2012 to June 2013.   2002

2013 Annual information form -- 33
Name and
place of residence		   Principal occupation during the five preceding years   Director since
Paula Rosput Reynolds
Seattle, Washington
U.S.A.		   President and Chief Executive Officer, PreferWest, LLC (business advisory group) since October 2009. Director, Anadarko Petroleum Corporation (oil and gas, exploration and production) since August 2007, Delta Air Lines, Inc. (airline) since August 2004 and BAE Systems plc. (aerospace, defence, information security) since April 2011. Vice-Chair and Chief Restructuring Officer, American International Group Inc. (insurance and financial services) from October 2008 to September 2009.   2011
John Richels(2)
Nichols Hills, Oklahoma
U.S.A.		   President and Chief Executive Officer, Devon Energy Corporation (Devon) (oil and gas, exploration and production, energy infrastructure) since 2010 (President since 2004). Director, Devon since 2007 and BOK Financial Corp. (financial services) since 2013. Chairman, American Exploration and Production Council since May 2012. Former Vice-Chairman of the board of governors, Association of Petroleum Producers.   2013
Mary Pat Salomone(3)(4)
Bonita Springs, Florida
U.S.A.		   Corporate director. Senior Vice-President and Chief Operating Officer, The Babcock & Wilcox Company (B&W) (energy infrastructure) from January 2010 to June 2013. Manager Business Development from 2009 to 2010 and Manager, Strategic Acquisitions from 2008 to 2009, Babcock & Wilcox Nuclear Operations Group Inc. (B&W Nuclear). Director, United States Enrichment Corporation (basic materials, nuclear) from December 2011 to October 2012.   2013
W. Thomas Stephens(5)
Greenwood Village, Colorado
U.S.A.		   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
D. Michael G. Stewart
Calgary, Alberta
Canada		   Corporate director. Director, Pengrowth Energy Corporation (oil and gas, exploration and production) since December 2010. Canadian Energy Services & Technology Corp. (chemical, oilfield services) since January 2010 and Northpoint Resources Ltd. (oil and gas, exploration and production) since July 2013. Director, C&C Energia Ltd. (oil and gas) from May 2010 to December 2012 and Orleans Energy Ltd. (oil and gas) from October 2008 to December 2010. Director, Pengrowth Corporation (administrator of Pengrowth Energy Trust) from October 2006 to December 2010. Director, Canadian Energy Services Inc. (general partner of Canadian Energy Services L.P.) from January 2006 to December 2009.   2006
Richard E. Waugh
Toronto, Ontario
Canada		   Corporate director. Former Deputy Chairman, President and Chief Executive Officer, The Bank of Nova Scotia (Scotiabank) (chartered bank) until January 2014.(6) Director, Catalyst Inc. (non-profit) from February 2007 to November 2013 and Chair, Catalyst Canada Advisory Board from February 2007 to October 2013.   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)
Mr. Richels joined the Board effective June 19, 2013.

(3)
Ms. Salomone joined the Board effective February 12, 2013.

(4)
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.

(5)
Mr. Stephens previously served on the Board from 2000 to 2005.

(6)
Mr. Waugh was President and Chief Executive Officer of Scotiabank until November 2013 where he then served as Deputy Chairman and director of Scotiabank until January 31, 2014.

34 -- 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 19, 2014, are identified below. Mr. Burney was appointed as the Chair of the Governance committee at the first Governance Committee meeting held in 2013, effective February 11, 2013. Mr. Stewart was appointed Chair of the Health, Safety and Environment committee effective April 26, 2013.

Director   Audit
committee		   Governance
committee		   Health, Safety and
Environment
committee		   Human Resources
committee
Kevin E. Benson   Chair   ü        
Derek H. Burney   ü   Chair        
Paule Gauthier           ü   ü
S. Barry Jackson       ü       ü
Paula Rosput Reynolds           ü   ü
John Richels       ü       ü
Mary Pat Salomone   ü       ü    
W. Thomas Stephens           ü   Chair
D. Michael G. Stewart   ü       Chair    
Richard E. Waugh   ü   ü        

Information about the Audit committee can be found in this AIF under the heading Audit committee.

OFFICERS
All of the executive officers and corporate officers of TransCanada reside in Calgary, Alberta, Canada. 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   Prior to November 2012, Senior Vice-President, Canadian and Eastern U.S. Pipelines, Prior to January 2011. Senior Vice-President, Power Commercial since January 2006.
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(2)   Executive Vice-President, Corporate Development   Prior to July 2010, Executive Vice-President, Pipeline Strategy and Development since May 2006.
Sean McMaster(1)   Executive Vice-President, Stakeholder Relations and General Counsel and Chief Compliance Officer   Prior to February 2012, Executive Vice-President, Corporate and General Counsel since January 2007 and Chief Compliance Officer since July 2006.
Alexander J. Pourbaix   President, Energy and Oil Pipelines   Prior to July 2010, Executive Vice-President, Corporate Development since July 2009 and President, Energy since June 2006.
(1)
Retiring effective February 28, 2014.

(2)
Effective February 28, 2014, Mr. McConaghy's title will change from Executive Vice-President, Corporate Development to Executive Vice-President of TransCanada until his retirement later this year.

2013 Annual information form -- 35

    Effective March 1, 2014, the executive officers of TransCanada will be:

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   Prior to November 2012, Senior Vice-President, Canadian and Eastern U.S. Pipelines. Prior to January 2011, Senior Vice-President, Power Commercial since January 2006.
Dennis J. McConaghy(1)   Executive Vice-President   Prior to March 2014, Executive Vice-President, Corporate Development since July 2010. Prior to July 2010, Executive Vice-President, Pipeline Strategy and Development since May 2006.
Donald R. Marchand   Executive Vice-President and Chief Financial Officer   Prior to July 2010, Vice-President, Finance and Treasurer since September 1999.
Alexander J. Pourbaix   Executive Vice-President and President, Development   Prior to March 2014, President, Energy and Oil Pipelines. Prior to July 2010, President, Energy. Prior to July 2010, Executive Vice-President, Corporate Development since July 2009 and President, Energy since June 2006.
James M. Baggs   Executive Vice-President, Operations and Engineering   Prior to March 2014, Senior Vice-President, Operations and Engineering. Prior to June 2012, Vice-President, Operations and Engineering. Prior to July 2009, Vice-President, Field Operations and Engineering since June 2006 (TCPL).
Kristine L. Delkus   Executive Vice-President, General Counsel and Chief Compliance Officer   Prior to March 2014, Senior Vice-President, Pipelines Law and Regulatory Affairs. Prior to June 2012, Deputy General Counsel, Pipelines and Regulatory Affairs since September 2006 (TCPL).
Paul E. Miller   Executive Vice-President and President, Liquids Pipelines   Prior to March 2014, Senior Vice-President, Oil Pipelines. Prior to December 2010, Vice-President, Oil Pipelines. Prior to July 2010, Vice-President, Keystone Pipeline since May 2008 (TCPL).
William C. Taylor   Executive Vice-President and President, Energy   Prior to March 2014, Senior Vice-President, US and Canadian Power. Prior to May 2013, Senior Vice-President, Eastern Power. Prior to July 2010, Vice-President and General Manager, U.S. Northeast Power since May 2008 (TCPL).
(1)
Effective February 28, 2014, Mr. McConaghy's title will change from Executive Vice-President, Corporate Development to Executive Vice-President of TransCanada until his retirement later this year.

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 since December 2008.
Ronald L. Cook   Vice-President, Taxation   Vice-President, Taxation since April 2002.
Joel E. Hunter   Vice-President, Finance   Prior to July 2010, Director, Corporate Finance since January 2008.
Christine R. Johnston   Vice-President and Corporate Secretary   Prior to March 2012, Vice-President, Finance Law. Prior to January 2010, Vice-President, Corporate Development Law. Prior to September 2009, Associate General Counsel, Corporate Development and Finance Law since September 2005.
Garry E. Lamb   Vice-President, Risk Management   Vice-President, Risk Management since October 2001.
G. Glenn Menuz   Vice-President and Controller   Vice-President and Controller since June 2006.

CONFLICTS OF INTEREST
Directors and officers of TransCanada and its subsidiaries are required to disclose any existing or potential conflicts in accordance with TransCanada policies governing directors and officers and in accordance with the CBCA. Our Code covers potential conflicts of interest.

Serving on other boards
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 our 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

36 -- TransCanada Corporation


shipper. The Governance committee monitors relationships among directors to ensure that business associations do not affect the Board's performance.

The Board considers whether directors serving on the boards of all entities including public and private companies, Crown corporations and non-profit organizations pose any potential conflict. The Board reviews these relationships annually to determine that they do not interfere with any of our director's ability to act in our best interests. Throughout the year, if a director declares a material interest in any material contract or material transaction being considered at the meeting, the director is not present during the discussion and does not vote on the matter.

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.

Our Code requires employees to receive consent before accepting a directorship with an entity that is not an affiliate. The chief executive officer and executive vice-presidents must receive the consent of the Governance committee. All other employees must receive the consent of their immediate supervisor.

Affiliates
The Board closely oversees relationships between TransCanada and any affiliates to avoid any potential conflicts of interest. This includes our relationship with the TCLP, a master limited partnership listed on the NYSE.

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.

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.

RELEVANT EDUCATION AND EXPERIENCE OF MEMBERS
The members of the Audit committee as of February 19, 2014 are Kevin E. Benson (Chair), Derek H. Burney, Mary Pat Salomone, D. Michael G. Stewart and Richard E. Waugh. Ms. Salomone and Mr. Waugh were appointed members of the Audit committee effective February 12, 2013 and February 1, 2014, respectively.

2013 Annual information form -- 37

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 and Mr. Waugh are Audit Committee Financial Experts 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 advisor at Norton Rose Fulbright. He 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.

Mary Pat Salomone
Ms. Salomone has a Bachelor of Engineering in Civil Engineering from Youngstown State University and a Master of Business Administration from Baldwin Wallace College. She completed the Advanced Management Program at Duke University's Fuqua School of Buiness in 2011. Ms. Salomone was the Senior Vice-President and Chief Operating Officer of the B&W until June 2013. She previously held a number of senior roles with B&W Nuclear, including serving as the Manager of Business Development from 2009 to 2010 and Manager of Strategic Acquisitions from 2008 to 2009, and served as President and Chief Executive Officer of Marine Mechanical Corporation 2001 through 2007, which B&W acquired in 2007.

D. Michael G. Stewart
Mr. Stewart earned a Bachelor of Science in Geological Sciences with First Class Honours from Queen's University. He has served and continues to serve on the boards of several public companies and other organizations and on the audit committee 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 also been active in the Canadian energy industry for over 40 years.

Richard E. Waugh
Mr. Waugh holds a Bachelor of Commerce (Honours) degree from the University of Manitoba and a Master of Business Administration from York University. He is a Fellow of the Institute of Canadian Bankers and has been awarded Honorary Doctor of Laws degrees from York University and Assumption University. Mr. Waugh was Deputy Chairman and a director of Scotiabank. Starting as a branch employee in 1970, he worked in increasingly senior roles at Scotiabank including President from January 2003 to October 2012 and Chief Executive Officer from December 2003 to November 2013. Mr. Waugh also serves on the boards of a number of private and non-profit corporations.

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, all non-audit services have been pre-approved by the Audit committee in accordance with the pre-approval policy described above.

38 -- TransCanada Corporation


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)   2013   2012
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 securities offering documents		   $6.4   $5.7
Audit-related fees
•  services related to the audit of the financial statements of certain TransCanada post-retirement and post-employment plans		   0.2   0.1
Tax fees
•  Canadian and international tax planning and tax compliance matters, including the review of income tax returns and other tax filings		   0.7   0.5
All other fees
•  review of information system design procedures
•  services related to vendor analytics and environmental compliance credits		   —   0.6
Total fees   $7.3   $6.9

Legal proceedings and regulatory actions

Legal proceedings, arbitrations and actions are part of doing business. While we cannot predict the final outcomes of proceedings and actions with certainty, management does not expect any current proceeding or action to have a material impact on our 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.

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 and also that they are independent accountants with respect to TransCanada under all relevant U.S. professional and regulatory standards.

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.

2013 Annual information form -- 39

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 (or plant)   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
Eastern Triangle   Canadian Mainline region between North Bay, Toronto and Montréal
FIT   Feed-in tariff
force majeure   Unforeseeable circumstances that prevent a party to a contract from fulfilling it
GHG   Greenhouse gas
HSE   Health, safety and environment
LNG   Liquefied natural gas
OM&A   Operating, maintenance and administration
PPA   Power purchase arrangement or agreement
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 Update
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
GAAP   U.S. generally accepted accounting principles

Government and regulatory bodies terms

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)
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

40 -- 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.

