40-F 1 a2207310z40-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, 2011 Commission File Number 1-8887

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

Canada
(Jurisdiction of incorporation or organization)

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

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

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

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


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

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

At December 31, 2011, 4,000,000 Cumulative Redeemable First Preferred Shares Series U
and 4,000,000 Cumulative Redeemable First Preferred Shares Series Y
were issued and outstanding.
731,998,733 common shares which are all owned by TransCanada Corporation

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

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

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

Form		Registration No.

F-9			333-163641
F-9			333-177789

EXPLANATORY NOTE

An amendment to this Form 40-F shall be filed to include the TransCanada PipeLines Limited ("TCPL") Annual Information Form for the year ended December 31, 2011. The amendment shall be filed no later than the date the Annual Information Form is required pursuant to home country requirements.

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

Except sections specifically referenced below which shall be deemed incorporated by reference herein and filed, no other portion of the TCPL 2011 Management's Discussion and Analysis and Audited Consolidated Financial Statements 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 91 through 149 of the TCPL 2011 Management's Discussion and Analysis and Audited Consolidated Financial Statements included herein. See Note 25 of the Notes to Audited Consolidated Financial Statements on pages 144 through 149 of the TCPL 2011 Management's Discussion and Analysis and Audited Consolidated Financial Statements, reconciling the significant differences between Canadian and United States generally accepted accounting principles.

B. Management's Discussion & Analysis

For management's discussion and analysis, see pages 2 through 90 of the TCPL 2011 Management's Discussion and Analysis and Audited Consolidated Financial Statements included herein.

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 91 of the TCPL 2011 Management's Discussion and Analysis and Audited Consolidated Financial Statements included herein.

UNDERTAKING

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

DISCLOSURE CONTROLS AND PROCEDURES

For information on disclosure controls and procedures, see "Controls and Procedures" in Management's Discussion and Analysis on pages 77 and 78 of the TCPL 2011 Management's Discussion and Analysis and Audited Consolidated Financial Statements.

AUDIT COMMITTEE FINANCIAL EXPERT

The Registrant's board of directors has determined that it has at least one audit committee financial expert serving on its audit committee. Mr. Kevin E. Benson has been designated an audit committee financial expert and is independent, as that term is defined by the New York Stock Exchange's listing standards applicable to the Registrant. The Commission has indicated that the designation of Mr. Benson as an audit committee financial expert does not make Mr. Benson an "expert" for any purpose, impose any duties, obligations or liability on Mr. Benson that are greater than those imposed on members of the audit committee and board of directors who do not carry this designation or affect the duties, obligations or liability of any other member of the audit committee.

CODE OF ETHICS

The Registrant has adopted codes of business ethics for its President and Chief Executive Officer, Chief Financial Officer, Controller, directors, employees and contractors. The Registrant's codes are available on its website at www.transcanada.com. No waivers have been granted from any provision of the codes during the 2011 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Pre-Approval Policies and Procedures

TransCanada's Audit Committee has adopted a pre-approval policy with respect to permitted non-audit services. Under the policy, the Audit Committee has granted pre-approval for specified non-audit services. For engagements of $25,000 or less which are not within the annual pre-approved limit, approval by the Audit Committee is not required, and for engagements between $25,000 and $100,000, approval of the Audit Committee Chair is required, and the Audit Committee is to be informed of the engagement at the next scheduled Audit Committee meeting. For all engagements of $100,000 or more, pre-approval of the Audit Committee is required. In all cases, regardless of the dollar amount involved, where there is a potential for conflict of interest involving the external auditor to arise on an engagement, the Audit Committee Chair must pre-approve the assignment.

To date, TransCanada has not approved any non-audit services on the basis of the de-minimus exemptions. All non-audit services have been pre-approved by the Audit Committee in accordance with the pre-approval policy described above.

External Auditor Service Fees

The following table provides information about the fees paid by the Company to KPMG LLP, the external auditor of the TransCanada group of companies, for professional services rendered for the 2011 and 2010 fiscal years.

($ millions)		2011		2010


Audit fees		$	6.9	$	6.5
•	audit of the annual consolidated financial statements
•	services related to statutory and regulatory filings or engagements
•	reviewing interim consolidated financial statements and information contained in various prospectuses and other offering documents

Audit-related fees			0.2		0.2
•	services related to the audit of the financial statements of certain TransCanada pension plans

Tax fees			0.4		1.0
•	Canadian and international tax planning and tax compliance matters, including the review of income tax returns and other tax filings

All other fees			0.1		0.2
•	services related to environmental compliance in 2011 and advice and training related to International Financial Reporting Standards in 2010

Total fees		$	7.6	$	7.9

OFF-BALANCE SHEET ARRANGEMENTS

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

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

For information on Tabular Disclosure of Contractual Obligations, see "Contractual Obligations" in Management's Discussion and Analysis on page 57 of the TCPL 2011 Management's Discussion and Analysis and Audited Consolidated Financial Statements.

IDENTIFICATION OF THE AUDIT COMMITTEE

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


	Chair: Members:		K.E. Benson D.H. Burney E.L. Draper P.L. Joskow J.A. MacNaughton D.M.G. Stewart

FORWARD-LOOKING INFORMATION

This document contains certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast", "intend", "target", "plan" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future plans and financial outlook. Forward-looking statements in this document may include, but are not limited to, statements regarding:

•: anticipated business prospects;
•: financial performance of TransCanada and its subsidiaries and affiliates;
•: expectations or projections about strategies and goals for growth and expansion;
•: expected cash flows;
•: expected costs;
•: expected costs for projects under construction;
•: expected schedules for planned projects (including anticipated construction and completion dates);
•: expected regulatory processes and outcomes;
•: expected outcomes with respect to legal proceedings, including arbitration;
•: expected capital expenditures;
•: expected operating and financial results; and
•: expected impact of future commitments and contingent liabilities.

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

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

•: inflation rates, commodity prices and capacity prices;
•: timing of debt issuances and hedging;
•: regulatory decisions and outcomes;
•: arbitration decisions and outcomes;
•: foreign exchange rates;
•: interest rates;
•: tax rates;
•: planned and unplanned outages and utilization of the Company's pipeline and energy assets;
•: asset reliability and integrity;
•: access to capital markets;
•: anticipated construction costs, schedules and completion dates; and
•: acquisitions and divestitures.

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

•: the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits;
•: the operating performance of the Company's pipeline and energy assets;
•: the availability and price of energy commodities;
•: amount of capacity payments and revenues from the Company's energy business;
•: regulatory decisions and outcomes;
•: outcomes with respect to legal proceedings, including arbitration;
•: counterparty performance;
•: changes in environmental and other laws and regulations;
•: competitive factors in the pipeline and energy sectors;
•: construction and completion of capital projects;
•: labour, equipment and material costs;
•: access to capital markets;
•: interest and currency exchange rates;
•: weather;
•: technological developments; and
•: economic conditions in North America.

Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC).

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

SIGNATURES

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


		TRANSCANADA PIPELINES LIMITED
		Per:		/s/ DONALD R. MARCHAND DONALD R. MARCHAND Executive Vice-President and Chief Financial Officer
				Date: February 17, 2012

DOCUMENTS FILED AS PART OF THIS REPORT


	13.1		Management's Discussion and Analysis (included on pages 2 through 90 of the TCPL 2011 Management's Discussion and Analysis and Audited Consolidated Financial Statements).
	13.2		2011 Audited Consolidated Financial Statements (included on pages 91 through 149 of the TCPL 2011 Management's Discussion and Analysis and Audited Consolidated Financial Statements), including the auditors' report thereon.
	13.3		Independent Auditors' Report of Registered Public Accounting Firm on the 2011 Audited Consolidated Financial Statements.
	13.4		Report of Independent Registered Public Accounting Firm on the effectiveness of TCPL's Internal Control Over Financial Reporting, as of December 31, 2011.

EXHIBITS


	23.1		Consent of KPMG LLP, Independent Registered Public Accounting Firm.
	31.1		Certification of Chief Executive Officer pursuant to Section 302 of 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.