2013 Annual information form -- 41

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. 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 or prospectus supplement relating to the issuance of debt securities 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 any financial outlook or future-oriented financial information disclosure in advance of its public release; 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 financial projections or presentations to credit rating agencies;
(e)
review with management and the external auditors major issues regarding accounting and auditing policies and practices, including any significant changes in the Company's selection or application of accounting policies, 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;

42 -- TransCanada Corporation

(f)
review and discuss quarterly findings 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 developments as well as any 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 arbitration and 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;
(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 any letter, report or other communication from the external auditors in respect of any identified weakness or unadjusted difference and management's response and follow-up, 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)
receive and review annually the external auditors' formal written statement of independence delineating all relationships between itself and the Company;

2013 Annual information form -- 43

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

    and to report to the Board on such meetings;

(d)
meet with the external auditors prior to the audit to review the planning and staffing of the audit;
(e)
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;
(f)
review and evaluate the external auditors, including the lead partner of the external auditor team;
(g)
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 that were not pre-approved 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;
(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;

44 -- TransCanada Corporation

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

(a)
review and approve annually the Statement of Investment Beliefs for the Company's pension plans;
(b)
delegate the ongoing administration and management of the financial aspects of the Canadian pension plans to the Pension Committee ("Pension Committee") comprised of members of the Company's management team appointed by the Human Resources Committee, in accordance with the Pension Committee Charter, which terms shall be approved by both the Audit Committee and the Human Resources Committee, and the terms of the Statement of Investment Beliefs;
(c)
monitor the financial management activities of the Pension Committee and receive updates at least annually from the Pension Committee on the investment of the Plan assets to ensure compliance with the Statement of Investment Beliefs;
(d)
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;
(e)
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;
(f)
receive, review and report to the Board on the actuarial valuation and funding requirements for the Company's pension plans;
(g)
approve the initial selection or change of actuary for the Company's pension plans;
(h)
approve the appointment or termination of auditors;

IX. U.S. Stock Plans

(a)
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 succession planning for the senior management in finance, treasury, tax, risk, internal audit and the controllers' group; and

XI. Information Security

(a)
review, at least annually, the report of the Chief Information Officer (or such other appropriate Company representative) on information security controls, education and awareness.

XII. 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

2013 Annual information form -- 45


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.

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.

46 -- TransCanada Corporation


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

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

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

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

2013 Annual information form -- 47

ENERGY NATURAL GAS FINANCIAL STRENGTH PEOPLE OIL CONNECTED BY ENERGY // 2013 ANNUAL REPORT OPPORTUNITY TransCanada has expanded its portfolio of commercially secured projects to $38 billion. They are all supported by strong market fundamentals and underpinned by long-term contracts. RESULTS Completion of these initiatives will transform our company. Our footprint, our diversity and our revenues will grow. COMMUNITY

 

2013 FINANCIAL HIGHLIGHTS NET INCOME ATTRIBUTABLE TO COMMON SHARES $1.7 BILLION OR $2.42 PER SHARE COMPARABLE EARNINGS(1) $1.6 BILLION OR $2.24 PER SHARE COMPARABLE EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION AND AMORTIZATION(1) $4.9 BILLION FUNDS GENERATED FROM OPERATIONS(1) $4.0 BILLION CAPITAL EXPENDITURES, EQUITY INVESTMENTS AND ACQUISITIONS $4.8 BILLION COMMON SHARE DIVIDENDS DECLARED $1.84 PER SHARE (1) Non-GAAP measure that does not have any standardized meaning prescribed by generally accepted accounting principles (GAAP). For more information see Non-GAAP measures in the Management’s Discussion and Analysis of the 2013 Annual Report. Forward-Looking Information and Non-GAAP Measures These pages contain certain forward-looking information and also contain references to certain non-GAAP measures that do not have any standardized meaning as prescribed by U.S. generally accepted accounting principles (GAAP) and therefore may not be comparable to similar measures presented by other entities. For more information on forward-looking information, the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, and reconciliations of non-GAAP measures to the most closely related GAAP measures, refer to TransCanada’s 2013 Annual Report filed with Canadian securities regulators and the U.S. Securities and Exchange Commission and available at TransCanada.com. 2,000 1,600 1,200 800 400 2012 2013 2011 Net Income Attributable to Common Shares (millions of dollars) 1,299 1,712 1,526 2,000 1,600 1,200 800 400 Comparable Earnings(1) (millions of dollars) 2012 2013 2011 1,330 1,584 1,559 6,000 5,000 4,000 3,000 2,000 1,000 Comparable EBITDA(1) (millions of dollars) 2012 2013 2011 4,245 4,859 4,544 5,000 4,000 3,000 2,000 1,000 Funds Generated from Operations(1) (millions of dollars) 2012 2013 2011 3,284 4,000 3,451 8,000 6,400 4,800 3,200 1,600 Capital Expenditures, Equity Investments and Acquisitions (millions of dollars) 2012 2013 2011 3,461 4,840 3,146 3 2 1 Comparable Earnings per Share(1) (dollars) 2012 2013 2011 1.89 2.24 2.22 3 2 1 Dividends Declared per Share (dollars) 2012 2013 2011 1.76 1.84 1.68 1,000 800 600 400 200 Common Shares Outstanding – Average (millions of shares) 2012 2013 2011 705 707 702 60 40 50 30 20 10 Market Price – Close Toronto Stock Exchange (dollars) 2012 2013 2011 47.02 48.54 44.53 3 2 1 Net Income per Share – Basic (dollars) 2012 2013 2011 1.84 2.42 2.17

 

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Connecting reliable and affordable sources of energy to markets is the foundation of North America’s prosperous economy and high standard of living. Whether it is natural gas to heat homes and fuel industry, electricity to keep lights on and computers running, or gasoline that moves millions of vehicles every day, nothing is more fundamental to maintaining and enhancing our quality of life. Demand for all forms of energy is steadily growing, and new supplies of oil and gas have led to greater energy security for North America and the possibility of supplying markets abroad. This has opened an era of unprecedented opportunity, as new pipelines, power generation facilities and other energy facilities are required to meet this demand in the future. At the same time, governments, regulators, landowners, Aboriginal and Native American peoples and local communities have greater expectations than ever before when it comes to being engaged in energy infrastructure projects that affect them. Companies must listen and ensure the questions, concerns and interests of stakeholders are addressed early in the process. TransCanada has been safely delivering critical energy products across the continent for more than 60 years and has a solid track record of responsible development, reliable operations, and treating our customers, partners and stakeholders with integrity and respect. This consistent approach has served us well in the past. It is also central to our execution of an unparalleled capital growth plan that is expected to see $38 billion in new projects completed by the end of this decade, generating significant value for our shareholders and benefits for communities across Canada, the United States and Mexico. The market’s confidence in us shows that we are well on our way to achieving our vision of being North America’s leading energy infrastructure company. To get there, we will continue to rely on the foundation of our existing asset base, the industry’s most talented and dedicated employees, and our financial strength and flexibility. We invite you to learn more about our performance and successes in 2013, our unprecedented capital growth plan underway through 2020, and our commitment to doing the right thing in all aspects of our project planning, construction and operation programs. CONNECTED BY ENERGY THE MARKET’S CONFIDENCE IN US SHOWS THAT WE ARE WELL ON OUR WAY TO ACHIEVING OUR VISION OF BEING NORTH AMERICA’S LEADING ENERGY INFRASTRUCTURE COMPANY. 2013 TRANSCANADA ANNUAL REPORT 01

 

A solid Foundation TransCanada plays a vital role in connecting energy supplies to key North American markets with $54 billion in assets in our Natural Gas Pipelines, Energy and oil Pipelines portfolios. Assets We operate one of the largest natural gas transmission networks in North America – 68,500 kilometres (km) (42,500 miles) – tapping into virtually every major gas supply basin and transporting approximately 20 per cent of the continent’s daily natural gas supply. We are North America’s third largest provider of natural gas storage and related services with more than 400 billion cubic feet (Bcf) of storage capacity. We own or have interests in 21 power facilities with the capacity to generate 11,800 megawatts (MW) of electricity, enough to power nearly 12 million homes. One-third of the power we produce comes from emission-less sources including nuclear, hydro, wind and solar. The 4,247-km (2,639-mile) Keystone Pipeline System transports almost one-quarter of Canada’s crude oil exports to the United States. It has safely delivered more than 550 million barrels of Canadian crude oil to markets in the U.S. since it began operation in July 2010. Keystone now includes the Gulf Coast extension, which began transporting crude oil from Cushing, Oklahoma to refineries on the Gulf Coast of Texas in January 2014, providing these refineries with a more stable and less expensive source of oil from U.S. and Canadian producers. PeoPle Our success is a reflection of our exceptional team of approximately 5,500 employees who bring skill, experience, energy and dedication to the work they do every day. Our employees are an important part of the communities where we operate in seven Canadian provinces, 31 U.S. states and six states in Mexico. FinAnciAl cAPAcity We are well positioned to fund our ongoing capital program with growing cash flow from our existing asset base and new assets being placed into service, an ‘A’ grade credit rating and a strong balance sheet. We have invested over $40 billion in new assets since 2000 and our shareholders have been rewarded with an average annual return of 15 per cent. We have invested over $40 billion in new assets since 2000 and our shareholders have been rewarded with an average annual return of 15 per cent. 02 2013 transcanada annual report

 

TransCanada’s credentials in the construction and operation of large-diameter pipelines in extreme climates and terrain are unequalled in North America. Mexico’s Guadalajara natural gas pipeline demonstrated this expertise. GUADALAJARA, MEXICO TransCanada has one of the best pipeline safety and operating records in the industry. Our state-of-the-art control centre monitors our pipelines 24/7. TransCanada has spent an average of $900 million per year over the last three years on pipeline integrity and preventative maintenance programs. OIL CONTROL CENTRE SOLID FOUNDATION THE KEYSTONE PIPELINE SYSTEM TRANSPORTS ALMOST 25% OF CANADA’S CRUDE OIL EXPORTS TO THE UNITED STATES OUR NATURAL GAS PIPELINE SYSTEM DELIVERS APPROXIMATELY 20% OF THE NATURAL GAS CONSUMED IN NORTH AMERICA EACH DAY. TRANSCANADA HAS THE CAPACITY TO GENERATE POWER FOR NEARLY 12 MILLION HOMES. 21 POWER FACILITIES 11,800 MW 12M 2013 TRANSCANADA ANNUAL REPORT 03

 

Delivering Strong Results 2013 was a successful year for TransCanada, marked by growth in earnings and cash flow and the capture of a record level of new capital projects, including the $12 billion Energy East Pipeline – the largest project in our history. Comparable earnings increased 19 per cent to $1.6 billion or $2.24 per share and funds generated from operations were up 22 per cent to $4.0 billion. The strong year-over-year results reflect a return to an eight unit site at Bruce Power, higher Western Power volumes, an increase in New York capacity prices, growth in our NGTl System, and a higher Canadian Mainline return on equity. Our Board of directors also declared a quarterly dividend of $0.48 per common share for the quarter ending March 31, 2014, equivalent to $1.92 per common share on an annualized basis, an increase of four per cent. This is the fourteenth consecutive year the Board of directors has raised the dividend. A total of $3.5 billion in new assets began contributing to earnings in 2013, beginning with the return to service of Bruce Power Units 1 and 2. for the first time in nearly two decades, all eight of Bruce Power’s nuclear reactors are operating simultaneously, providing 6,200 MW of emission-less power and supplying Ontario with more than 30 per cent of its electricity. We acquired the first four of nine solar generation facilities in Ontario, with the remaining five facilities expected to come on-line in 2014, further expanding the company’s renewable energy portfolio. In addition, the Sundance A power facility in Alberta returned to service after the operator was ordered to rebuild two units that were shut down, providing us with the 560 MW of power we are entitled to under a power purchase agreement. Several pipeline projects also progressed during 2013, and key settlements and decisions were reached that will provide clarity and stability for our natural gas pipelines in the coming years. Approximately $700 million in new facilities began service on the NGTl System in northern Alberta and northeast British Columbia as part of a $2.7 billion expansion program. In November, construction wrapped up on the Gulf Coast Project, a 780-km (485-mile) pipeline that transports crude oil from the primary U.S. crude oil storage hub at Cushing, Oklahoma to refineries on the Gulf Coast of Texas. This southern extension of the Keystone Pipeline System began service on January 22, 2014, following successful commissioning and line fill activities. The gulf coast project, a 780-km (485-mile) pipeline that transports crude oil from cushing, oklahoma to refineries on the gulf coast of texas, began operations on january 22, 2014. 04 2013 transcanada annual report

 

We continue to advance the Keystone xl Pipeline Project, which has now been under regulatory review by the United States government for more than five years. The U.S. department of State (DOS) released the final Supplemental environmental Impact Statement on the project on January 31, 2014, which concluded the pipeline will have minimal impact on the environment. This finding was consistent with the results of four previous environmental reviews dating back to 2010. The dOS has now entered a 90-day National Interest determination period for Keystone xl. We are optimistic the project will be approved in 2014 since it will greatly enhance America’s energy security and create more than 9,000 direct jobs for skilled American workers over two years of construction. In March, Canada’s National energy Board (NeB) released its decision on our proposal for restructuring tolls and services on the Canadian Mainline following an extensive public hearing. The decision fundamentally altered some of the long-standing principles of the Mainline’s regulated cost-of-service model. TransCanada successfully implemented the NeB decision and shippers have renewed 2.5 Bcf per day of firm contracts on the system through November 2016. In the fall of 2013 we reached a settlement with local natural gas distribution companies in Ontario and Québec that will allow us to continue expanding the eastern portion of the Mainline system to meet the future needs of this growing market. Settlements were also reached with shippers on the NGTl and Great lakes systems in 2013. capturing opportunities It was also a banner year for securing new growth opportunities, as we commercially secured $19 billion of new projects that are underpinned by long-term contracts with our customers. In January, we were selected by Progress energy Canada ltd. to build, own and operate the proposed $5 billion Prince rupert Gas Transmission project, a 750-kilometre (466-mile) pipeline to transport natural gas from northeastern B.C. to the Pacific Northwest lNG export facility planned near Prince rupert. We are also proceeding with the $1.7 billion North Montney project that will expand the NGTl System and connect with the Prince rupert Gas Transmission pipeline. In August, we announced we will For the first time in two decades, all eight of Bruce Power’s nuclear reactors are operating simultaneously, providing 6,200 MW of emission-less power and supplying ontario with more than 30 per cent of its electricity. Bruce Power 2013 transcanada annual report 05