Management’s Discussion and Analysis and Audited Consolidated Financial Statements TransCanada PipeLines Limited 2011 TransCanada PipeLines Limited 2011

13 14 15 1 12 11 10 9 17 2 5 8 4 6 3 3 7 16 1 2 1 2 1 21 22 16 17 20 21 18 19 Kibby Wind TC Hydro Ocean State Power Ravenswood Coolidge Natural Gas Storage Edson CrossAlta (60% ownership) 15 14 13 10 11 12 1 2 3 4 5 6 7 8 9 NATURAL GAS PIPELINES Canadian Mainline Alberta System ANR GTN (83.3% effective ownership) Foothills Bison (83.3% effective ownership) Guadalajara Tamazunchale North Baja (33.3% effective ownership) Tuscarora (33.3% effective ownership) Northern Border (16.7% effective ownership) Great Lakes (69% effective ownership) Iroquois (44.5% ownership) TQM (50% ownership) Portland (61.7% ownership) Alaska Pipeline Project (proposed by TransCanada) Mackenzie Gas Project (proposed by producers) Natural Gas Storage ANR Natural Gas Storage OIL PIPELINES Keystone Keystone XL (in development) ENERGY Bear Creek MacKay River Redwater Sundance A PPA Sundance B PPA (50% ownership) Sheerness PPA Carseland Cancarb Bruce Power (Bruce A – 48.8%, Bruce B – 31.6%) Halton Hills Portlands Energy (50% ownership) Bécancour Cartier Wind (62% ownership) (under construction) Grandview 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 1 2 9 11 17 12 13 14 16 15 1 2 3 4 5 7 6 8 20 21 18 19 10

Financial Highlights

Year ended December 31 (millions of dollars)	2011	2010		2009		2008	2007

Income
Net income attributable to common shares	1,504	1,234		1,357		1,420	1,210

Cash Flow
Funds generated from operations	3,572	3,279		3,044		2,992	2,603
Decrease/(increase) in operating working capital	282	(256	)	(88	)	128	63

Net cash provided by continuing operations	3,854	3,023		2,956		3,120	2,666

Capital expenditures and acquisitions	3,274	5,036		6,319		6,363	5,874
Balance Sheet
Total assets	49,723	48,126		44,670		40,735	31,737
Long-term debt	17,632	17,028		16,186		15,368	12,377
Junior subordinated notes	1,009	985		1,036		1,213	975
Common shareholders' equity	18,073	15,358		14,483		12,574	9,664

TRANSCANADA PIPELINES LIMITED 1

TABLE OF CONTENTS


TCPL OVERVIEW		3
TCPL'S STRATEGY		5

CONSOLIDATED FINANCIAL REVIEW		7
	Selected Three-Year Consolidated Financial Data	7
	Highlights	8
	Reconciliation of Non-GAAP Measures	9
	Results of Operations	11

FORWARD-LOOKING INFORMATION		13
NON-GAAP MEASURES		14
OUTLOOK		15

NATURAL GAS PIPELINES		16
	Map	16
	Highlights	18
	Results	19
	Financial Analysis	20
	Opportunities and Developments	23
	Business Risks	25
	Outlook	28
	Natural Gas Throughput Volumes	29

OIL PIPELINES		30
	Map	30
	Highlights	31
	Results	31
	Financial Analysis	31
	Opportunities and Developments	32
	Business Risks	34
	Outlook	35

ENERGY		36
	Map	36
	Highlights	38
	Power Plants – Nominal Generating Capacity and Fuel Type	38
	Results	39
	Financial Analysis	40
	Opportunities and Developments	49
	Business Risks	50
	Outlook	52

CORPORATE		53
OTHER INCOME STATEMENT ITEMS		53

LIQUIDITY AND CAPITAL RESOURCES		54
	Summarized Cash Flow	54
	Highlights	54
	Cash Flow and Capital Resources	54

CONTRACTUAL OBLIGATIONS		57

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS		61
	Financial Risks and Financial Instruments	61
	Other Risks	73

CONTROLS AND PROCEDURES		77
CRITICAL ACCOUNTING POLICIES AND ESTIMATES		78

ACCOUNTING CHANGES		81

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA		82
FOURTH QUARTER 2011 HIGHLIGHTS		84
SHARE INFORMATION		87
OTHER INFORMATION		87
GLOSSARY OF TERMS		88

2 MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis (MD&A) dated February 13, 2012 should be read in conjunction with the accompanying audited Consolidated Financial Statements of TransCanada PipeLines Limited (TCPL or the Company) and the notes thereto for the year ended December 31, 2011 which are prepared in accordance with Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook (CGAAP). This MD&A covers TCPL's financial position and operations as at and for the year ended December 31, 2011. "TCPL" or "the Company" includes TransCanada PipeLines Limited and its subsidiaries, unless otherwise indicated. Amounts are stated in Canadian dollars unless otherwise indicated. Abbreviations and acronyms not defined in this MD&A are defined in the Glossary of Terms in the Company's 2011 Annual Report.

TCPL OVERVIEW

With more than 60 years experience, TCPL is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and natural gas storage facilities.

Today, TCPL is:

•: One of the largest natural gas transmission companies in North America with a network of wholly- and partially-owned natural gas pipelines extending more than 68,500 kilometres (km) (42,500 miles), tapping into virtually all major gas supply basins;
•: One of the continent's largest providers of natural gas storage and related services with approximately 380 billion cubic feet (Bcf) of storage capacity;
•: The largest private sector power company in Canada and owns or has interests in over 10,800 megawatts (MW) of power generation in Canada and the United States (U.S.); and
•: A significant player in the oil transmission business with the start up of the Keystone oil pipeline system and the large expansion opportunity to the U.S. Gulf Coast (Keystone XL).

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

With assets of approximately $50 billion and a substantial growth portfolio, TCPL believes it is well positioned to build on its track record of strong and sustainable earnings, cash flow and dividends. Since the spring of 2010, TCPL has brought $10 billion of growth projects in service and is positioned to complete another $12 billion of new projects by the end of 2014.

TCPL's 2011 Key Developments

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

•: Achieved full commercial operations in February 2011 on the sections of the Keystone crude oil pipeline system, extending from Hardisty, Alberta to Wood River and Patoka in Illinois (Wood River/Patoka) and from Steele City, Nebraska, to Cushing, Oklahoma (Cushing Extension) and recorded earnings before interest, taxes, depreciation and amortization (EBITDA) of $0.6 billion in Keystone's first eleven months of operations;
•: Received a favourable Final Environmental Impact Statement (FEIS) in August from the U.S. Department of State (DOS) for Keystone XL;
•: Secured commercial support for an extension and expansion of Keystone XL to provide crude oil transportation service from Hardisty, Alberta to Houston, Texas; and
•: Received notice that the DOS had denied the Presidential Permit for Keystone XL, based on the DOS's position that it did not have sufficient time to receive and review additional information necessary to assess alternative routes that would avoid the Sandhills region of Nebraska. TCPL will submit a revised Presidential Permit application to the DOS.

MANAGEMENT'S DISCUSSION AND ANALYSIS 3

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

•

Continued to advance pipeline development projects on the Alberta System to transport new natural gas supply from the Horn River and Montney shale basins in northeastern British Columbia (B.C.) as well as the Deep Basin in Alberta:

•: Received approval from the National Energy Board (NEB) for the construction of natural gas pipeline projects on the Alberta System with capital costs totalling approximately $910 million including the $275 million Horn River pipeline; and
•: Filed additional pipeline development projects with the NEB costing approximately $810 million that included new agreements to further extend the Horn River pipeline by approximately 100 km (62 miles) at an estimated cost of $230 million.

•

Placed in service:

•: The US$630 million Bison pipeline in January 2011, which delivers natural gas from the Powder River Basin in Wyoming to an interconnection with the Northern Border Pipeline; and
•: The US$360 million Guadalajara pipeline in June 2011, which transports natural gas from Manzanillo to Guadalajara in Mexico.

•

Filed a comprehensive application, with the NEB in September 2011, to change the business structure and the terms and conditions of service for the Canadian Mainline to address tolls for 2012 and 2013;

•

Closed the sale of a 25 per cent interest in each of Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC (Bison LLC) to TC PipeLines, LP for an aggregate purchase price of US$605 million, which included US$81 million or 25 per cent of GTN LLC debt outstanding; and

•

Filed a supplemental application with the NEB to construct $130 million of new pipeline infrastructure on the Canadian Mainline to receive Marcellus shale basin natural gas from the U.S. at the Niagara Falls receipt point for further transportation to Eastern markets.

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

•: Placed in service the US$500 million Coolidge generation station in May 2011, capable of producing 575 MW;
•: Completed construction and placed in service the Montagne-Sèche and phase one of the Gros-Morne wind farms in November 2011, capable of producing 159 MW of renewable energy;
•: Executed an agreement in December 2011 for the purchase of nine Ontario solar projects, with a combined capacity of 86 MW, for approximately $470 million that are expected to come into service between late 2012 and mid-2013; and
•: Continued to progress the $4.8 billion refurbishment and restart of two reactors at the Bruce Power nuclear facility in Ontario. TCPL's expected net capital cost of the project is $2.4 billion. Fuelling of both Unit 1 and Unit 2 has now been completed and the final phases of commissioning for Unit 2 are underway. Subject to regulatory approval, Bruce Power expects to commence commercial operations of Unit 2 in first quarter 2012 and commercial operations of Unit 1 in third quarter 2012.

The following are other key developments in Energy in 2012:

•: Both units at Sundance A were not operational throughout 2011 and have been subject to force majeure and economic destruction claims by the asset owner. TCPL has recorded revenues and costs throughout 2011 as it considers this event to be an interruption of supply in accordance with the terms of the power purchase arrangement (PPA). An arbitration hearing is scheduled for April 2012 to hear both claims.
•: Since July 2011, spot prices for capacity sales applicable to Ravenswood have been negatively impacted by the manner in which New York Independent System Operator (NYISO) has applied pricing rules for a new power plant in the New York City Zone J market. TCPL has filed formal complaints with the Federal Energy Regulatory Commission (FERC) that are pending.
•: TCPL reached a formal agreement to use an arbitration process to settle the Oakville contract dispute resulting from the termination of a 20-year Clean Energy Supply contract with the Ontario Power Authority (OPA).