 

TransCanada reached binding long-term agreements to proceed with the $900 million Heartland Pipeline and TC Terminals projects connecting a storage terminal in the Heartland industrial area north of Edmonton, Alberta with our facilities in Hardisity, Alberta. CONNECTING EDMONTON WITH HARDISTY 06 2013 TRANSCANADA ANNUAL REPORT

 

MB AB BC YT SK NT NU ON QC PE NB NS HARDISTY MOOSOMIN MONTRÉAL SAINT JOHN LÉVIS CACOUNA proceed with the $12 billion Energy East Pipeline Project, an innovative project that will convert 3,000 km (1,800 miles) of existing natural gas pipeline in the Canadian Mainline to oil transportation between Alberta and Ontario and build 1,600 km (994 miles) of new pipeline to transport up to 1.1 million barrels per day of crude oil from Western Canada to Eastern Canadian refineries and two export marine terminals. We began initial public consultation, design and engineering work on Energy East Pipeline Projects in 2013 and expect to file an application for the project with the NEB in mid-2014. We also reached binding long-term agreements to proceed with the $900 million Heartland Pipeline and TC Terminals projects that will support growing crude oil production in Alberta with a storage terminal in the Heartland industrial area north of Edmonton, Alberta and a pipeline to connect with our facilities in Hardisty, Alberta. Energy East Pipeline Project proposed route. The existing gas pipeline system consists of several individual pipes running parallel with each other. This project will entail the conversion of just one of those individual pipes. EnErgy East PiPElinE ProjEct IT WAs AlsO A BANNEr yEAr fOr sECurINg NEW grOWTH OPPOrTuNITIEs, As WE COMMErCIAlly sECurEd $19 BIllION Of NEW PrOjECTs THAT ArE uNdErPINNEd By lONg-TErM CONTrACTs WITH Our CusTOMErs. $12 billion EnErgy EasT PiPElinE ProjEcT bEnEfiTs all canadians This projecT will produce $35 Billion of Gross doMesTic producT for canada’s econoMy. The enerGy easT pipeline will GeneraTe $10 Billion in Tax revenues for all levels of GovernMenT in The counTry. = NEW PIPELINE CONSTRUCTION = EXISTING PIPELINE CONvERSION = TERMINALS = RECEIPT/DELIvERy POINTS The $12 Billion projecT could eliMinaTe canada’s reliance on 700,000 BBl/d of crude oil iMporTed froM overseas By replacinG iT wiTh wesTern canadian crude, alonG wiTh supporTinG easTern canadian refineries. iT will creaTe More Than 10,000 direcT, full-TiMe joBs. 2013 transcanada annual report 07

 

The scope of TransCanada’s growth plan is truly unprecedented, with $38 billion in capital projects that will transform the company and position it as a leader in each of our core business areas. Subject to required approvals and final investment decisions by our partners, our asset base will grow by almost one-half to approximately $80 billion of long-life assets that are predominantly supported by long-term contracts or regulated cost-of-service arrangements when complete by the end of the decade. earnings before interest, taxes, depreciation and amortization (EBITDA) from these projects and existing assets are expected to almost double, reaching approximately $9.5 billion by 2020. oil PiPelines North America’s crude oil production is anticipated to increase four million barrels per day by 2020, the majority of which is expected to come out of Western Canada, the Bakken formation in the Williston Basin, and the eagle ford formation in Texas, where we are well positioned. Oil pipelines are expected to provide approximately 40 per cent of our eBITdA by the end of the decade. A network of 11,400 km (7,000 miles) of high-capacity pipelines will be capable of moving approximately 2.5 million barrels per day – half of Western Canada’s forecasted production – to refining markets and export terminals in Canada and the United States. It will also include 29 million barrels of oil storage capacity and two marine terminals. We have $23 billion in oil pipeline projects planned or in development. Once complete, the Keystone Pipeline System, including Keystone xl and the Gulf Coast extension, will have capacity to transport 1.4 million barrels of Canadian and U.S.-produced crude oil per day. The $12 billion energy east Pipeline Project is also underpinned by long-term contracts to ship approximately 900,000 barrels per day when it begins service to Québec in early 2018 and to New Brunswick later that year and will allow Canadian refineries to eliminate their reliance on more expensive crude oil imported from overseas. We are also proceeding with $3.5 billion in projects to expand Alberta’s crude oil pipeline gathering network, including the Grand rapids, heartland and Northern Courier pipeline projects, as well as new terminal facilities at hardisty, Alberta and the heartland region north of edmonton. BRIGHT FUTURE AHEAD OIL PIPELINES ARE EXPECTED TO PROVIDE APPROXIMATELY 40 PER CENT OF OUR EBITDA BY THE END OF THE DECADE. 08 2013 transcanada annual report

 

Natural gAs PiPelines North America’s demand for natural gas is expected to grow by 15 Bcf/d by 2020, presenting opportunities for growth along with challenges related to low prices and changing flow patterns on some existing pipeline systems. We have $13 billion in projects under development to connect new supplies with domestic and overseas markets and expect eBITdA from natural gas pipeline assets to represent approximately 45 per cent of our eBITdA by 2020. Most notably, the Coastal Gaslink and Prince rupert Gas Transmission pipeline projects represent $9 billion of infrastructure investment in support of British Columbia’s emerging liquefied natural gas (lNG) export opportunity and are supported by long-term contracts with major international energy companies. route selection, public engagement and environmental assessments are well underway for both of these high-profile projects, with final investment decisions from the project backers expected in late-2014 and 2015. TransCanada has $13 billion in natural gas projects under development to connect new supplies with domestic and overseas markets and expects EBiTdA from these and existing assets to represent approximately 45 per cent of our EBiTdA by 2020. NATURAL GAS PIPELINE NETWORK OIL PIPELINE NETWORK A NETWORK OF 11,400 KM (7,000 MILES) OF HIGH-CAPACITY PIPELINES WILL BE CAPABLE OF MOVING APPROXIMATELY 2.5 MILLION BARRELS PER DAY – HALF OF WESTERN CANADA’S FORECASTED PRODUCTION. 2020 ASSET OUTLOOK OUR ASSET BASE WILL GROW BY APPROXIMATELY 50% TO APPROXIMATELY $80 BILLION OF LONG-LIFE ASSETS THAT ARE PREDOMINANTLY SUPPORTED BY LONG-TERM CONTRACTS OR REGULATED COST-OF-SERVICE ARRANGEMENTS, WHEN COMPLETE BY THE END OF THE DECADE.* oil Gas ToTal $13B $30B $35B $25B $15B $16B $80B $54B EnErGy 2020 EBiTdA ouTlook earninGs Before inTeresT, Taxes, depreciaTion and aMorTizaTion (eBiTda) froM These operaTions and exisTinG asseTs are expecTed To alMosT douBle, reachinG approxiMaTely $9.5 Billion By 2020.* $3.9B oil $4.2B $2.8B $0.8B Gas $1.4B $1.3B EnErGy $9.5B $4.9B ToTal = 2013 = 2020 BoTh asseTs and eBiTda ouTlooKs include exisTinG asseTs and $38 Billion of coMMercially secured projecTs expecTed To Be in-service By 2020, suBjecT To various condiTions includinG corporaTe and reGulaTory approvals. * 2013 transcanada annual report 09

 

Mexico is also an increasingly important region for us, with US$1.9 billion in new natural gas pipeline projects underway under 25-year contracts with Mexico’s state electricity company. When complete in 2016, the Mazatlan and Topolobampo pipelines in Western Mexico, along with our expanded Tamazunchale pipeline and Guadalajara pipeline will increase our asset base in the country to US$2.5 billion. Our growing presence and experience in successfully completing projects in Mexico ensures we are well positioned to capture additional growth opportunities as the country shifts towards natural gas as a cleaner and more economical source of power. Meanwhile, we are working to ensure existing natural gas pipeline assets are maximized and realizing their greatest value. The Canadian Mainline continues to be a critical piece of natural gas infrastructure, supplying close to 4 Bcf/d to high-population markets in eastern Canada and the Northeastern U.S. TransCanada will ensure there is sufficient pipeline capacity to meet the current and future needs of eastern Canadian gas consumers and that gas transmission costs on the Mainline are no higher as a result of converting some Mainline capacity to crude oil service for the energy east Pipeline Project. Some of our U.S. natural gas pipelines continue to be challenged by changing market dynamics. We have responded by restructuring and reducing operating costs on these systems, along with pursuing new opportunities to connect growing production from shale gas basins including the Marcellus and Utica. ENERGY North America’s demand for electricity continues to grow by approximately one per cent per year and efforts to transition to less carbon intense forms of power generation are well aligned with our expertise in building and operating highly efficient natural gas-fired and renewable energy facilities. We are already Canada’s largest private-sector power generator and will add another 900 MW of gas-fired generation capacity when the Napanee Generating Station in eastern Ontario begins service in late 2017 or early 2018. To date, TransCanada has invested over $5 billion in renewable energy sources. Thirty per cent of the energy TransCanada produces is emission-less, including the largest wind developments in Maine and Canada, 13 hydro power facilities in the u.s. Northeast, along with solar and nuclear. cArtier wind energy OUR GROWING PRESENCE AND EXPERIENCE IN SUCCESSFULLY COMPLETING PROJECTS IN MEXICO ENSURES WE ARE WELL POSITIONED TO CAPTURE ADDITIONAL GROWTH OPPORTUNITIES AS THE COUNTRY SHIFTS TOWARDS NATURAL GAS AS A CLEANER AND MORE ECONOMICAL SOURCE OF POWER. 10 2013 transcanada annual report

 

The project has a 20-year power purchase agreement with the Ontario Power Authority to support the $1 billion project that will create hundreds of jobs over several years of construction and bring economic benefits to Greater Napanee for decades to come. We also continue to expand our portfolio of renewable energy sources with the addition of nine new solar generation facilities coming on-line in 2013 and 2014 in Ontario, all under long-term contract with the Ontario Power Authority. Solar generation is complemented by our ownership of the largest wind developments in Canada and Maine, along with several historic hydropower generating stations on the Connecticut and deerfield rivers in New england. We will continue to pursue additional opportunities for new power generation assets in our established market areas. The Alberta power market is undergoing unprecedented demand growth. In addition, there is the expected removal of critical base-load supplies with the planned retirement of coal-fired generation beginning near the end of the decade. Both represent key opportunities for us. There is also the potential for new opportunities for power generation projects in Mexico and in the U.S. and Canada that we will continue to consider. NORTH AMERICA’S DEMAND FOR ELECTRICITY CONTINUES TO GROW BY APPROXIMATELY ONE PER CENT PER YEAR AND EFFORTS TO TRANSITION TO LESS CARBON INTENSE FORMS OF POWER GENERATION ARE WELL ALIGNED WITH OUR EXPERTISE IN BUILDING AND OPERATING HIGHLY EFFICIENT NATURAL GAS-FIRED AND RENEWABLE ENERGY FACILITIES. TRANSCANADA IS ALREADY CANADA’S LARGEST PRIVATE-SECTOR POWER GENERATOR AND WILL ADD ANOTHER 900 MW OF GAS-FIRED GENERATION CAPACITY WHEN THE NAPANEE GENERATING STATION IN EASTERN ONTARIO BEGINS SERVICE IN LATE 2017 OR EARLY 2018. (ARTIST ILLUSTRATION) NAPANEE GENERATING STATION POWER ASSETS BY FUEL SOURCE TRANSCANADA GENERATES POWER FROM A VARIETY OF SOURCES. FUEL MIX 11,800 MW NATURAL GAS NATURAL GAS/OIL NUCLEAR COAL HYDRO WIND SOLAR 1% 4% 5% 14% 34% 21% 21% CARTIER WIND IS THE LARGEST WIND DEVELOPMENT IN CANADA. TRANSCANADA IS A 62% OWNER IN THE $1.1 BILLION FACILITY IN QUÉBEC. APPROXIMATELY ONE-THIRD OF THE POWER WE PRODUCE COMES FROM EMISSIONLESS ENERGY. TRANSCANADA OWNS 13 HYDROELECTRIC FACILITIES IN NEW HAMPSHIRE, VERMONT AND MASSACHUSETTS, PRODUCING 583 MEGAWATTS OF CLEAN ELECTRICITY. MW 2013 TRANSCANADA ANNUAL REPORt 11

 

TransCanada’s 60-year record of safety and reliability, combined with our dedication to respectful co-operation and giving back to the communities wherever we do business, has made us the partner of choice for large-scale energy development across North America. We are guided by our values of Integrity, responsibility, Collaboration and Innovation. every employee is expected to demonstrate these values on a daily basis in all of their dealings with colleagues, customers, landowners, government leaders and other stakeholders, as well as with Aboriginal and Native American and Indigenous communities. Getting it right is more important than ever when it comes to safety, stakeholder relations, minimizing environmental impact and operating in a sustainable manner. We perform at the top of our class in these areas, but we recognize the need to continually improve how we undertake our projects in order to realize our vision of becoming North America’s leading energy infrastructure company. That’s why our Corporate Social responsibility (CSR) department spent much of 2013 formalizing our efforts and moving towards greater rigour and transparency when it comes to reporting on our performance publicly. The results of this work will be reflected in the company’s annual CSr reports going forward. We continue to be recognized for our efforts. for the twelfth year in a row, we were named to the dow Jones Sustainability World Index. for the second year in a row, we were among Canada’s top 200 companies on the Climate disclosure leadership Index and we improved our rating when it comes to reporting on greenhouse gas emissions and climate change initiatives. In addition to creating jobs and generating economic growth across North America as part of developing our $38 billion capital program, we are committed to the communities where we live and work. In 2013, we contributed more than $11 million to non-profit organizations across North America. Our dedication to responsible energy development and safe and reliable operations is the foundation for how we will build and maintain the social acceptance that is critical to ensuring we can continue to successfully develop North America’s energy future. We are committed to conducting our business in an ethical manner that will deliver sustainable, long-term value for our shareholders. CONNECTED WITH COMMUNITIES OUR DEDICATION TO RESPONSIBLE ENERGY DEVELOPMENT AND SAFE AND RELIABLE OPERATIONS IS THE FOUNDATION FOR HOW WE WILL BUILD AND MAINTAIN THE SOCIAL ACCEPTANCE THAT IS CRITICAL TO ENSURING WE CAN CONTINUE TO SUCCESSFULLY DEVELOP NORTH AMERICA’S ENERGY FUTURE. 12 2013 transcanada annual report

 

Good neighbours help out. Our Community Investment Program seeks to do just that. We directly support not-for-profit organizations, like Habitat for Humanity, and seek partnerships or other ways to leverage our contributions. BUILDING HOMES IN HOUSTON, TEXAS Employees from TransCanada’s Ravenswood Generating Station in Queen’s, New York have teamed up with the Riis Settlement Society to provide basic asthma screening, consultations and referrals from healthcare professionals. The Queensbridge neighbourhood has the highest child asthma rates in the city. FIGHTING ASTHMA IN NEW YORK CITY: (image left) Environmental field studies involve the identification of trees along our proposed right-of-way that bear marks that are important to Aboriginal people. These marks can be simple way-finding signs or have significant spiritual meaning. We often build or operate facilities near Aboriginal, Native American or Indigenous communities. We work hard to build positive relationships and focus on ensuring community impacts are minimized. ENVIRONMENTAL STUDIES IN NORTHERN BRITISH COLUMBIA COMMUNITY CONTRIBUTIONS NEW YORK IN NEW YORK CITY, WE HELPED LAUNCH THE GROWING GREEN! PROGRAM TO IMPROVE EDUCATION ABOUT ENVIRONMENTAL ISSUES AND SUSTAINABILITY FOR SCHOOL-AGED CHILDREN. HOPE AIR IN NORTHERN BRITISH COLUMBIA, WE PROVIDED SUPPORT FOR HOPE AIR, A CHARITY GROUP DEDICATED TO ASSISTING FAMILIES DEALING WITH THE HIGH COSTS OF TRAVEL TO RECEIVE NECESSARY MEDICAL TREATMENT. FIRE CHIEFS WE ENTERED INTO A FOUR-YEAR PARTNERSHIP WITH THE INTERNATIONAL ASSOCIATION OF FIRE CHIEFS TO DEVELOP EDUCATION AND TRAINING PROGRAMS TO IMPROVE EMERGENCY RESPONSE AND PREPAREDNESS RELATED TO ENERGY AND PIPELINE FACILITIES. 2013 TRANSCANADA ANNUAL REPORT 13

 

LETTER TO SHAREHOLDERS Our assets performed well, we resolved many of the headwinds constraining our performance and we are now working on numerous, high quality, commercially secured projects from Alaska to Mexico, from the Pacific Coast to the tip of New Brunswick and many places in between. We are building North America’s energy future and we are very proud of what we accomplished this year. Twenty-thirteen is perhaps most appropriately described as a year of unprecedented opportunity as TransCanada announced $19 billion of new projects. The list includes the largest initiative the company has ever undertaken – the $12 billion energy east Project. It will convert 3,000 kilometres (km) of our Canadian Mainline from natural gas to oil transportation and include 1,500 km of new pipeline. energy east will deliver 1.1 million barrels of crude oil a day to eastern Canadian refineries and export markets beginning in 2018. Other important initiatives announced in 2013 include: the $5 billion Prince rupert Gas Transmission Project (PRGT) that will transport natural gas for export off the coast of British Columbia; the $1.7 billion North Montney extension that will expand the NGTl system and connect with PRGT; and the $900 million heartland Pipeline and TC Terminals project with capacity to transport up to 900,000 barrels per day and store 1.9 million barrels of oil within Alberta. As a result of capturing these opportunities, TransCanada has expanded its portfolio of commercially secured projects to $38 billion. They are all supported by strong market fundamentals and underpinned by long-term contracts or the revenue stability of cost-of-service regulation. Completion of these initiatives will transform our company. Our footprint, our diversity and our revenues will grow. We expect these projects will lead to a doubling of EBITDA – earnings before interest, taxes, depreciation and amortization – by the end of the decade, providing a foundation for increased earnings, dividends and shareholder value to and beyond 2020. It is one thing to capture opportunities; it is another for proposed projects to become operational. At TransCanada we have a 60-year history of safely and efficiently bringing new facilities into service. Our construction teams again demonstrated that discipline in 2013 as $3.5 billion of new assets were brought on-line. This marked the first time in decades that a full set of eight reactors were running at Bruce Power. As well, we have now brought four of nine Ontario solar facilities into service, along with numerous NGTl system expansions as we continue to capture the majority of the new natural gas production in northeast British Columbia and northwest Alberta. In late January 2014, our employees completed construction of the US$2.6 billion Gulf Coast Project, the southern extension of Keystone designed to transport up to 700,000 barrels a day of crude oil to Texas refineries – an important milestone for Our vision is to be the leading energy infrastructure company in North America and in 2013 we took another significant step toward achieving this vision. TransCanada has expanded its portfolio of commercially secured projects to $38 billion with $19 billion secured in 2013. russell K. GirlinG President & Chief Executive Officer 14 2013 transcanada annual report // LETTER TO SHAREHOLDERS

 

our emerging oil transportation business. Also in late January, we received a positive final Supplemental environmental Impact Statement from the U.S. department of State. While this has taken much more time than expected I remain confident this will ultimately lead to the approval of Keystone XL in 2014. In both the construction and operation of our assets, our top priority is the safety of our employees, our contractors and the communities where we operate. While 2013 saw unprecedented growth in hours worked and miles driven, our safety performance remained in the top decile of our industry. While I am proud of this performance, we can and we will do better. Our objective is to be incident free and we will continue to relentlessly push to achieve this objective. The path to better performance is ingrained in the strong safety culture that permeates throughout TransCanada. A well-honed safety culture is the only way to ensure everyone in the organization makes decisions based on the same fundamental values and beliefs. We encourage people to err on the side of caution, and our employees and contractors are supported and rewarded for doing so. We can make up lost dollars but we can’t ever repair the damage and devastation of a catastrophic event and the impact it can have on families. At TransCanada, I’m very comfortable we are on this path. New projects, improved performance from existing assets and recovering commodity prices all contributed to a strong financial performance in 2013. This year we reported comparable earnings of $2.24 per share, which is a 19 per cent increase over last year. funds generated from operations were $4 billion, a 22 per cent rise from 2012. As we have always said, sustained, visible growth in cash flow and earnings will lead to steady growth in dividends. 2014 is the 14th consecutive year TransCanada’s Board has raised the common share dividend resulting in a compound annual growth rate of seven per cent over that period. looking forward, we remain focused on four simple priorities. first, maximize the value of our $54 billion blue-chip portfolio of assets and continue to operate them safely and reliably – that’s what we do, that’s what our customers expect. Second, we will advance our $38 billion portfolio of new projects through permitting and construction to operation. Third, we will maintain our financial strength, discipline and flexibility in order to fund our growth. finally, we’ll continue to pursue low-risk growth projects, both through acquisition and development in our three core businesses in geographies where we have or can develop a sustainable, competitive advantage. Our ability to manage complex stakeholder matters has always been one of our strengths, something that is rooted in our core values of respect and integrity. In this new world of activists working to prevent new, critical energy infrastructure from being built, along with rising stakeholder expectations, this capability has become our competitive advantage. Customers are telling us they cannot afford to risk their brand by partnering with infrastructure operators who don’t have the ability to navigate these challenging and difficult waters. TransCanada has a 60-year history and reputation of fairly dealing with all stakeholders, being honest and transparent, and solving issues when they arise – that will continue. Since the year 2000, we have invested approximately $40 billion in long-life energy infrastructure assets in our three core businesses, and we are positioned to confidently and prudently deliver on that again before the end of the decade. I have great confidence in the senior leadership of our company and in our 5,500 employees – they will get the job done. They are simply the best at what they do and I am proud of their many accomplishments. We will continue to deliver safe, reliable energy for millions of people, and generate superior risk-adjusted returns for our shareholders for many decades to come. Our top priority is the safety of our employees, our contractors and the communities where we operate. Our safety performance remained in the top decile of our industry. LETTER TO SHAREHOLDERS // 2013 transcanada annual report 15

 

Our employees live by our values of Integrity, Responsibility, Collaboration and Innovation. OUR VALUES 16 2013 TRANSCANADA ANNUAL REPORT // EXECUTIVE LEADERSHIP TEAM

 

EXECUTIVE LEADERSHIP TEAM Both of these executives in his own way have contributed greatly to the success of TransCanada. It has been my privilege to work with Sean and Greg over many years. I extend my sincere personal thanks to them and wish them well in their future endeavours. – RUSS GIRLING EXECUTIVE VICE-PRESIDENTS, RETIRED FEBRUARY 28, 2014: RUSS GIRLING President and Chief executive Officer JIM BaGGs executive vice-President, Operations and engineering Bill taylor executive vice-President and President, energy don marchand executive vice-President and Chief financial Officer KRISTINE DELKUS executive vice-President and General Counsel paul miller executive vice-President and President, liquids Pipelines Wendy hanrahan executive vice-President, Corporate Services dennis mcconaGhy executive vice-President sean mcmaster executive vice-President, Stakeholder relations and General Counsel Karl Johannson executive vice-President and President, Natural Gas Pipelines alex pourBaix executive vice-President and President, development GreG lohnes executive vice-President, Operations and Major Projects EXECUTIVE LEADERSHIP TEAM // 2013 transcanada annual report 17

 

The capture of $19 billion of new projects last year adds to the existing development portfolio of pipelines to deliver natural gas from Alberta and B.C. that will be liquefied and exported off the West Coast, further Alberta oil pipeline development, emission-free power in Ontario, and the growth of our natural gas infrastructure in Mexico. This takes the total portfolio of projects under development in the company today to $38 billion – an unprecedented level. The Energy East Pipeline, the largest of those projects, has been billed as a true ‘nation building’ project similar to the Canadian Pacific Railway, the TransCanada Highway and our own Canadian Mainline. By delivering Western Canadian crude oil to Central and Eastern Canada, it creates yet another scenario where all Canadians can share in the benefits of responsibly developing our nation’s resources. Execution of major projects in today’s environment is ever more challenging and these projects will test the capacity of the organization at all levels, including the Board, over the next few years. TransCanada’s governance – the processes and decisions that support and define the company’s activities, grant power and verify performance – remains vitally important and an area of constant focus externally and internally. In 2013, the company was listed on the Dow Jones Sustainability (DJSI) World Index for the twelfth straight year. The DJSI measures sustainability performance by gauging economic, environmental and social contributions and is an important benchmark for TransCanada. In addition to the DJSI and other governance recognition, TransCanada was also identified as one of the top Canadian companies in the Climate Disclosure Leadership Index, ranking eighth among 200 of Canada’s biggest companies. The index noted the company’s commitment to the issue of climate change; CO2 emissions savings; refurbishing major assets; groundbreaking research in carbon reduction; and investments in solar power. Internally, we are continuing the board transition and renewal that started in 2012; a process that will see eight directors retire between 2012 and 2015. John McNaughton announced his retirement early in 2013 for health reasons and we were all saddened by his passing in February of last year. Dr. Linn Draper retired in the spring of 2013 as planned, and Dr. Paul Joskow also announced his retirement this past spring. Thomas Stephens will be retiring at the annual shareholders’ meeting after many years of dedicated service to shareholders. New additions to the Board last year included Mary Pat Salomone and John Richels. This year, Siim A. Vanaselja is being nominated to the Board for the first time and brings extensive experience in accounting and finance, governance, management and risk management. TransCanada and our entire Board have benefited from the quality counsel those directors who left the organization provided. Looking forward, we are appreciative of the fresh ideas and guidance already offered by new Board members. We are grateful to have Paule Gauthier and Derek Burney agree to extend their tenure on the Board for an additional year to provide guidance on projects such as Energy East and to allow for continuity at the Board during its transition. On behalf of the Board, I would like to thank the staff for their efforts and successes over the last year. Our employee population has never been more diverse in terms of age, geography, culture and expertise. Since 2012 we have welcomed more than 1,000 new employees to TransCanada and it is those employees along with their existing 4,500 colleagues and the company’s senior leadership team who will allow us to continue to build on past successes and optimize and enhance future shareholder value for decades to come. CHAIRMAN’S MESSAGE 2013 could very well mark the start of one of the most transformative periods in TransCanada’s history. S. BARRY JACKSON 18 2013 TRANSCANADA ANNUAL REPORT // CHAIRMAN’S MESSAGE

 

 

Management's discussion and analysis

 
 

February 19, 2014

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, 2013.