4 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

Natural Gas Pipelines

TCPL's natural gas pipeline systems consist of a network of more than 57,000 km (35,500 miles) of wholly owned natural gas pipelines, and more than 11,500 km (7,000 miles) of partially owned natural gas pipelines. The network connects major natural gas supply basins and markets, transporting approximately 20 per cent of the natural gas consumed in North America or 14 Bcf of natural gas per day, which is delivered to local distribution companies, power generation facilities and other businesses in markets across North America. The Company's U.S. Natural Gas Pipelines include regulated natural gas storage facilities in Michigan with a total capacity of 250 Bcf.

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

Oil Pipelines

The Company's Keystone crude oil pipeline system currently operates on the Wood River/Patoka and the Cushing Extension sections and has a nominal design capacity of 591,000 barrels per day (bbl/d). With increasing production of crude oil in Alberta and new crude oil discoveries in the U.S., including the Bakken shale play in Montana and North Dakota, combined with growing demand for secure, reliable sources of energy, TCPL has identified additional opportunities to develop new oil pipeline capacity.

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

Energy

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

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

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

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

TCPL'S STRATEGY

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 5

strategies continue to evolve with the Company's growth and development and its changing business environment. TCPL's corporate strategy integrates four fundamental value-creating activities:

•: Maximize the full-life value of TCPL's infrastructure assets and commercial positions
•: Commercially develop and physically execute new asset investment programs
•: Cultivate a focused portfolio of high-quality development options
•: Maximize TCPL's competitive strengths

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

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

Commercially develop and physically execute new asset investment programs

TCPL's expertise, scale and financial capacity enable access to attractive commercial, financing and input cost arrangements that influence the quality of projects, notably the current $12 billion capital program. These projects are expected to provide further contributions to the Company's earnings over the next three years as they are put in service. Success in this capital program requires effective performance in engineering and in project set-up and delivery. It also requires expert regulatory, legal and financing support, as well as outstanding operational set-up. TCPL's model for managing construction risks and maximizing capital productivity helps ensure disciplined attention to quality, cost and schedule that produces superior service for its customers and quality returns to shareholders. Many of these functional capabilities also create the basis for successful acquisition and integration of new energy and pipeline facilities, an important dimension of the growth strategy.

Cultivate a focused portfolio of high-quality development options

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

Maximize TCPL's competitive strengths

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

6 MANAGEMENT'S DISCUSSION AND ANALYSIS

CONSOLIDATED FINANCIAL REVIEW

SELECTED THREE-YEAR CONSOLIDATED FINANCIAL DATA

(millions of dollars except per share amounts)		2011	2010		2009

Income Statement
Revenues		9,139	8,064		8,181
Comparable EBITDA⁽¹⁾		4,806	3,941		4,107
Net Income Attributable to Common Shares		1,504	1,234		1,357
Comparable Earnings⁽¹⁾		1,542	1,368		1,308
Per Share Data
Net Income per Common Share – Basic and Diluted		$2.22	$1.87		$2.20
Dividends Declared
	Series U Preferred Shares	$2.80	$2.80		$2.80
	Series Y Preferred Shares	$2.80	$2.80		$2.80
Cash Flows
Funds Generated from Operations⁽¹⁾		3,572	3,279		3,044
Decrease/(Increase) in Operating Working Capital		282	(256	)	(88	)

Net Cash Provided by Operations		3,854	3,023		2,956

Capital Expenditures		3,274	5,036		5,417
Acquisitions, Net of Cash Acquired		–	–		902
Balance Sheet
Total Assets		49,723	48,126		44,670
Total Long-Term Liabilities		24,326	25,923		24,065

⁽¹⁾: Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA, Comparable Earnings and Funds Generated from Operations.

MANAGEMENT'S DISCUSSION AND ANALYSIS 7

HIGHLIGHTS

Earnings

•: Net Income Attributable to Common Shares was $1.5 billion in 2011 compared to $1.2 billion in 2010.
•: TCPL's Comparable Earnings in 2011 were $1.5 billion compared to the $1.4 billion reported in 2010.

Cash Flow

•

Funds Generated from Operations were $3.6 billion in 2011, an increase of $0.3 billion or nine per cent from $3.3 billion in 2010.

•

TCPL invested $3.3 billion in its Natural Gas Pipelines, Oil Pipelines and Energy capital projects in 2011, including the following:

•: capital expenditures of $0.9 billion for Natural Gas Pipelines projects, including expansion of the Alberta System and completion of Bison and Guadalajara;
•: capital expenditures of $1.2 billion for Keystone; and
•: capital expenditures of $1.1 billion for Energy projects, including the refurbishment and restart of Bruce A Units 1 and 2, completion of Coolidge and construction of Cartier Wind, including completion of Montagne-Sèche and phase one of the Gros-Morne project.

•

In 2011, TCPL issued approximately $1.6 billion of long-term debt and $2.4 billion of common shares, primarily comprising the following:

•: in December 2011, the issuance of 56.3 million common shares resulting in proceeds of $2.4 billion;
•: in December 2011, TC PipeLines, LP made a draw of US$300 million on its senior revolving credit facility;
•: in November 2011, the issuance of $750 million of medium-term notes; and
•: in June 2011, TC PipeLines, LP issued US$350 million of senior notes.

Balance Sheet

•: Total assets increased by $1.6 billion to $49.7 billion in 2011 from 2010, primarily due to investments in capital projects, described above.
•: TCPL's Equity Attributable to Controlling Interests increased by $2.8 billion to $18.5 billion in 2011 from 2010.

Dividends

•: On February 13, 2012, the Board of Directors of TCPL declared a dividend for the quarter ending March 31, 2012 in an aggregate amount equal to the quarterly dividend to be paid on TransCanada Corporation's (TransCanada) issued and outstanding common shares at the close of business on March 30, 2012. In addition, the Board of Directors declared regular dividends on TCPL preferred shares.

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

8 MANAGEMENT'S DISCUSSION AND ANALYSIS

Reconciliation of Non-GAAP Measures

Year ended December 31, 2011
(millions of dollars)

Natural Gas
Pipelines

Oil Pipelines

Energy

Corporate

Total

Comparable EBITDA

2,967

587

1,338

(86

)

4,806

Depreciation and amortization

(986

)

(130

)

(398

)

(14

)

(1,528

)

Comparable EBIT

1,981

457

940

(100

)

3,278

Other Income Statement Items

Comparable interest expense

(1,046

)

Interest expense of joint ventures

(55

)

Comparable interest income and other

Comparable income taxes

(566

)

Net income attributable to non-controlling interests

(107

)

Preferred share dividends

(22

)

Comparable Earnings

1,542

Specific items (net of tax):

Risk management activities⁽¹⁾

(38

)

Net Income Attributable to Common Shares

1,504

Year ended December 31, 2011 (millions of dollars)		2011

Comparable Interest Expense		(1,046	)
Specific item:
	Risk management activities⁽¹⁾	2

Interest Expense		(1,044	)

Comparable Interest Income and Other		60
Specific item:
	Risk management activities⁽¹⁾	(5	)

Interest Income and Other		55

Comparable Income Taxes		(566	)
Specific item:
	Risk management activities⁽¹⁾	22

Income Taxes Expense		(544	)

MANAGEMENT'S DISCUSSION AND ANALYSIS 9

Reconciliation of Non-GAAP Measures

Year ended December 31, 2010 (millions of dollars)		Natural Gas Pipelines		Oil Pipelines	Energy		Corporate		Total

Comparable EBITDA		2,915		–	1,125		(99	)	3,941
Depreciation and amortization		(977	)	–	(377	)	–		(1,354	)

Comparable EBIT		1,938		–	748		(99	)	2,587

Other Income Statement Items
Comparable interest expense									(754	)
Interest expense of joint ventures									(59	)
Comparable interest income and other									94
Comparable income taxes									(385	)
Net income attributable to non-controlling interests									(93	)
Preferred share dividends									(22	)

Comparable Earnings									1,368
Specific items (net of tax):
	Valuation provision for MGP								(127	)
	Risk management activities⁽¹⁾								(7	)

Net Income Attributable to Common Shares									1,234

Year ended December 31, 2010 (millions of dollars)		2010

Comparable Income Taxes		(385	)
Specific items:
	Valuation provision for MGP	19
	Risk management activities⁽¹⁾	1

Income Taxes Expense		(365	)

10 MANAGEMENT'S DISCUSSION AND ANALYSIS

Reconciliation of Non-GAAP Measures

Year ended December 31, 2009 (millions of dollars)		Natural Gas Pipelines		Oil Pipelines	Energy		Corporate		Total

Comparable EBITDA		3,093		–	1,131		(117	)	4,107
Depreciation and amortization		(1,030	)	–	(347	)	–		(1,377	)

Comparable EBIT		2,063		–	784		(117	)	2,730

Other Income Statement Items
Comparable interest expense									(986	)
Interest expense of joint ventures									(64	)
Comparable interest income and other									119
Comparable income taxes									(395	)
Net income attributable to non-controlling interests									(74	)
Preferred share dividends									(22	)

Comparable Earnings									1,308
Specific items (net of tax):
	Dilution gain from reduced interest in TC PipeLines, LP								18
	Risk management activities⁽¹⁾								1
	Income tax adjustments								30

Net Income Attributable to Common Shares									1,357

Year ended December 31, 2009 (millions of dollars)		2009

Comparable Income Taxes		(395	)
Specific items:
	Dilution gain from reduced interest in TC PipeLines, LP	(11	)
	Income tax adjustments	30

Income Taxes Expense		(376	)

⁽¹⁾ For the year ended (millions of dollars)	2011		2010		2009

Risk Management Activities Gains/(Losses):
U.S. Power derivatives	(48	)	2		–
Canadian Power derivatives	(3	)	–		–
Natural Gas Storage proprietary inventory and derivatives	(6	)	(10	)	1
Interest rate derivatives	2		–		–
Foreign exchange derivatives	(5	)	–		–
Income taxes attributable to risk management activities	22		1		–

Risk Management Activities	(38	)	(7	)	1

RESULTS OF OPERATIONS

TCPL had Net Income Attributable to Common Shares of $1,504 million in 2011 compared to $1,234 million and $1,357 million in 2010 and 2009, respectively.

Comparable Earnings in 2011, 2010 and 2009 were $1,542 million, $1,368 million and $1,308 million, respectively. Comparable Earnings in 2011 excluded $38 million of net unrealized after-tax losses ($60 million pre-tax) resulting from changes in the fair value of certain risk management activities.

Comparable Earnings in 2010 excluded a $127 million after-tax ($146 million pre-tax) valuation provision for advances to the Aboriginal Pipeline Group (APG) for the Mackenzie Gas Project (MGP) and $7 million of net unrealized after-tax losses ($8 million pre-tax) resulting from changes in the fair value of certain risk management activities.

MANAGEMENT'S DISCUSSION AND ANALYSIS 11

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

Comparable Earnings increased $174 million in 2011 compared to 2010 and included the following:

•: increased Comparable Earnings Before Interest and Taxes (EBIT) from Natural Gas Pipelines primarily due to incremental earnings from Bison and Guadalajara which were placed in service in January 2011 and June 2011, respectively, lower general, administrative and support costs as well as lower business development spending, partially offset by lower revenues from certain U.S. Pipelines and the negative impact of a weaker U.S. dollar;
•: Oil Pipelines Comparable EBIT as the Company commenced recording earnings from Keystone in February 2011;
•: increased Comparable EBIT from Energy primarily due to higher realized power prices for Western Power and incremental earnings from Halton Hills and Coolidge, partially offset by lower contributions from Bruce B, Natural Gas Storage and U.S. Power;
•: increased Comparable Interest Expense primarily due to decreased capitalized interest upon placing Keystone and other new assets in service, and higher interest expense as a result of U.S. dollar-denominated debt issuances in June and September 2010, partially offset by gains on derivatives used to manage the Company's exposure to rising interest rates in 2011 compared to losses incurred in 2010 and the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest expense;
•: decreased Comparable Interest Income and Other primarily due to lower realized gains in 2011 compared to 2010 on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income;
•: increased Comparable Income Taxes primarily due to higher pre-tax earnings in 2011 and higher positive income tax adjustments in 2010 compared to 2011; and
•: increased Non-Controlling Interests due to the sale of a 25 per cent interest in GTN LLC and Bison LLC to TC PipeLines, LP in May 2011 and the reduction in the Company's ownership interest in TC PipeLines, LP.

Comparable Earnings increased $60 million in 2010 compared to 2009. The increase in Comparable Earnings was primarily due to increased capitalized interest relating to Keystone and other capital projects. This increase was partially offset by decreased EBIT from Natural Gas Pipelines and Energy as discussed later.

On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. operations is significantly offset by other U.S. dollar-denominated items as set out in the following table. The resultant pre-tax net exposure is managed using derivatives, further reducing the Company's exposure to changes in Canadian-U.S. foreign exchange rates. The average exchange rate to convert a U.S. dollar to a Canadian dollar for the year ended December 31, 2011 was 0.99 (2010 – 1.03; 2009 – 1.14).

Summary of Significant U.S. Dollar-Denominated Amounts

Year ended December 31 (millions of dollars)	2011		2010		2009

U.S. Natural Gas Pipelines Comparable EBIT⁽¹⁾	786		710		682
U.S. Oil Pipelines Comparable EBIT⁽¹⁾	301		–		–
U.S. Power Comparable EBIT⁽¹⁾	164		187		78
Interest on U.S. dollar-denominated long-term debt	(734	)	(680	)	(645	)
Capitalized interest on U.S. capital expenditures	116		290		123
U.S. non-controlling interests and other	(192	)	(164	)	(132	)

	441		343		106

⁽¹⁾: Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBIT.

12 MANAGEMENT'S DISCUSSION AND ANALYSIS

FORWARD-LOOKING INFORMATION

This MD&A contains certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast", "intend", "target", "plan" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TCPL security holders and potential investors with information regarding TCPL and its subsidiaries, including management's assessment of TCPL's and its subsidiaries' future plans and financial outlook. Forward-looking statements in this document may include, but are not limited to, statements regarding:

•: anticipated business prospects;
•: financial performance of TCPL and its subsidiaries and affiliates;
•: expectations or projections about strategies and goals for growth and expansion;
•: expected cash flows;
•: expected costs;
•: expected costs for projects under construction;
•: expected schedules for planned projects (including anticipated construction and completion dates);
•: expected regulatory processes and outcomes;
•: expected outcomes with respect to legal proceedings, including arbitration;
•: expected capital expenditures;
•: expected operating and financial results; and
•: expected impact of future commitments and contingent liabilities.

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

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

•: inflation rates, commodity prices and capacity prices;
•: timing of debt issuances and hedging;
•: regulatory decisions and outcomes;
•: arbitration decisions and outcomes;
•: foreign exchange rates;
•: interest rates;
•: tax rates;
•: planned and unplanned outages and utilization of the Company's pipeline and energy assets;
•: asset reliability and integrity;
•: access to capital markets;
•: anticipated construction costs, schedules and completion dates; and
•: acquisitions and divestitures.

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

•: the ability of TCPL to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits;
•: the operating performance of the Company's pipeline and energy assets;
•: the availability and price of energy commodities;
•: amount of capacity payments and revenues from the Company's energy business;

MANAGEMENT'S DISCUSSION AND ANALYSIS 13

•: regulatory decisions and outcomes;
•: outcomes with respect to legal proceedings, including arbitration;
•: counterparty performance;
•: changes in environmental and other laws and regulations;
•: competitive factors in the pipeline and energy sectors;
•: construction and completion of capital projects;
•: labour, equipment and material costs;
•: access to capital markets;
•: interest and currency exchange rates;
•: weather;
•: technological developments; and
•: economic conditions in North America.

Additional information on these and other factors is available in the reports filed by TCPL with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC).

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

NON-GAAP MEASURES

TCPL uses the measures Comparable Earnings, EBITDA, Comparable EBITDA, EBIT, Comparable EBIT, Comparable Interest Expense and Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this MD&A. These measures do not have any standardized meaning as prescribed by CGAAP. They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TCPL uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TCPL's operating performance, liquidity and ability to generate funds to finance operations.

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

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

The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing derivatives. The risk management activities which TCPL excludes from Comparable Earnings provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each year. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to be representative of the

14 MANAGEMENT'S DISCUSSION AND ANALYSIS

underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.

The Reconciliation of Non-GAAP Measures table in this MD&A presents a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares.

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

OUTLOOK

TCPL's corporate strategy is to maximize the full-life value of its existing assets and commercial positions, and to pursue long-term growth opportunities that add long-term shareholder value while focusing on its core strengths in its pipelines and energy businesses in North America. In 2012 and beyond, TCPL expects that its net income and operating cash flow combined with a strong balance sheet and its proven ability to access capital markets will provide the financial resources needed to complete its current $12 billion capital expenditure program, which includes Keystone XL and the Bruce Power restarts, to continue pursuing additional long-term growth opportunities and to create additional value for its shareholders. This strategy will be executed with the same discipline and deliberate manner that characterized TCPL's capital expenditure program in previous years.

TCPL expects a positive impact on its 2012 earnings from assets that were placed in service in 2011 such as the Guadalajara natural gas pipeline, the Coolidge power facility and two Cartier Wind farm projects, from Keystone's Wood River/Patoka and Cushing Extension sections that began recording earnings in 2011, and from assets that are expected to be placed in service in 2012, such as Bruce Power Units 1 and 2. TCPL expects that as these assets are placed in service, its consolidated earnings for the year will be somewhat offset by a corresponding reduction in capitalized interest.