This MD&A should be read with our accompanying December 31, 2013 audited comparative consolidated financial statements and notes for the same period, which have been prepared in accordance with U.S. generally accepted accounting principles (GAAP).

 
 
 


Contents

ABOUT THIS DOCUMENT   2
ABOUT OUR BUSINESS   4
  •  Three Core Businesses   4
  •  A long-term strategy   7
  •  2013 financial highlights   9
  •  Outlook   14
  •  Non-GAAP measures   15
NATURAL GAS PIPELINES   19
OIL PIPELINES   35
ENERGY   45
CORPORATE   65
FINANCIAL CONDITION   67
OTHER INFORMATION   76
  •  Risks and risk management   76
  •  Controls and procedures   82
  •  CEO and CFO certifications   83
  •  Critical accounting estimates   83
  •  Financial instruments   86
  •  Accounting changes   89
  •  Quarterly results   90
GLOSSARY   96

2013 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 19, 2014 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 and future financing options available to us
•
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 impact of regulatory 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 accounting changes, 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 financings 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 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
•
costs for labour, equipment and materials
•
access to capital markets
•
interest and foreign exchange rates
•
weather
•
cyber security
•
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).

As actual results could vary significantly from the forward-looking information, 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 165 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).

2013 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 $54 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.

GRAPHIC

4 -- TransCanada Corporation

GRAPHIC

2013 Management's discussion and analysis -- 5
at December 31
(millions of $)		 2013 2012 per cent
change		    
Total assets          
Natural Gas Pipelines 25,165 23,210 8%    
Oil Pipelines 13,253 10,485 26%    
Energy 13,747 13,157 4%    
Corporate 1,733 1,544 12%    
   
  53,898 48,396 11%    

GRAPHIC

 
 
year ended December 31
(millions of $)		 2013 2012 per cent
change		    
Total revenue          
Natural Gas Pipelines 4,497 4,264 5%    
Oil Pipelines 1,124 1,039 8%    
Energy 3,176 2,704 17%    
   
  8,797 8,007 10%    

GRAPHIC

 
 
year ended December 31
(millions of $)		 2013   2012   per cent
change		    
Comparable EBIT 1              
Natural Gas Pipelines 1,839   1,808   2%    
Oil Pipelines 603   553   9%    
Energy 1,069   620   72%    
Corporate (124 ) (111 ) 12%    
   
  3,387   2,870   18%    
1
Comparable EBIT is a non-GAAP measure – see page 15 for details.

GRAPHIC

 

Share price of our common shares
at December 31

GRAPHIC

Common shares outstanding – average

(millions)        
2013   707    

2012
 
705
 
 

2011
 
702
 
 
 
as at February 14, 2014
Common shares		 Issued and outstanding  
  707 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
Series 7 24 million 24 million Series 8 preferred shares
Series 9 18 million 18 million Series 10 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, long-term power sale agreements and shorter-term power sales to wholesale and load customers are used to manage and optimize our portfolio and to manage price volatility.
2 Commercially develop and build new asset investment programs
 
Our strategy at a glance
 
 
 

•  We are developing high quality, long-life projects under our current $38 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 returns to shareholders.

•  As part of our growth strategy, we rely on this experience and our regulatory, commercial, financial, legal and operational expertise to successfully build and integrate new energy and pipeline facilities.

•  Our growing investment in natural gas, nuclear, wind, hydro and solar generating facilities demonstrates our commitment to clean, sustainable energy.
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 assess opportunities to acquire and develop energy infrastructure that complements our existing portfolio and provides access to attractive supply and market regions.

•  We will advance selected opportunities to full development and construction when market conditions are appropriate and project risks and returns 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 us our competitive edge.

•  Strong leadership: scale, presence, operating capabilities, strategy development; expertise in regulatory, legal, commercial 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 sizable 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.

2013 Management's discussion and analysis -- 7

$38 billion capital program
We are developing quality projects under our long-term $38 billion capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties and are expected to generate significant growth in earnings and cashflow.

Our $38 billion capital program is comprised of $12 billion of small to medium-sized projects and $26 billion of large scale projects. Amounts presented exclude the impact of foreign exchange and capitalized interest.

at December 31, 2013
(billions of $)		   Expected
In-Service Date		   Estimated
Project Cost		   Amount Spent
Small to medium-sized projects            
Gulf Coast Project1   January 2014   US 2.6   US 2.3
Ontario Solar   2014   0.5   0.2
Tamazunchale Extension   2014   US 0.5   US 0.4
Houston Lateral and Terminal   2015   US 0.4   US 0.1
Heartland and TC Terminals   2016   0.9   -
Keystone Hardisty Terminal   2016   0.3   0.1
Topolobampo   2016   US 1.0   US 0.4
Mazatlan   2016   US 0.4   US 0.1
Grand Rapids2   2015-2017   1.5   0.1
Northern Courier   2017   0.8   0.1
NGTL System   2014-2018   2.0   0.2
Napanee   2017 or 2018   1.0   -
        11.9   4.0
Large scale projects3            
Keystone XL4   Approximately 2 years from date permit received   US 5.4   US 2.2
Energy East5   2018   12.0   0.2
Prince Rupert Gas Transmission   2018   5.0   0.1
Coastal GasLink   2018+   4.0   0.1
        26.4   2.6
        38.3   6.6
1
Commercial in-service date of January 22, 2014.

2
Represents our 50 per cent share.

3
Subject to cost adjustments due to market conditions, route refinement, permitting conditions and scheduling.

4
Estimated project cost will increase depending on the timing of the Presidential permit.

5
Excludes transfer of Canadian Mainline gas assets.

8 -- TransCanada Corporation

2013 FINANCIAL HIGHLIGHTS
We use certain financial measures that do not have a standardized meaning under 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.

Highlights
Comparable EBITDA (comparable earnings before interest, taxes, depreciation and amortization), comparable EBIT (comparable earnings before interest and taxes), comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See page 15 for more information about the non-GAAP measures we use and a reconciliation to their GAAP equivalents.

year ended December 31
(millions of $, except per share amounts)		   2013   2012   2011
Revenue   8,797   8,007   7,839
Comparable EBITDA   4,859   4,245   4,544
Net income attributable to common shares   1,712   1,299   1,526
  per common share – basic and diluted   $2.42   $1.84   $2.17
Comparable earnings   1,584   1,330   1,559
  per common share   $2.24   $1.89   $2.22

Operating cash flow
 
 
 
 
 
 
Funds generated from operations   4,000   3,284   3,451
(Increase)/decrease in working capital   (326)   287   235
Net cash provided by operations   3,674   3,571   3,686

Investing activities
 
 
 
 
 
 
Capital expenditures   4,461   2,595   2,513
Equity investments   163   652   633
Acquisitions, net of cash acquired   216   214   -

Balance sheet
 
 
 
 
 
 
Total assets   53,898   48,396   47,338
Long-term debt   22,865   18,913   18,659
Junior subordinated notes   1,063   994   1,016
Preferred shares   1,813   1,224   1,224
Common shareholders' equity   16,712   15,687   15,570

Dividends declared
 
 
 
 
 
 
  per common share   $1.84   $1.76   $1.68
  per Series 1 preferred share   $1.15   $1.15   $1.15
  per Series 3 preferred share   $1.00   $1.00   $1.00
  per Series 5 preferred share   $1.10   $1.10   $1.10
  per Series 7 preferred share1   $0.91   -   -
1
Issued March 4, 2013.

2013 Management's discussion and analysis -- 9

Comparable earnings and net income

Comparable earnings

GRAPHIC

Comparable earnings in 2013 were $254 million higher than in 2012, an increase of $0.35 per share.

The increase in comparable earnings was the result of:

•
higher equity income from Bruce Power due to incremental earnings from Units 1 and 2 and lower planned outage days at Unit 4
•
higher earnings from the Canadian Mainline reflecting the higher rate of return on common equity (ROE) of 11.50 per cent in 2013 compared to 8.08 per cent in 2012 due to the National Energy Board's (NEB) 2013 decision on the Canadian Restructuring Proposal (the NEB decision)
•
higher earnings from U.S. Power because of higher capacity prices in New York and higher realized power prices
•
higher earnings from the NGTL System reflecting a higher investment base and the impact of the 2013-2014 NGTL Settlement approved by the NEB in November 2013
•
higher earnings from the Keystone Pipeline System primarily due to higher volumes
•
higher earnings from Western Power because of higher purchased volumes under the power purchase arrangements (PPA).

These increases were partly offset by lower contributions from U.S. natural gas pipelines because of lower earnings at ANR and Great Lakes.

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
•
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 2011 and 2012.

These decreases were partially offset by:

•
a full year of revenue from the Guadalajara pipeline
•
higher Keystone Pipeline System revenues primarily due to higher 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.

10 -- TransCanada Corporation

Net income attributable to common shares

GRAPHIC

Net income attributable to common shares in 2013 was $1,712 million, a year-over-year increase of $413 million (2012 – $1,299 million; 2011 – $1,526 million).

Net income attributable to common shares includes comparable earnings discussed above as well as other specific items which are excluded from comparable earnings. See page 15 for explanation of specific items in non-GAAP measures. The following specific items were recognized in net income in 2011 to 2013:

•
$84 million of net income recorded in 2013 related to 2012 from the NEB decision
•
$25 million favourable tax adjustment in 2013 due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax
•
$15 million after-tax charge ($20 million pre-tax) in 2012 related to the Sundance A PPA arbitration decision. This charge was recorded in second quarter 2012 but related to amounts originally recorded in fourth quarter 2011
•
the impact of certain risk management activities each year.

Cash flow

Funds generated from operations
Funds generated from operations were 22 per cent higher this year compared to 2012 primarily for the same reasons comparable earnings were higher, as described above.

GRAPHIC

2013 Management's discussion and analysis -- 11

Funds used in investing

Capital expenditures
We invested $4.5 billion in capital projects this year as part of our ongoing capital program compared to $6.4 billion we expected to spend in 2013 primarily because of the delay in Keystone XL permitting. Our capital 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 that are expected to generate stable, predictable earnings and cash flow for years to come.

GRAPHIC

Capital expenditures
year ended December 31 (millions of $)   2013   2012   2011
Natural Gas Pipelines   1,776   1,389   917
Oil Pipelines   2,483   1,145   1,204
Energy   152   24   384
Corporate   50   37   8
    4,461   2,595   2,513

Equity investments and acquisitions
In 2013, we invested $0.2 billion in our equity investments. We also spent $0.2 billion on the acquisition of four solar facilities from Canadian Solar Solutions Inc.

Balance sheet
We maintained a strong balance sheet while growing our total assets by $6.6 billion since 2011. At December 31, 2013, common equity represented 40 per cent (42 per cent in 2012) of our capital structure. See page 68 for more information about our capital structure.

Dividends
We increased the quarterly dividend on our outstanding common shares by four per cent to $0.48 per share for the quarter ending March 31, 2014 which equates to an annual dividend of $1.92 per share. This is the 14th consecutive year we have increased the dividend on our common shares representing a compound annual growth rate of seven per cent since 2000.

GRAPHIC

12 -- TransCanada Corporation

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

Before April 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 annual dividends paid on common shares since 2011 is, in part, the result of this change combined with the impact of increases in the annualized dividend rate between 2011 and 2013 from $1.68 to $1.84 per share.

Quarterly dividend on our common shares
$0.48 per share (for the quarter ending March 31, 2014)

Annual dividends on our preferred shares

Series 1 $1.15

Series 3 $1.00

Series 5 $1.10

Series 7 $1.00

Series 9 $1.06

Cash dividends
year ended December 31 (millions of $)   2013   2012   2011
Common shares   1,285   1,226   961
Preferred shares   71   55   55

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

2013 Management's discussion and analysis -- 13

OUTLOOK

Earnings
We anticipate earnings in 2014 to be higher than 2013, mainly due to the net effect of the following:

•
Gulf Coast project achieving commercial in service in January 2014
•
Tamazunchale Pipeline Extension which is expected to be placed in service in second quarter 2014
•
expected higher realized capacity and commodity prices in New York and New England
•
full year of earnings from four solar facilities acquired in 2013 as well as the additional facilities expected to be acquired in 2014
•
anticipated lower Alberta power prices and lower gas storage spreads
•
no earnings from Cancarb Limited and its related power generation facility after the sale which is expected to close late in first quarter 2014
•
higher operating, maintenance and administration (OM&A) costs related to new growth projects.