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

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

Energy's EBIT in 2012 is expected to be positively affected by assets that were placed in service during 2011 and assets that are expected to be placed in service in 2012. Energy's EBIT in 2012 could also be affected by the uncertainty and ultimate resolution of the capacity pricing issues in New York and outcome of the Sundance A PPA arbitration. Although a significant portion of Energy's output is sold under long-term contracts, output that is sold under shorter-term forward arrangements or at spot prices will continue to be impacted by fluctuations in commodity prices.

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

The Company's results in 2012 may be affected by a number of factors and developments as discussed throughout this MD&A including, without limitation, the factors and developments discussed in the Forward-Looking Information and Business Risks sections for Natural Gas Pipelines, Oil Pipelines and Energy. Refer to the Outlook sections in this MD&A for further discussion on the outlook for Natural Gas Pipelines, Oil Pipelines and Energy.

MANAGEMENT'S DISCUSSION AND ANALYSIS 15

NATURAL GAS PIPELINES

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

CANADIAN MAINLINE The Canadian Mainline is a 14,101 km (8,762 miles) natural gas transmission system in Canada that extends from the Alberta/Saskatchewan border east to the Québec/Vermont border and connects with other natural gas pipelines in Canada and the U.S.

ALBERTA SYSTEM The Alberta System is a 24,373 km (15,145 miles) natural gas transmission system in Alberta and Northeast B.C. that connects with the Canadian Mainline and Foothills natural gas pipelines and with third-party natural gas pipelines.

16 MANAGEMENT'S DISCUSSION AND ANALYSIS

ANR ANR is a 16,656 km (10,350 miles) natural gas transmission system that extends from producing fields located in the Texas and Oklahoma panhandle regions, from the offshore and onshore regions of the Gulf of Mexico, and from the U.S. midcontinent region to markets located mainly in Wisconsin, Michigan, Illinois, Indiana and Ohio. ANR also owns and operates regulated underground natural gas storage facilities in Michigan with a total working capacity of 250 Bcf.

GTN Owned 75 per cent by TCPL and 25 per cent by TC PipeLines, LP, GTN is a 2,178 km (1,353 miles) natural gas transmission system that transports WCSB and Rocky Mountain-sourced natural gas to third-party natural gas pipelines and markets in Washington, Oregon and California, and connects with Tuscarora. TCPL operates GTN and effectively owns 83.3 per cent of the system through the combination of its direct ownership interest and its 33.3 per cent interest in TC PipeLines, LP.

FOOTHILLS Foothills is a 1,241 km (771 miles) transmission system in Western Canada carrying natural gas for export from central Alberta to the U.S. border to serve markets in the U.S. Midwest, Pacific Northwest, California and Nevada.

BISON Owned 75 per cent by TCPL and 25 per cent by TC PipeLines, LP, Bison is a 487 km (303 miles) natural gas pipeline that was placed in service in January 2011 and connects supply from the Powder River Basin in Wyoming to Northern Border in North Dakota. TCPL operates Bison and effectively owns 83.3 per cent of the system through the combination of its direct ownership interest and its 33.3 per cent interest in TC PipeLines, LP.

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

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

NORTH BAJA Owned 100 per cent by TC PipeLines, LP, North Baja is a natural gas transmission system extending 138 km (86 miles) from Ehrenberg, Arizona to Ogilby, California and connecting with a third-party natural gas pipeline system in Mexico. TCPL operates North Baja and effectively owns 33.3 per cent of the system through its 33.3 per cent interest in TC PipeLines, LP.

TUSCARORA Owned 100 per cent by TC PipeLines, LP, Tuscarora is a 491 km (305 miles) pipeline system transporting natural gas from GTN at Malin, Oregon to Wadsworth, Nevada, with delivery points in northeastern California and northwestern Nevada. TCPL operates Tuscarora and effectively owns 33.3 per cent of the system through its 33.3 per cent interest in TC PipeLines, LP.

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

GREAT LAKES Owned 53.6 per cent by TCPL and 46.4 per cent by TC PipeLines, LP, Great Lakes is a 3,404 km (2,115 miles) natural gas transmission system serving markets in Eastern Canada and the U.S. Northeast and Midwest regions. TCPL operates Great Lakes and effectively owns 69.0 per cent of the system through the combination of its direct ownership interest and its 33.3 per cent interest in TC PipeLines, LP.

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

TQM Owned 50 per cent by TCPL, TQM is a 572 km (355 miles) pipeline system that connects with the Canadian Mainline near the Québec/Ontario border, transports natural gas to markets in Québec, and connects with Portland. TQM is operated by TCPL.

PORTLAND Owned 61.7 per cent by TCPL, Portland is a 474 km (295 miles) pipeline that connects with TQM near East Hereford, Québec and delivers natural gas to customers in the northeastern U.S. Portland is operated by TCPL.

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 17

GAS PACIFICO/INNERGY Owned 30 per cent by TCPL, Gas Pacifico is a 540 km (336 miles) natural gas pipeline extending from Loma de la Lata, Argentina to Concepción, Chile. TCPL also has a 30 per cent ownership interest in INNERGY, an industrial natural gas marketing company based in Concepción that markets natural gas transported on Gas Pacifico.

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

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

NATURAL GAS PIPELINES – HIGHLIGHTS

•: Comparable EBIT from Natural Gas Pipelines was $2.0 billion in 2011, an increase of $0.1 billion from $1.9 billion in 2010.
•: The Company invested $0.9 billion in Natural Gas Pipelines capital projects in 2011 primarily related to growth on the Alberta System and construction of the Guadalajara pipeline.
•: In January 2011, the Bison natural gas pipeline was placed in service.
•: In June 2011, the Company's US$360 million, 307 km (191 miles) Guadalajara natural gas pipeline went into service. This pipeline has capacity to transport 500 million cubic feet per day (MMcf/d) of natural gas to a power plant and 320 MMcf/d to the Pemex-owned national pipeline system near Guadalajara.
•: The Alberta System growth continues through new connections of supply primarily in the Horn River and Montney shale basins in B.C. as well as the Deep Basin in Alberta. In 2011, the NEB approved the construction of natural gas pipeline projects for the Alberta System with a capital cost of approximately $910 million, including the approval to construct the Horn River pipeline with an estimated capital cost of $275 million and an in-service date of second quarter 2012. In addition, Pipeline projects with a total capital cost of approximately $810 million are still awaiting NEB decisions. The Company executed new agreements to further extend the Horn River pipeline by approximately 100 km (62 miles) at an estimated cost of $230 million. Subject to regulatory approval this extension is projected to commence service in 2014.
•: In September 2011, TCPL filed, with the NEB, the Restructuring Proposal, a comprehensive application to change the business structure and the terms and conditions of service for the Canadian Mainline including a 7.0 per cent after-tax weighted average cost of capital (ATWACC) fair return, revised depreciation rates and other parameters to address tolls for 2012 and 2013. The application also includes components that affect the Alberta System and Foothills. The NEB decision for this filing is expected in late 2012 or early 2013.
•: In November 2011, TCPL refiled an application with the NEB including supplemental information to construct $130 million of new pipeline infrastructure on the Canadian Mainline to receive Marcellus shale basin natural gas from the U.S. at the Niagara Falls receipt point for further transportation to Eastern markets.
•: In May 2011, TCPL closed the sale of a 25 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an aggregate purchase price of US$605 million plus closing adjustments, which included US$81 million or 25 per cent of GTN LLC debt outstanding.

18 MANAGEMENT'S DISCUSSION AND ANALYSIS

NATURAL GAS PIPELINES – RESULTS

Year ended December 31 (millions of dollars)		2011		2010		2009

Canadian Natural Gas Pipelines
Canadian Mainline		1,058		1,054		1,133
Alberta System		742		742		728
Foothills		127		135		132
Other (TQM, Ventures LP)		50		50		59

Canadian Natural Gas Pipelines Comparable EBITDA⁽¹⁾		1,977		1,981		2,052
Depreciation and amortization		(722	)	(715	)	(714	)

Canadian Natural Gas Pipelines Comparable EBIT⁽¹⁾		1,255		1,266		1,338

U.S. Natural Gas Pipelines (in U.S. dollars)
ANR		312		314		300
GTN⁽²⁾		131		171		170
Great Lakes⁽³⁾		101		109		120
TC PipeLines, LP^(2)4)(5)		101		99		90
Iroquois		67		67		68
Bison⁽⁵⁾		49		–		–
Portland⁽⁶⁾		22		22		22
International (Tamazunchale, Guadalajara, TransGas, Gas Pacifico/INNERGY)⁽⁷⁾		77		42		52
General, administrative and support costs⁽⁸⁾		(9	)	(31	)	(17	)
Non-controlling interests⁽⁹⁾		202		173		153

U.S. Natural Gas Pipelines Comparable EBITDA⁽¹⁾		1,053		966		958
Depreciation and amortization		(267	)	(256	)	(276	)

U.S. Natural Gas Pipelines Comparable EBIT⁽¹⁾		786		710		682
Foreign exchange		(8	)	24		105

U.S. Natural Gas Pipelines Comparable EBIT⁽¹⁾ (in Canadian dollars)		778		734		787

Natural Gas Pipelines Business Development Comparable EBITDA and EBIT⁽¹⁾		(52	)	(62	)	(62	)

Natural Gas Pipelines Comparable EBIT⁽¹⁾		1,981		1,938		2,063

Summary:
Natural Gas Pipelines Comparable EBITDA⁽¹⁾		2,967		2,915		3,093
Depreciation and amortization		(986	)	(977	)	(1,030	)

Natural Gas Pipelines Comparable EBIT⁽¹⁾		1,981		1,938		2,063
Specific items:
	Valuation provision for MGP⁽¹⁰⁾	–		(146	)	–
	Dilution gain from reduced interest in TC PipeLines, LP⁽¹¹⁾	–		–		29

Natural Gas Pipelines EBIT⁽¹⁾		1,981		1,792		2,092

⁽¹⁾: Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA, Comparable EBIT and EBIT.
⁽²⁾: Results reflect TCPL's direct ownership of 75 per cent of GTN effective May 2011 when 25 per cent was sold to TC PipeLines, LP, and 100 per cent prior to that date. GTN's results also include North Baja until July 2009, when North Baja was sold to TC PipeLines, LP.
⁽³⁾: Represents TCPL's 53.6 per cent direct ownership interest.
⁽⁴⁾: Effective May 2011, TCPL's ownership interest in TC PipeLines, LP decreased from 38.2 per cent to 33.3 per cent. Results reflect TCPL's indirect effective ownership interest of 8.3 per cent in each of GTN and Bison effective May 2011. Effective November 18, 2009,

MANAGEMENT'S DISCUSSION AND ANALYSIS 19

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

⁽⁵⁾: Results reflect TCPL's direct ownership of 75 per cent of Bison effective May 2011 when 25 per cent was sold to TC PipeLines, LP and 100 per cent since January 2011 when Bison went into service.
⁽⁶⁾: Portland's results reflect TCPL's 61.7 per cent ownership interest.
⁽⁷⁾: Includes Guadalajara effective June 2011.
⁽⁸⁾: Represents General, Administrative and Support Costs associated with certain of the Company's pipelines, including $17 million for the start up of Keystone in 2010.
⁽⁹⁾: Non-controlling interests reflects Comparable EBITDA for the 66.7 per cent and 38.3 per cent portions of TC PipeLines, LP and Portland, respectively, not owned by TCPL.
⁽¹⁰⁾: In 2010, the Company recorded a valuation provision of $146 million for its advances to the APG for the MGP.
⁽¹¹⁾: As a result of TC PipeLines, LP issuing common units to the public in July 2009, the Company's ownership interest in TC PipeLines, LP was reduced to 38.2 per cent from 42.6 per cent and a dilution gain of $29 million was realized.

Natural Gas Pipelines' Comparable EBIT was $1,981 million in 2011 compared to $1,938 million in 2010. Comparable EBIT in 2010 excluded a $146 million valuation provision for the Company's advances to the APG for the MGP. Comparable EBIT in 2009 was $2,063 million excluding the $29 million dilution gain resulting from TCPL's reduced interest in TC PipeLines, LP, which occurred as a result of the public issuance of common units by TC PipeLines, LP in November 2009.

Wholly Owned Canadian Natural Gas Pipelines Net Income

Year ended December 31 (millions of dollars)	2011	2010	2009

Canadian Mainline	246	267	273
Alberta System	200	198	168
Foothills	22	27	23

NATURAL GAS PIPELINES – FINANCIAL ANALYSIS

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

The Canadian Mainline operated under a five-year tolls settlement from 2007 through 2011. The cost of capital reflected an ROE as determined by the NEB's ROE formula on deemed common equity of 40 per cent. The tolls settlement established certain elements of the Canadian Mainline's fixed operating, maintenance and administration (OM&A) costs for each of the five years. All other cost elements of the revenue requirement were treated on a flow-through basis. The settlement also allowed for performance-based incentive arrangements that the Company believes were mutually beneficial to TCPL and its customers.

The Canadian Mainline's net income of $246 million in 2011 was $21 million lower compared to 2010 as a result of a lower ROE of 8.08 per cent in 2011 compared to 8.52 per cent in 2010 and a lower average investment base, partially offset by higher incentive earnings. Net income in 2010 was $6 million lower compared to 2009. This decrease was primarily due to lower OM&A incentive earnings as a result of cost-sharing with customers and an ROE of 8.52 per cent in 2010 compared to 8.57 per cent in 2009.

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

20 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

The Alberta System currently operates under the 2010 - 2012 Revenue Requirement Settlement approved by the NEB in September 2010. The 2010 - 2012 Revenue Requirement Settlement established an ROE of 9.70 per cent on deemed common equity of 40 per cent and included an annual fixed amount of $174 million for certain OM&A costs. Variances between actual and agreed-to OM&A costs accrue to TCPL. All other cost elements of the revenue requirement are treated on a flow-through basis. In 2009, the Alberta System operated under the 2008 - 2009 Revenue Requirement Settlement approved by the Alberta Utilities Commission (AUC) in December 2008. The Alberta System was regulated by the AUC until April 2009.

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

The Alberta System's net income of $200 million in 2011 was $2 million higher compared to 2010. The increase is primarily due to higher earnings as a result of a growing average investment base. Net income in 2010 was $30 million higher than in 2009. This increase reflected an ROE of 9.70 per cent on 40 per cent deemed common equity in 2010 compared to the earnings achieved under the settlement in place in 2009 and a higher average investment base, partially offset by lower incentive earnings. The increase in average investment base from 2009 to 2011 reflects capital expenditures to expand capacity in response to growing customer demand for service.

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

Foothills The Foothills System's net income of $22 million in 2011 was $5 million lower compared to 2010. The decrease was primarily due to lower earnings from a lower average investment base and lower OM&A incentive

MANAGEMENT'S DISCUSSION AND ANALYSIS 21

earnings. Net income in 2010 was $4 million higher than 2009, due to a Foothills 2010 settlement agreement, which established an ROE of 9.70 per cent on deemed common equity of 40 per cent for 2010 through 2012. Results in 2009 were based on the NEB ROE formula of 8.57 per cent on deemed common equity of 36 per cent.

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

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

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

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

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

GTN GTN is regulated by the FERC and is operated in accordance with tariffs that establish maximum and minimum rates for various services. GTN is permitted to discount or negotiate rates on a non-discriminatory basis. In 2011, GTN negotiated a settlement for new rates with its customers in lieu of filing a rate case. The FERC approved the settlement agreement in November 2011 for new rates effective January 1, 2012. The settlement includes a four-year moratorium during which GTN and the settling parties are prohibited from taking certain actions, including making any filings to adjust rates prior to December 31, 2015. The settlement also requires GTN to file for new rates that are to be effective January 1, 2016.

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

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

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

22 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

NATURAL GAS PIPELINES – OPPORTUNITIES AND DEVELOPMENTS

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

The abundance of supply resulting in relatively low natural gas prices across North America is supportive of increased reliance on natural gas to meet growing energy demands. A shift to increased natural gas fired power generation is also emerging in the U.S. and Canada. Numerous proposals for development of LNG export facilities from North America is another example of the evolution of the natural gas industry. Persistently high oil prices, particularly relative to North America natural gas prices, have resulted in increased deployment of capital for the exploration and production of liquid-rich hydrocarbon basins, which also tend to produce associated natural gas. A recent announcement by the Mexican government to change its procurement strategy away from LNG imports to infrastructure improvements that facilitate increased access to natural gas supply from the U.S. is further evidence of the increased confidence in the availability of supply at stable prices across North America.

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

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

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

•: Extension of the Alberta System footprint to points on the Canadian Mainline in Saskatchewan, and on the Foothills System in Saskatchewan and B.C., thereby reducing the cost to transport gas from the Western Canada Sedimentary Basin (WCSB) to markets served by the Canadian Mainline.
•: Lower depreciation expense and therefore lower tolls resulting from adjustments to the economic planning horizons for the three Canadian Mainline segments and a reallocation of accumulated depreciation to better match consumed service value for each segment.
•: Changes to toll design, services, and pricing resulting in higher revenues and lower overall tolls.
•: A 7.0 per cent ATWACC fair return which is equivalent to an ROE of 12 per cent on deemed common equity of 40 per cent.

MANAGEMENT'S DISCUSSION AND ANALYSIS 23

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

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

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

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

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

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

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

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

Canadian Mainline, Alberta System and Foothills 2012 Tolls TCPL filed for and received approval to implement interim 2012 tolls on the Canadian Mainline effective January 1, 2012, at the same level as the currently approved 2011 final tolls. In addition, TCPL filed for interim 2012 tolls on the Alberta System and annual tolls for Foothills to be

24 MANAGEMENT'S DISCUSSION AND ANALYSIS

effective January 1, 2012. These tolls have also been approved on an interim basis pending the outcome of the NEB's decision on the Restructuring Proposal.