Results from our U.S. businesses are subject to fluctuations in foreign exchange rates. These fluctuations are largely offset by our hedging activities which are recorded in our Corporate segment.

Natural Gas Pipelines
Earnings from the Natural Gas Pipelines segment in 2014 will be affected by regulatory decisions and the timing of those decisions. Earnings will also be affected by market conditions, which drive the level of demand and the rates we 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.

For 2014, the Canadian Mainline will continue to operate under the direction of the NEB decision which included an ROE of 11.50 per cent. We also expect the NGTL System's investment base to continue to grow as new natural gas supply in northeastern B.C. and western Alberta continues to be developed which will have a positive impact on earnings in 2014.

Many of our U.S. natural gas pipelines are backed by long-term take-or-pay contracts that are expected to deliver stable and consistent financial performance. ANR and Great Lakes have had more commercial exposure from transportation and storage contract renewals which resulted in reduced earnings in 2012 and 2013 as transportation and storage values fell to historically low levels. ANR and GLGT are examining commercial, regulatory and operational changes to optimize their position to benefit from positive developments in supply fundamentals, particularly in the Utica/Marcellus shale areas, combined with continued growth in end use markets for natural gas. In addition, significant effort to reduce costs for our U.S. pipelines operations are underway and expected to help with the near term revenue challenges. Overall in 2014, we expect earnings from our U.S. Pipelines to be consistent with 2013.

Earnings from our Mexican pipelines are expected to be higher in 2014 compared to 2013 as a result of the Tamazunchale Pipeline Extension being placed in service in second quarter 2014. Earnings for our current operating assets are expected to be consistent with 2013 due to the long-term nature of the contracts for these pipeline systems.

Oil Pipelines
Oil Pipelines principally generate earnings by providing pipeline capacity to shippers 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 which provides opportunities to generate incremental earnings.

The Gulf Coast project, an extension of the Keystone Pipeline System achieved commercial in-service in January 2014 and is expected to have a positive impact on the Oil Pipelines segment earnings in 2014. Although the majority of the capacity on this extension is contracted, the actual results for 2014 will be impacted by the level and pricing of spot volumes shipped each month, which is a function of available capacity, market conditions and competitive transportation options.

14 -- TransCanada Corporation


Energy
The higher level of power plant outages and other supply challenges that contributed to higher than expected prices and volatility within the Alberta power market in 2013 are not anticipated to continue in 2014. The sale of Cancarb Limited and its related power generation facility, which is expected to close in late first quarter 2014, as well as lower forecasted prices are expected to result in lower earnings in Western Power in 2014.

Eastern Power earnings in 2014 are expected to be relatively consistent with 2013 with earnings from a full year of service for four solar facilities offset by lower contributions from Bécancour.

Bruce Power equity income is expected to be consistent with 2013 earnings.

U.S. Power earnings are expected to be higher in 2014 due to an increase in realized capacity prices and commodity prices partially offset by lower power marketing contribution. Commodity prices for both power and natural gas are forecasted to be higher in 2014. As well, increased competition will continue to put downward pressure on retail and wholesale marketing margins and volumes in the U.S. Power segment.

Lower summer-to-winter natural gas spreads are expected to result in lower earnings from Natural Gas Storage.

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 expect to spend approximately $5 billion in 2014 on new and existing capital projects, excluding Keystone XL. The amount and timing of capital spending on Keystone XL will be dependent on the decision by the U.S. Department of State (DOS) to issue a Presidential Permit. The 2014 expected capital spending relates to the NGTL System expansion, Mexican pipelines and new growth pipeline projects including Heartland, Northern Courier and Grand Rapids.

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

•
EBITDA
•
EBIT
•
funds generated from operations
•
comparable earnings
•
comparable earnings per common share
•
comparable EBITDA
•
comparable EBIT
•
comparable depreciation and amortization
•
comparable interest expense
•
comparable interest income and other
•
comparable income tax expense.

These measures do not have any standardized meaning as prescribed by 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 tax, 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.

2013 Management's discussion and analysis -- 15


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 9 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. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.

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 depreciation and amortization   depreciation and amortization
comparable interest expense   interest expense
comparable interest income and other   interest income and other
comparable income tax expense   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
•
impact of regulatory or arbitration decisions relating to prior year earnings
•
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.

16 -- TransCanada Corporation

Reconciliation of non-GAAP measures
year ended December 31
(millions of $, except per share amounts)		   2013   2012   2011
EBITDA   4,958   4,224   4,495
Non-comparable risk management activities affecting EBITDA   (44)   21   49
NEB decision – 2012   (55)   -   -
Comparable EBITDA   4,859   4,245   4,544
Comparable depreciation and amortization   (1,472)   (1,375)   (1,328)
Comparable EBIT   3,387   2,870   3,216

Other income statement items
 
 
 
 
 
 
Comparable interest expense   (984)   (976)   (939)
Comparable interest income and other   42   86   60
Comparable income tax   (662)   (477)   (594)
Net income attributable to non-controlling interests   (125)   (118)   (129)
Preferred share dividends   (74)   (55)   (55)
Comparable earnings   1,584   1,330   1,559
Specific items (net of tax):            
  NEB decision – 2012   84   -   -
  Part VI.I income tax adjustment   25   -   -
  Sundance A PPA arbitration decision – 2011   -   (15)   -
  Risk management activities1   19   (16)   (33)
Net income attributable to common shares   1,712   1,299   1,526
Comparable depreciation and amortization   (1,472)   (1,375)   (1,328)
Specific item:            
  NEB decision – 2012   (13)   -   -
Depreciation and amortization   (1,485)   (1,375)   (1,328)
Comparable interest expense   (984)   (976)   (939)
Specific items:            
  NEB decision – 2012   (1)   -   -
  Risk management activities1   -   -   2
Interest expense   (985)   (976)   (937)
Comparable interest income and other   42   86   60
Specific items:            
  NEB decision – 2012   1   -   -
  Risk management activities1   (9)   (1)   (5)
Interest income and other   34   85   55

2013 Management's discussion and analysis -- 17
year ended December 31
(millions of $, except per share amounts)		   2013   2012   2011
Comparable income tax expense   (662)   (477)   (594)
Specific items:            
  NEB decision – 2012   42   -   -
  Part VI.I income tax adjustment   25   -   -
  Sundance A PPA arbitration decision – 2011   -   5   -
  Risk management activities1   (16)   6   19
Income tax expense   (611)   (466)   (575)
Comparable earnings per common share   $2.24   $1.89   $2.22
Specific items (net of tax):            
  NEB decision – 2012   0.12   -   -
  Part VI.I Income tax adjustment   0.04   -   -
  Sundance A PPA arbitration decision – 2011   -   (0.02)   -
  Risk management activities1   0.02   (0.03)   (0.05)
Net income per common share   $2.42   $1.84   $2.17
 
1
year ended December 31
(millions of $)		   2013   2012   2011
Canadian Power   (4)   4   1
U.S. Power   50   (1)   (48)
Natural Gas Storage   (2)   (24)   (2)
Interest rates   -   -   2
Foreign exchange   (9)   (1)   (5)
Income tax attributable to risk management activities   (16)   6   19
Total gains/(losses) from risk management activities   19   (16)   (33)

Comparable EBITDA and comparable EBIT by business segment

 
year ended December 31, 2013
(millions of $)		   Natural Gas
Pipelines		   Oil
Pipelines		   Energy   Corporate   Total
Comparable EBITDA   2,852   752   1,363   (108)   4,859
Comparable depreciation and amortization   (1,013)   (149)   (294)   (16)   (1,472)
Comparable EBIT   1,839   603   1,069   (124)   3,387
 
year ended December 31, 2012
(millions of $)		   Natural Gas
Pipelines		   Oil
Pipelines		   Energy   Corporate   Total
Comparable EBITDA   2,741   698   903   (97)   4,245
Comparable 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 $)		   Natural Gas
Pipelines		   Oil
Pipelines		   Energy   Corporate   Total
Comparable EBITDA   2,875   587   1,168   (86)   4,544
Comparable depreciation and amortization   (923)   (130)   (261)   (14)   (1,328)
Comparable EBIT   1,952   457   907   (100)   3,216

18 -- TransCanada Corporation


Natural Gas Pipelines

Our natural gas pipeline network transports natural gas to local distribution companies, power generation facilities and other businesses across Canada, the U.S. and Mexico. We serve more than 80 per cent of the Canadian demand and approximately 15 per cent of the U.S. 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)
•
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 from the west coast of Canada and additional pipeline developments within Mexico
  •  connections to emerging Canadian and U.S. shale gas and other supplies
  •  connections to new and growing markets
 
all of which play a critical role in meeting the increasing demand for natural gas in North America.

2013 Management's discussion and analysis -- 19

GRAPHIC

20 -- TransCanada Corporation

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

      length   description   effective
ownership

 
Canadian pipelines
 
 
 
 
 
 
1 NGTL System   24,522 km
(15,237 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%
2 Canadian Mainline   14,114 km
(8,770 miles)		   Transports natural gas from the Alberta/Saskatchewan border to serve eastern Canada and the U.S. northeast markets   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 Montréal to Québec City corridor, and connects with the Portland pipeline system that serves the northeast U.S.   50%

 
U.S. pipelines
 
 
 
 
 
 
  ANR            
5       Pipeline   16,121 km
(10,017 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 to the Gulf Coast region as well as Wisconsin, Michigan, Illinois, Indiana and Ohio. Connects with Great Lakes   100%
5a       Storage   250 Bcf   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 50.2 per cent of the system through the combination of our 30 per cent direct ownership interest and our 28.9 per cent interest in TC PipeLines, LP   50.2%
7 Gas Transmission Northwest (GTN)   2,178 km
(1,353 miles)		   Transports natural gas from the WCSB and the Rocky Mountains to Washington, Oregon and California. Connects with Tuscarora and Foothills. We effectively own 50.2 per cent of the system through the combination of our 30 per cent direct ownership interest and our 28.9 per cent interest in TC PipeLines, LP   50.2%
8 Great Lakes   3,404 km
(2,115 miles)		   Connects with the Canadian Mainline near Emerson, Manitoba and St Clair, Ontario, plus interconnects with ANR at Crystal Falls and Farwell in Michigan, to transport natural gas to eastern Canada, and the U.S. upper Midwest. We effectively own 67 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 28.9 per cent interest in TC PipeLines, LP   67%
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%

2013 Management's discussion and analysis -- 21
      length   description   effective
ownership

 
U.S. pipelines
 
 
 
 
 
 
10 North Baja   138 km
(86 miles)		   Transports natural gas between Arizona and California, and connects with another third-party system on the California/Mexico border. We effectively own 28.9 per cent of the system through our interest in TC PipeLines, LP   28.9%
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 14.5 per cent of the system through our 28.9 per cent interest in TC PipeLines, LP   14.5%
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 Nevada, and delivers gas in northeastern California and northwestern Nevada. We effectively own 28.9 per cent of the system through our interest in TC PipeLines, LP   28.9%

 
Mexican pipelines
 
 
 
 
 
 
14 Guadalajara   310 km
(193 miles)		   Transports natural gas from Manzanillo, Colima to Guadalajara, Jalisco   100%
15 Tamazunchale   130 km
(81 miles)		   Transports natural gas from Naranjos, Veracruz in east central Mexico to Tamazunchale, San Luis Potosi   100%

 
Under construction
 
 
 
 
 
 
16 Mazatlan Pipeline   413 km
(257 miles)		   To deliver natural gas from El Oro to Mazatlan, Sinaloa in Mexico. Will connect to the Topolobampo Pipeline at El Oro   100%
17 Tamazunchale Pipeline Extension   235 km
(146 miles)		   To extend existing terminus of the Tamazunchale Pipeline to deliver natural gas to power generating facilities in El Sauz, Queretaro and other parts of central Mexico   100%
18 Topolobampo Pipeline   530 km
(329 miles)		   To deliver natural gas to Topolobampo, Sinaloa, from interconnects with third-party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico   100%

 
In development
 
 
 
 
 
 
19 Alaska LNG Pipeline   1,448 km*
(900 miles)		   To transport natural gas from Prudhoe Bay to LNG facilities in Nikiski, Alaska    
20 Coastal GasLink   650 km*
(404 miles)		   To deliver natural gas from the Montney gas producing region at an expected interconnect on NGTL near Dawson Creek, B.C. to LNG Canada's proposed LNG facility near Kitimat, B.C.   100%
21 Prince Rupert Gas Transmission   750 km*
(466 miles)		   To deliver natural gas from the North Montney gas producing region at a NGTL interconnect near Fort St. John, B.C. to the proposed Pacific Northwest LNG facility near Prince Rupert, B.C.   100%
22 North Montney Mainline   306 km*
(190 miles)		   To deliver natural gas from the North Montney gas producing region and connect to NGTL's existing Groundbirch Mainline   100%
* Pipe lengths are estimates as final route is still under design
 		   