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

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

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

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

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

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

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

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

NATURAL GAS PIPELINES – BUSINESS RISKS

Natural Gas Supply, Markets and Competition TCPL faces competition at both the supply and market ends of its natural gas pipeline systems. This competition comes from other natural gas pipelines accessing supply basins, including the WCSB, and markets served by TCPL's pipelines as well as from natural gas supplies produced in certain basins not directly served by the Company. Growth in supply and pipeline infrastructure has increased competition throughout North America. Production has increased in the U.S., driven primarily by shale gas, as well as in the WCSB. After declining over the past four years, WCSB production showed signs of recovery in 2011. Lower-cost shale gas in the U.S. has resulted in an increase in competition between supply basins, changes to traditional flow patterns and an

MANAGEMENT'S DISCUSSION AND ANALYSIS 25

increase in supply choices for customers. This change has contributed to a trend of continued reduction in long-haul, long-term firm contracted capacity and a shift to shorter-distance, short-term firm and interruptible contracts on many natural gas pipelines.

Although TCPL has diversified its natural gas supply sources, many of its North American natural gas pipelines and its transmission infrastructure remain dependent on supply from the WCSB. TCPL's Alberta System is the major natural gas gathering and transportation system for the WCSB, connecting most of the natural gas processing plants in Western Canada to domestic and export markets. The Alberta System, however, faces competition for connection to supply, particularly in northeast B.C., where the largest new source of natural gas has access to two existing pipeline companies with infrastructure in the area.

The Canadian Mainline, with its primary source of supply being the WCSB, also seeks opportunities to increase market share in Canadian domestic markets. However, TCPL expects to continue to face competition for both the eastern domestic markets and in particular, the northeastern U.S export markets. Consumers in the northeastern U.S. generally have access to natural gas through numerous delivery and supply options. Eastern markets that historically received Canadian supplies only from TCPL's systems are now able to receive supplies from new natural gas pipelines that source U.S. and Atlantic Canada supplies. In recent years, the Canadian Mainline has experienced reductions in volumes originating at the Alberta border and in Saskatchewan, which have been partially offset by increases in volumes originating at points east of Saskatchewan. These reductions in both volumes and distance transported have resulted in an increase in Canadian Mainline tolls per unit that adversely affects its competitive position.

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

ANR competes for market share with other natural gas pipelines and storage operators in its primary markets in the U.S. Midwest. As transportation capacity has become more abundant due to major pipeline additions over the past few years, lower natural gas prices that result in less available supply could negatively affect the value of pipeline capacity. The value of ANR's natural gas storage services is based on market conditions, which could become unfavourable resulting in reduced rates and terms.

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

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

Demand for Pipeline Capacity 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.

26 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

Gas Price

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

Basin on Basin Competition

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

Technology

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

Basis Differentials

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

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

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

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 27

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

NATURAL GAS PIPELINES – OUTLOOK

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

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

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

WCSB production is expected to increase slightly in 2012. Despite reduced overall drilling levels across the WCSB, the dramatic increases in initial productivity resulting from horizontally drilled wells, in combination with a renewed focus on associated natural gas liquids, has significantly offset the anticipated negative supply impact associated with reduced levels of conventionally drilled vertical wells. Drilling activity has increased in northwestern Alberta and northeastern B.C. as producers develop projects to access deeper multi-zone gas plays, shales and tight sands utilizing horizontally-drilled wells in combination with fracking techniques. Recently, shale gas production in northeastern B.C. has emerged as a significant natural gas supply source. TCPL forecasts approximately 5 Bcf/d of total production from the Montney and Horn River shale gas sources by 2020, however, achieving this level will depend on natural gas prices as well as producer economics in the basin. The production from these two natural gas supply regions is currently approximately 1.5 Bcf/d.

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

Demand for WCSB-sourced natural gas in Eastern Canada and the U.S. Northeast decreased in 2011, largely as a result of a diversification of supply sources. However, demand for natural gas in TCPL's key eastern markets served by the Canadian Mainline is expected to increase over time, particularly to meet the expected growth in natural gas-fired power generation.

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

TCPL continues to seek opportunities in Mexico to further develop natural gas infrastructure opportunities. TCPL will leverage the experience and expertise gained on its Guadalajara and Tamazunchale pipelines and intends to participate in the $10 billion program recently announced by the Mexican government to expand its natural gas transmission infrastructure.

28 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

Earnings Canadian Natural Gas Pipelines' earnings are affected by changes in investment base, ROE, capital structure and terms of toll settlements or other toll proposals as approved by the NEB, with the most significant variables being ROE, capital structure and investment base. Absent an NEB decision in 2012 with respect to Canadian Mainline 2012 tolls, earnings from the Canadian Mainline will be lower than in 2011 as results will reflect the last approved ROE of 8.08 per cent on deemed common equity of 40 per cent, and will exclude incentive earnings that have enhanced Canadian Mainline's earnings in recent years. The Company expects continued growth of the Alberta System investment base as new supply in northeastern B.C. and western Alberta continues to be developed and connected to the Alberta System. TCPL also anticipates a modest level of investment in its other Canadian natural gas pipelines but expects a continued net decline in the average investment bases of these pipelines as annual depreciation outpaces capital investment, the result of which would have the effect of reducing year-over-year earnings from these assets. Under the current regulatory model, earnings from Canadian natural gas pipelines are not affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contract levels.

The ability to recontract unsold capacity on TCPL's U.S. pipelines and to sell capacity at attractive rates is influenced by prevailing market conditions and competitive factors, including competing natural gas pipelines and supply from other natural gas sources in these markets. EBIT from U.S. Natural Gas Pipelines' operations is also affected by the level of OM&A costs, regulatory decisions and changes in foreign currency exchange rates.

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

Capital Expenditures Total capital spending for natural gas pipelines was $0.9 billion in 2011. Capital spending for the Company's wholly owned pipelines is expected to be approximately $1.0 billion in 2012.

NATURAL GAS THROUGHPUT VOLUMES

(Bcf)	2011	2010	2009

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

⁽¹⁾: Canadian Mainline's throughput volumes reflect physical deliveries to domestic and export markets. Customer contracting patterns have changed in recent years therefore the Company uses physical deliveries to measure system utilization. Canadian Mainline physical receipts originating at the Alberta border and in Saskatchewan in 2011 were 1,160 Bcf (2010 – 1,228 Bcf; 2009 – 1,579 Bcf).
⁽²⁾: Field receipt volumes for the Alberta System in 2011 were 3,622 Bcf (2010 – 3,471 Bcf; 2009 – 3,578 Bcf) and includes three months of ATCO Pipelines receipts consistent with the commercial integration of NGTL and ATCO Pipelines effective October 1, 2011.
⁽³⁾: Effective January 14, 2011.

MANAGEMENT'S DISCUSSION AND ANALYSIS 29

OIL PIPELINES

KEYSTONE

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

30 MANAGEMENT'S DISCUSSION AND ANALYSIS

OIL PIPELINES – HIGHLIGHTS

•: Wood River/Patoka and Cushing Extension sections of Keystone achieved full commercial operations in February 2011. The Company recorded EBITDA of $587 million in its first eleven months of operations.
•: In August 2011, a favourable FEIS was received from the DOS for Keystone XL.
•: The Company secured commercial support for an extension and expansion of Keystone XL to provide crude oil transportation service from Hardisty, Alberta to Houston, Texas, increasing total long-term firm contracts on Keystone to in excess of 1.1 million bbl/d for an average term of approximately 18 years.
•: In January 2012, the DOS denied TCPL's application requesting a Presidential Permit to construct Keystone XL based on the DOS's position that they did not have sufficient time to receive and review additional information necessary to assess alternative routes that would avoid the Sandhills region of Nebraska. The Company will reapply for a Presidential Permit for Keystone XL.

OIL PIPELINES – RESULTS

Year ended December 31⁽¹⁾ (millions of dollars)	2011

Canadian Oil Pipelines Comparable EBITDA⁽²⁾	210
Depreciation and amortization	(49	)

Canadian Oil Pipelines Comparable EBIT⁽²⁾	161

U.S. Oil Pipelines Comparable EBITDA⁽²⁾ (in U.S. dollars)	383
Depreciation and amortization	(82	)

U.S. Oil Pipelines Comparable EBIT⁽²⁾	301
Foreign exchange	(3	)

U.S. Oil Pipelines Comparable EBIT⁽²⁾ (in Canadian dollars)	298

Oil Pipelines Business Development
Comparable EBITDA and EBIT⁽²⁾	(2	)

Oil Pipelines Comparable EBIT⁽²⁾	457

Summary:
Oil Pipelines Comparable EBITDA⁽²⁾	587
Depreciation and amortization	(130	)

Oil Pipelines Comparable EBIT⁽²⁾	457

⁽¹⁾: Results reflect eleven months of operations.
⁽²⁾: Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

OIL PIPELINES – FINANCIAL ANALYSIS

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 31

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

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

Although the Wood River/Patoka section commenced commercial operations in June 2010, cash flows other than general, administrative and support costs were capitalized until February 2011. As a condition of the NEB's approval to begin operations, the Wood River/Patoka section operated at a reduced maximum operating pressure (MOP) on the Canadian conversion segment of the pipeline, which did not allow the pipeline to run at design pressure and reduced throughput capacity below the initial nominal capacity of 435,000 bbl/d. After additional in-line inspections were completed, the NEB removed the MOP restriction in December 2010 and the required operational modifications were completed in late January 2011 allowing the system to operate at its design pressure and throughput capacity.