22 -- TransCanada Corporation

RESULTS

Natural Gas Pipelines results
Comparable EBITDA and comparable EBIT are non-GAAP measures. See page 15 for more information.

year ended December 31 (millions of $)   2013   2012   2011
Canadian Pipelines            
Canadian Mainline   1,121   994   1,058
NGTL System   846   749   742
Foothills   114   120   127
Other Canadian (TQM1, Ventures LP)   26   29   34
Canadian Pipelines – comparable EBITDA   2,107   1,892   1,961
Comparable depreciation and amortization   (790)   (715)   (711)
Canadian Pipelines – comparable EBIT   1,317   1,177   1,250
U.S. and International Pipelines (in US$)            
ANR   188   254   306
GTN2   76   112   131
Great Lakes3   34   62   101
TC PipeLines, LP1,4   72   74   85
Other U.S. pipelines (Iroquois1, Bison2, Portland5)   107   111   111
International (Gas Pacifico/INNERGY1, Guadalajara6, Tamazunchale, TransGas1)   106   112   77
General, administrative and support costs   (10)   (8)   (9)
Non-controlling interests7   186   161   173
U.S. and International Pipelines – comparable EBITDA   759   878   975
Comparable depreciation and amortization   (217)   (218)   (214)
U.S. and International Pipelines – comparable EBIT   542   660   761
Foreign exchange impact   15   -   (7)
U.S. and International Pipelines – comparable EBIT (Cdn$)   557   660   754
Business Development comparable EBITDA and comparable EBIT   (35)   (29)   (52)
Natural Gas Pipelines – comparable EBIT   1,839   1,808   1,952
Summary            
Natural Gas Pipelines – comparable EBITDA   2,852   2,741   2,875
Comparable depreciation and amortization   (1,013)   (933)   (923)
Natural Gas Pipelines – comparable EBIT   1,839   1,808   1,952
1
Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments.

2
Effective July 1, 2013, reflects our direct ownership interest of 30 per cent. Prior to that our direct ownership interest was 75 per cent effective May 2011 and 100 per cent prior to that date.

3
Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TC PipeLines, LP.

2013 Management's discussion and analysis -- 23

4
Effective May 22, 2013, our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent. On July 1, 2013, we sold 45 per cent of GTN and Bison to TC PipeLines, LP. The following table shows our ownership interest in TC PipeLines, LP and our ownership of GTN, Bison, and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.
    Ownership percentage as of
    July 1, 2013   May 22, 2013   May 3, 2011   January 1, 2011
 
TC PipeLines, LP
 
28.9
 
28.9
 
33.3
 
38.2
  Effective ownership through TC PipeLines, LP:                
    GTN/Bison   20.2   7.2   8.3   -
    Great Lakes   13.4   13.4   15.5   17.7
5
Represents our 61.7 per cent ownership interest.

6
Included as of June 2011.

7
Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

Canadian Pipelines
year ended December 31 (millions of $)   2013   2012   2011
Net income            
  Canadian Mainline – net income   361   187   246
  Canadian Mainline – comparable earnings   277   187   246
  NGTL System   243   208   200
Average investment base            
  Canadian Mainline   5,841   5,737   6,179
  NGTL System   5,938   5,501   5,074

Comparable EBITDA and net income for our rate-regulated Canadian Pipelines are primarily affected by our approved 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 have a significant impact on net income as they are almost entirely recovered in revenue on a flow-through basis.

Canadian Mainline's comparable earnings this year increased by $90 million compared to 2012 because of the impact of the NEB decision. Among other items, the NEB decision approved an ROE of 11.50 per cent on 40 per cent deemed common equity for the years 2012 through 2017 compared to the last approved ROE of 8.08 per cent on 40 per cent deemed common equity that was used to record earnings in 2012. The NEB decision also approved an incentive mechanism based on total net revenues. The 2013 increase in comparable EBITDA is mainly due to the higher ROE plus incentive earnings. Net income of $361 million recorded in 2013 included $84 million related to the 2012 impact of the NEB decision, which was excluded from comparable earnings. Net income in 2012 was $59 million lower than 2011 because there were no incentive earnings and the average investment base was lower as annual depreciation outpaced our capital investment.

Net income in 2013 for the NGTL System was $35 million higher than 2012 because of a higher average investment base associated with 2012 and 2013 capital expenditures and the impact of the 2013-2014 NGTL Settlement approved by the NEB in November 2013. The settlement included an ROE of 10.10 per cent on 40 per cent deemed common equity, compared to an ROE of 9.70 per cent on 40 per cent deemed equity in 2012, and included annual fixed amounts for certain OM&A costs. Net income in 2012 was $8 million higher than 2011, mainly due to a growing investment base, partially offset by lower incentive earnings.

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

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

24 -- TransCanada Corporation

ANR is also affected by the level of contracting and the determination of rates driven by the market value of its storage capacity, storage related transportation services, 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$119 million lower in 2013 than 2012. This was due to the net effect of:

•
lower transportation and storage revenues at ANR offset by higher incidental commodity sales
•
higher OM&A and other costs relating to services provided by other pipelines to ANR
•
lower revenue at Great Lakes because of uncontracted capacity
•
lower contributions from GTN and Bison due to the reduction of our effective ownership in each pipeline from 83 per cent in 2012 to 50 per cent, effective July 1, 2013
•
higher contributions from Portland due to higher short term revenues.

Comparable EBITDA for the U.S. and International Pipelines was US$97 million lower in 2012 than 2011. This was due to 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 costs at ANR
•
incremental earnings from the Guadalajara pipeline which started operations in June 2011.

Comparable depreciation and amortization
Comparable depreciation and amortization was $80 million higher in 2013 than in 2012 mainly because of a higher NGTL System investment base and higher composite depreciation rate in the 2013-2014 Settlement, as well as the impact of the NEB decision. Depreciation and amortization was $10 million higher in 2012 than in 2011 mainly because Bison began operations in January 2011 and Guadalajara began operations in June 2011.

Business development
In 2013, business development expenses were $6 million higher than last year and $23 million lower in 2012 compared to 2011. Both variances are mainly due to a change in scope on the Alaska pipeline project. See page 32 for further discussion on Alaska.

OUTLOOK

Canadian Pipelines

Earnings
Earnings for Canadian Pipelines 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.

For 2014, we expect the Canadian Mainline will continue to operate under the direction of the NEB decision which included an ROE of 11.50 per cent. We expect 2014 earnings to be in line with 2013.

We expect the NGTL System investment base to continue to grow as we connect new natural gas supply in northeastern B.C. and western Alberta and respond to growing demand in the oil sands market in northeast Alberta. We expect the growing investment base to have a positive impact on earnings in 2014.

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 materially affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contracted capacity levels.

2013 Management's discussion and analysis -- 25


U.S. Pipelines

Earnings
U.S. Pipeline 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. Earnings are also affected by the level of OM&A and other costs, which includes the impact of safety, environmental and other regulator's decisions.

Many of our U.S. natural gas pipelines are backed by long-term take-or-pay contracts that are expected to deliver stable and consistent financial performance. ANR and Great Lakes have had more commercial exposure from transportation and storage contract renewals which resulted in reduced earnings in 2012 and 2013 as transportation and storage values were depressed to historically low levels.

ANR and Great Lakes are examining commercial, regulatory and operational changes to optimize their position from positive developments in supply fundamentals, particularly in the Utica/Marcellus shale plays, combined with continued growth in end use markets for natural gas. In addition, significant efforts to reduce costs for our U.S. pipelines operations are underway and are expected to help with the near term revenue challenges. Overall in 2014, we expect earnings from our U.S. Pipelines to be consistent with 2013.

Mexican Pipelines
Overall earnings from our Mexican pipelines in 2014 are expected to be higher than 2013 due to the Tamazunchale Pipeline Extension which is expected to be placed in service in second quarter 2014. The 2014 earnings for our current operating assets are expected to be consistent with 2013 due to the nature of the long-term contracts applicable to our Mexican pipeline systems.

Capital expenditures
We spent a total of $1.8 billion in 2013 for our natural gas pipelines in Canada, the U.S. and Mexico, and expect to spend $2 billion in 2014 primarily on the NGTL System expansion projects, the Topolobampo and Mazatlan pipelines in Mexico, and the Prince Rupert and Coastal GasLink LNG pipelines. See page 82 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 to end customers such as local distribution companies, power generation facilities, industrial operations and other pipeline interconnects or end-users. The network includes pipelines that are buried underground and transport natural gas under high pressure, compressor stations that act like pumps to move the large volumes of natural gas along the pipeline and meter stations that record the amount of natural gas coming on the network at receipt locations and leaving the delivery locations.

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

Regulators in Canada, the U.S. and Mexico allow us to recover 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

26 -- TransCanada Corporation


our costs to ensure they are prudent, and approves tolls that provide us a reasonable opportunity to recover them.

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 operator may negotiate lower rates with shippers.

Sometimes we enter into agreements or settlements with our shippers 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, Canadian natural gas pipelines request the NEB to approve the pipeline's cost of service and tolls once a year, and recover or refund the variance between actual and expected revenues and costs in future years. Due to the NEB decision, the Canadian Mainline was required to fix its contracted tolls for five years (2013-2017) and defer certain costs to the end of the five-year period. The Mainline was also given flexibility to price its discretionary or uncontracted services in order to maximize its revenue.

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 Mexican pipelines are also regulated and have approved tariffs, services and related rates. However, the contracts underpinning the construction and operation of the facilities in Mexico are long-term negotiated fixed-rate contracts. These rates are only subject to change under specific circumstances such as certain types of force majeure events or changes in law.

2013 Management's discussion and analysis -- 27

Business environment and strategic priorities
The North American natural gas pipeline network has 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 as well as changing demand.

We have a significant pipeline footprint in the WCSB and transport approximately 75 per cent of total WCSB production to markets within and outside of the basin. Our pipelines also source natural gas, to a lesser degree, from the other major basins including the Appalachian (Utica and Marcellus), Rockies, Williston, Haynesville, Fayetteville and Anadarko as well as the Gulf of Mexico.

GRAPHIC

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 150 trillion cubic feet of remaining conventional resources and a technically accessible unconventional resource base of almost 780 trillion cubic feet. The total WCSB resource base has recently more than quadrupled with the advent of technology that can economically access unconventional gas areas in the basin. We expect production from the WCSB to increase slightly in 2014 after decreasing every year since 2006. WCSB production is expected to continue to increase over the next several years. 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 2 Bcf/d, to grow to approximately 6 Bcf/d by 2020, depending on natural gas prices and the economics of exploration and production.

The primary sources of natural gas in the U.S. are the U.S. shale areas, 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 demand by 2020. Of the shale areas in the U.S, the Utica, Marcellus, Haynesville, Barnett, Eagle Ford and Fayetteville are the major supply sources.

28 -- TransCanada Corporation

The supply of natural gas in North America is forecast to increase significantly over the next decade (by approximately 20 Bcf/d or 22 per cent 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 in the U.S. northeast, and the Montney and Horn River 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, have resulted in an increase in exploration and production of liquid-rich hydrocarbon basins. There is often associated gas in these areas (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 existing markets, particularly in the northeast U.S., has led to an increase in the number of supply choices and is changing historical gas pipeline flow patterns, generally from long-haul, long-term firm contracted capacity to shorter-distance, shorter-term contracts. While the Canadian Mainline has also seen this shift following the NEB decision, we have seen a considerable volume of long-haul transportation recontracted through 2014.

While the increase in supply, particularly in northeastern B.C., has created opportunities for us to build and plan new large pipeline infrastructure on the NGTL System to move the natural gas to markets, including proposed LNG exports, the majority of existing Canadian and U.S. pipelines, including ours, have focused on smaller debottlenecking or short pipe connections as part of any new infrastructure development.

Changing demand
The growing supply of natural gas has resulted in relatively low natural gas prices in North America, which have supported increased demand for natural gas particularly in the following areas:

•
natural gas-fired power generation
•
petrochemical and industrial facilities
•
the production of Alberta oil sands
•
exports to Mexico to fuel new power generation facilities.

Natural gas producers are also assessing opportunities 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. Assuming the receipt of all necessary regulatory and other approvals, these facilities are expected to become operational later in 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 levels and locations have resulted in increased competition for transportation services throughout North America. Development technology for shale gas supply basins that are closer to markets historically served has resulted in changes to flow patterns of existing natural gas pipeline infrastructure from long haul to shorter haul distances particularly with the large development of U.S. northeast supply. Along with other pipelines, we are restructuring our tolls and service offerings to capture this growing northeast supply and North American demand.

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

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

The Canadian Mainline continued to be a focal point in 2013 following the receipt and implementation of the NEB decision. Following the NEB decision, we reached an LDC Settlement that addresses issues associated

2013 Management's discussion and analysis -- 29


with the NEB decision. The LDC Settlement reflects our focus on developing a framework that balances the needs of our shippers while at the same time ensuring a reasonable opportunity to recover the capital from our existing facilities and any new facilities required to serve existing and new markets.

The NGTL 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 NGTL 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 NGTL System is well positioned to connect WCSB supply to meet expected demand for LNG exports on the B.C. coastline. Obtaining the necessary regulatory approvals to extend and expand the NGTL System into northeast B.C. to connect the Montney shale area will be a key focus in 2014.

Our U.S. pipeline assets are positioned well for anticipated connections to growth in supply and markets for the following reasons:

•
expected continued growth in gas-fired generation and therefore load on our pipes, including the new proposed Carty lateral on the GTN system to deliver natural gas to a new power plant in Oregon
•
growth in industrial load in response to robust levels of natural gas supply, including connections to the ANR System to serve a new nitrogen fertilizer plant in Iowa
•
Utica/Marcellus supply growth and Gulf Coast LNG export development supporting ANR utilization, including the Lebannon Lateral project attracting Utica supply to the ANR system with additional phases of further expansion expected.

Management expects to divest our remaining U.S. natural gas pipeline assets into TC PipeLines, LP over time as a means of funding a portion of our capital growth program.

Our focus in Mexico in 2014 is to complete the Tamazunchale Pipeline Extension project and to advance the construction phase for the Mazatlan and Topolobampo pipelines. We continue to be very interested in the further development of natural gas infrastructure in Mexico and will work to advance future projects that align with the investment profile of our current set of assets.

We continue to assess repurposing opportunities for our existing natural gas pipelines assets, including the possibility of converting existing infrastructure from natural gas to crude oil service. In 2007, we received NEB approval to convert one of our Canadian Mainline gas pipelines to crude oil service for the original Keystone project. Another project, the Energy East Pipeline is planning, subject to regulatory approval, to utilize approximately 3,000 km (1,864 miles) of the Canadian Mainline from the Alberta border to a point in eastern Ontario, southeast of Ottawa. As a result, we are working closely with our shipper community to ensure their firm service needs will continue to be met following the planned conversion.

SIGNIFICANT EVENTS

Canadian Pipelines
In 2013, we completed and placed in service approximately $730 million of pipeline projects to expand and extend the NGTL System and $160 million to expand the Canadian Mainline.

NGTL System
In addition to completing and placing in service new pipeline projects to expand the NGTL System, in 2013 the NEB approved approximately $290 million in additional expansions that are currently in various stages of development or construction but were not in service at the end of 2013.

On November 8, 2013, we filed an application with the NEB to construct and operate the North Montney Project, which is an extension and expansion of the NGTL System to receive and transport natural gas from the

30 -- TransCanada Corporation


North Montney area of B.C. The estimated capital cost of the project is $1.7 billion and it consists of approximately 300 km (186 miles) of pipeline.

The NEB approved the 2013-2014 NGTL Settlement and final 2013 rates, as filed, in November 2013. We expect the final tolls for 2014 for the NGTL System will be determined on the basis of the NGTL settlement process.

Canadian Mainline
In March 2013, we received the NEB decision on our application to change the business structure and the terms and conditions of service for the Canadian Mainline and implemented the decision on July 1, 2013. The implementation of the NEB decision was a key priority in 2013 and with the ability to price discretionary services at market prices we were able to essentially meet our overall cost of service requirements for 2013.

The NEB decision established a Tolls Stabilization Account (TSA) to capture the surplus or the shortfall between our revenues and our cost of service for each year over the five-year term of the decision. The NEB decision also identified certain circumstances that would require a new tolls application prior to the end of the five-year term. One of those circumstances is if the TSA balance becomes positive, which occurred in 2013.

The Mainline and the three largest Canadian local distribution companies entered into a settlement (LDC Settlement) which was filed with the NEB for approval in December 2013. The LDC Settlement, if approved, will establish new fixed tolls for 2015 to 2020 and maintain tolls for 2014 at the current rates. The LDC Settlement calculates tolls for 2015 on a base ROE of 10.10 per cent on 40 per cent deemed common equity. It also includes an incentive mechanism that requires a $20 million (after tax) annual contribution by us from 2015 to 2020, which could result in a range of ROE outcomes from 8.70 per cent to 11.50 per cent.

The LDC Settlement will enable the addition of facilities in the Eastern Triangle to serve immediate market demand for supply diversity and market access. The LDC Settlement is intended to provide a market-driven, stable, long-term accommodation of future demand in this region in combination with the anticipated lower demand for transportation on the Prairies Line and the Northern Ontario Line while providing a reasonable opportunity to recover our costs. The LDC Settlement also retains pricing flexibility for discretionary services and implements certain tariff changes and new services as required by the term of the settlement.

The NEB decision remains in effect pending the outcome of the LDC Settlement application.

On January 31, 2014, shippers on the Canadian Mainline elected to renew approximately 2.5 Bcf/d of their contracts through November 2016. This represents a significant amount of volume renewal, especially by Canadian shippers.

U.S. Pipelines

Bison and GTN
In July 2013, we sold an additional 45 per cent interest in each of GTN and Bison to TC PipeLines, LP. for an aggregate purchase price of US$1.05 billion. We continue to hold a 30 per cent direct ownership interest in both pipelines. We also hold 28.9 per cent interest in, and are the General Partner of, TC PipeLines, LP.

ANR Lebanon Lateral Reversal Project
Following a successful binding open season which concluded in October 2013, we have executed firm transportation contracts for 350 million cubic feet per day at maximum tariff rates for 10 years on the ANR Lebanon Lateral Reversal Project, which will entail modifications to existing facilities. The facility modifications are expected to be completed in first quarter 2014. Contracted volumes will increase over the course of 2014 generating incremental earnings. The project will substantially increase our ability to receive gas on ANR's southeast mainline from the Utica/Marcellus shale areas.

Great Lakes
In November 2013, we received FERC approval for a rate settlement with our shippers resulting in maximum recourse rates increasing by approximately 21 per cent resulting in a modest increase in revenues derived from

2013 Management's discussion and analysis -- 31


our recourse rate contracts. The settlement includes a 17 month moratorium through March 2015 and requires us to have new rates in effect by January 1, 2018.

Mexican Pipelines

Topolobampo and Mazatlan Pipeline Projects.
Permitting and engineering activities are advancing as planned for these two northwest Mexico pipelines. The Topolobampo project is a 530 km (329 miles), 30-inch pipeline with a capacity of 670 MMcf/d and a cost of US$1 billion that will deliver gas from El Encino, Chihuahua and interconnects with third party pipelines in El Oro, Sinaloa to Topolobampo, Sinaloa. The Mazatlan project is a 413 km (257 miles), 24-inch pipeline running from El Oro to Mazatlan, within the state of Sinaloa with a capacity of 200 MMcf/d and an estimated cost of US$400 million. Both projects are supported by 25-year contracts with the Comisión Federal de Electricidad (CFE) and are expected to be in service mid to late 2016.

Tamazunchale Pipeline Extension Project
The construction of the US$500 million Tamazunchale Pipeline Extension project is proceeding although delays have occurred due to a significant number of archeological finds within the pipeline route. It is expected these findings and related alternative construction will move the project scheduled in-service date to second quarter 2014. As these types of findings are not uncommon in significant infrastructure projects in Mexico, contractual relief for such delays is provided. We continue to work with local, state and federal authorities to minimize and mitigate ground disturbance at the specific sites as well as to minimize impact to the scheduled in-service date.

LNG Pipeline Projects

Coastal GasLink
In June 2012, we were selected to design, build, own and operate the proposed Coastal GasLink project. The estimated $4 billion, 650 km (404 miles) pipeline is expected to have an initial capacity of 1.7 Bcf/d and will transport natural gas from the Montney gas producing region near Dawson Creek B.C. to LNG Canada's proposed LNG export facility near Kitimat B.C.

We are currently focused on community, landowner, government and First Nations engagement as the project advances through the regulatory process. We filed the Application for an Environmental Assessment Certificate with the B.C. Environmental Assessment Office (BCEAO) in January 2014.

The pipeline would be placed in service near the end of the decade, subject to a final investment decision to be made by LNG Canada after obtaining final regulatory approvals. We continue to advance this project and all costs would be recoverable should the project not proceed.

Prince Rupert Gas Transmission Project
We have been selected to design, build, own and operate the proposed $5 billion, 750 km (466 miles) Prince Rupert Gas Transmission Project. The 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 are currently focused on First Nations, community, landowner and government engagement as the Prince Rupert pipeline project advances through the regulatory process with the BCEAO. We continue to refine our study corridor based on consultation and detailed studies to date. A final investment decision to construct the project, for a planned in-service date of late 2018, is expected to be made following final regulatory approvals.

We continue to advance this project and all costs would be fully recoverable should the project not proceed.

Alaska LNG Project
The State of Alaska is proposing new legislation that would transition from the Alaska Gasline Inducement Act and enable a new commercial arrangement to be established with us, the three major producers, and the Alaska Gasline Development Corp. It has also been agreed that an LNG export project, rather than a pipeline

32 -- TransCanada Corporation


to Alberta, is currently the best opportunity to commercialize Alaska North Slope gas resources in current market conditions. It is anticipated that two years of front end engineering will be completed before further commitments to commercialize the project will be made.

BUSINESS RISKS
The following are risks specific to our natural gas pipelines business. See page 76 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 largely on supply from the WCSB. There is competition for this supply from several pipelines, demand within the basin, and in the future, demand for pipelines proposed for LNG exports from the west coast of B.C. An overall decrease in production and/or competing demand for supply, could impact throughput on WCSB connected pipelines that in turn could impact overall revenues generated. The WCSB has considerable reserves, but how much of it is actually produced will depend on many variables, including the price of natural gas, basin-on-basin competition, downstream pipeline tolls, demand within the basin 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 basins being developed closer to markets we have historically served may reduce the throughput and/or distance of haul on our existing pipelines that may impact revenue. 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 for greenfield expansion
We face competition from other pipeline companies seeking opportunities to invest in greenfield natural gas pipeline development opportunities. This competition could result in fewer projects being available that meet our investment hurdles or projects that proceed with lower overall financial returns.

Demand for pipeline capacity
Demand for pipeline capacity is ultimately the key driver that enables pipeline 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. Renewal of expiring contracts, and the opportunity to charge and collect a toll the market requires depends on the overall demand for transportation service. A change in the level of demand for our pipeline transportation services could impact revenues.

Regulatory risk
Decisions by regulators can have an impact on the approval, timing, construction, operation and financial performance of our natural gas pipelines. There is a risk that decisions are delayed or are not favourable that could impact revenues and the opportunity to further invest capital in our systems. There is also risk of a regulator disallowing a portion or all prudently incurred costs, now or at some point in the future.

The regulatory approval process for larger infrastructure projects including the time it takes to receive a decision could be slowed or unfavorable due to the influence from the evolving role of activists and their impact on public opinion and government policy related to natural gas pipeline infrastructure development.

Increased scrutiny of operating processes by the regulator or other enforcing agencies, has the potential to increase operating costs. There is a risk of an impact to revenues if these costs are not fully recoverable.

2013 Management's discussion and analysis -- 33

We continuously monitor regulatory developments and decisions to determine the possible impact on our gas pipelines business. We also work closely with our stakeholders in the development of rate, facility and tariff applications and negotiated settlements, where possible.

Operational
Keeping our pipelines operating safely and reliably is essential to the success of our business. Interruptions in our pipeline operations impact our throughput capacity and may result in reduced revenue and can affect corporate reputation as well as customer and public confidence in our operations. 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.

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Oil Pipelines

Our existing crude oil pipeline infrastructure connects Alberta crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas, as well as connecting U.S. crude oil supplies from the Cushing, Oklahoma hub to refining markets in the U.S Gulf Coast.



Strategy at a glance
  With the increasing production of crude oil in Alberta and the U.S. and the growing demand for secure, reliable sources of energy, developing new liquids pipeline capacity and related infrastructure is essential.
 
We continue to focus on accessing and delivering growing North American crude oil supply to key markets, and are planning to expand our crude oil transportation infrastructure to deliver supply directly from the production site seamlessly along a contiguous path to the market.
 
Construction of these infrastructure projects will provide North America with a key crude oil transportation network to transport growing crude oil supply directly to key markets and provide opportunities for us to further expand our liquids pipelines business.

2013 Management's discussion and analysis -- 35

GRAPHIC

36 -- TransCanada Corporation

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

      length   description   ownership

 
Oil pipelines
 
 
 
 
 
 
23 Keystone Pipeline System (includes Gulf Coast Project)   4,247 km
(2,639 miles)		   Transports crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka in Illinois, Cushing, Oklahoma, and to the U.S. Gulf Coast refining market   100%

 
Under construction
 
 
 
 
 
 
24 Cushing Marketlink Receipt Facility   Crude oil receipt
facilities		   To facilitate the transportation of crude oil from the market hub at Cushing, Oklahoma to the U.S. Gulf Coast refining market on facilities that form part of the Keystone Pipeline System   100%
25 Houston Lateral and Terminal   77 km
(48 miles)		   To transport crude oil from the Keystone Pipeline System to Houston, Texas   100%
26 Keystone Hardisty Terminal   Crude oil terminal   Crude oil terminal to be located at Hardisty