Operating Statistics

Year ended December 31⁽¹⁾		2011

Delivery volumes (thousands of barrels)⁽²⁾
	Total	137,384
	Average	411

⁽¹⁾: Results reflect eleven months of operations.
⁽²⁾: Delivery volumes reflect physical deliveries.

OIL PIPELINES – OPPORTUNITIES AND DEVELOPMENTS

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

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

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

In 2010, three entities, each of which had entered into Transportation Service Agreements for the Cushing Extension, had filed separate Statements of Claim against certain of TCPL's Keystone subsidiaries in the Alberta Court of Queen's Bench, seeking declaratory relief, or alternatively, damages in varying amounts. All of the claims have been discontinued on a without-cost and without-liability basis.

32 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

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

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

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

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

Marketlink Projects The Company is pursuing opportunities to transport growing Bakken shale crude oil production from the Williston Basin in Montana and North Dakota to major U.S. refining markets. In 2010, the Company secured firm, five-year shipper contracts totalling 65,000 bbl/d for its proposed Bakken Marketlink project, which would transport U.S. crude oil from Baker, Montana to Cushing on facilities that form part of Keystone XL. The capital cost of the incremental facilities is expected to be approximately US$140 million and, pending regulatory approvals, commercial in service is anticipated in early 2015.

In fourth quarter 2011, TCPL secured additional contractual support for the Cushing Marketlink project, which would transport crude oil from Cushing, Oklahoma to Port Arthur and Houston, Texas. The approximate US$50 million Cushing Marketlink project would use a portion of the Keystone XL facilities including the Houston Lateral. Pending regulatory approvals, Cushing Marketlink is expected to begin shipping crude oil to Port Arthur and Houston in early 2015.

MANAGEMENT'S DISCUSSION AND ANALYSIS 33

OIL PIPELINES – BUSINESS RISKS

Crude Oil Supply, Markets and Competition Alberta produces the majority of the crude oil in the WCSB and is the primary source of crude oil supply for Keystone. In 2011, the WCSB produced an estimated 2.7 million bbl/d, consisting of 1.1 million bbl/d of conventional crude oil and condensate, and 1.6 million bbl/d of Alberta oil sands crude oil. The production of conventional crude oil has been declining but has been offset by increases in production from new shale oil production including the Bakken and Cardium formations and from the oil sands. The Alberta Energy Resources Conservation Board estimated, in its June 2010 report, that there are approximately 170 billion barrels of remaining established reserves in the Alberta oil sands.

In June 2011, the Canadian Association of Petroleum Producers (CAPP) forecasted WCSB crude oil supply would increase to 3.5 million bbl/d by 2015 and to 4.5 million bbl/d by 2020, indicating future growth in Alberta crude oil production. CAPP estimated spending in the oil sands totalled $19 billion in 2011 and is expected to increase from that level in 2012.

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

The Williston Basin, located primarily in North Dakota and Montana, is the primary source of crude oil supply for the Bakken Marketlink project. In 2011, the Williston Basin achieved production rates of nearly 530,000 bbl/d. TCPL expects production levels will reach approximately 840,000 bbl/d by 2015 due to growth in Bakken shale oil production.

The Permian Basin, located primarily in western Texas, is the primary source of crude oil for the Cushing Marketlink project. Production in the Permian Basin connected to crude oil storage facilities at Cushing is more than 1.0 million bbl/d and has been growing since 2006.

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

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

Regulatory Risk Regulations and decisions issued by Canadian and U.S. regulatory bodies, including the NEB, FERC, EPA, Army Corps of Engineers, various state regulators, U.S. Department of Transportation, PHMSA and DOS, may have a significant impact on the approval, construction, operational and financial performance of TCPL's crude oil pipelines. TCPL continuously monitors existing and proposed regulations to determine their possible impact on its Oil Pipelines business.

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

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

Plant Availability Optimizing and maintaining plant availability is essential to the success of the Oil Pipelines business. TCPL has a proven history of achieving high levels of performance through the use of risk-based comprehensive preventative maintenance programs, prudent operating and capital investment and a skilled workforce. Unexpected plant outages will impact throughput capacity and may result in reduced contracted capacity payments and lower uncontracted transportation sales revenue.

34 MANAGEMENT'S DISCUSSION AND ANALYSIS

Execution and Capital Cost Risk Capital costs related to the construction of Keystone are subject to a capital cost risk- and reward-sharing mechanism with Keystone's long-term committed shippers. This mechanism allows Keystone to adjust its tolls by a factor based on the percentage change in the capital cost of the project. Tolls on Keystone XL would be adjusted by a factor equal to 75 per cent of the percentage change in capital costs. Capital costs related to the construction of the Bakken Marketlink and Cushing Marketlink projects would not be subject to a capital cost risk- and reward-sharing mechanism with the shippers.

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

OIL PIPELINES – OUTLOOK

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

Producers continue to develop new crude oil supply in Western Canada. Several Alberta oil sands projects recently completed or under construction will begin to produce crude oil or will increase crude oil production in 2012 and 2013. Alberta oil sands production is forecast to increase to 2.3 million bbl/d by 2016 from 1.6 million bbl/d in 2011 and total Western Canada crude oil supply is projected to grow over the same period to 3.7 million bbl/d from 2.7 million bbl/d. The primary market for new crude oil production extends from the U.S. Midwest to the U.S. Gulf Coast and contains a large number of refineries that are capable of handling Canadian light and heavy crude oil blends. Incremental western Canadian crude oil production is expected to replace declining U.S. imports of crude oil from other countries.

The increase in WCSB crude oil exports from Alberta requires access to new markets, including international markets and markets in the U.S., that are currently served by foreign imports. TCPL will continue to pursue additional opportunities to transport crude oil from Alberta to new markets.

Production in the Williston Basin is also growing and pipeline capacity in the region is constrained. Major markets for Williston Basin crude oil include the U.S. midcontinent and Midwest, and the U.S. Gulf Coast. TCPL is competing with several other proposals to build pipeline capacity to transport crude oil supply from this region to U.S. refining centres. Capacity is constrained on the pipelines serving the crude oil storage facilities at Cushing. This situation periodically causes the price of West Texas Intermediate crude oil to be depressed relative to world prices. There are several competitive proposals to build pipeline capacity to transport oil supply from this region to the U.S. Gulf Coast. TCPL will continue to compete for additional opportunities to transport Cushing crude oil to U.S. refining centres.

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

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 35

ENERGY

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

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

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

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

SUNDANCE A&B TCPL has the rights to 100 per cent of the generating capacity of the 560 MW Sundance A coal-fired power generating facility under a PPA that expires in 2017. TCPL also has a 50 per cent interest in ASTC Power Partnership, which has a PPA that expires in 2020, in place for 100 per cent of the production from the 706 MW Sundance B power facility. The Sundance facilities are located in south-central Alberta.

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

36 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

BRUCE POWER Bruce Power is a nuclear generating facility located northwest of Toronto, Ontario. TCPL owns 48.8 per cent of Bruce A, which has four 750 MW reactors. Two of these reactors are currently operating and two are being refurbished. TCPL owns 31.6 per cent of Bruce B, which has four operating reactors with a combined capacity of approximately 3,200 MW.

HALTON HILLS A 683 MW natural gas-fired, combined-cycle power plant in Halton Hills, Ontario.

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

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

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

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

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

TC HYDRO TC Hydro has a total generating capacity of 583 MW and comprises 13 hydroelectric facilities, including stations and associated dams and reservoirs, on the Connecticut and Deerfield rivers in New Hampshire, Vermont and Massachusetts.

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

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

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

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

CROSSALTA A 68 Bcf underground natural gas storage facility connected to the Alberta System near Crossfield, Alberta. CrossAlta's central processing system is capable of maximum injection and withdrawal rates of 550 MMcf/d of natural gas. TCPL owns 60 per cent of CrossAlta and, through an agreement made effective July 1, 2011, is now the operator of the facility.

MANAGEMENT'S DISCUSSION AND ANALYSIS 37

ENERGY – HIGHLIGHTS

•

Energy's Comparable EBIT was $940 million in 2011, an increase of $192 million from $748 million in 2010.

•

In 2011, the Company invested $1.1 billion in Energy capital projects which are all supported by long-term contracts, including:

•: the 575 MW Coolidge generating facility, which was placed in service in May 2011;
•: construction of the two remaining wind farms at Cartier Wind, including completion of the 58 MW Montagne-Sèche project and the 101 MW phase one of the Gros-Morne project; and
•: the restart of Bruce Power Units 1 and 2.

•

Refurbishment work on Bruce Power Units 1 and 2 reached significant milestones in 2011. Fuelling of both Units 1 and 2 has now been completed and the final phases of commissioning for Unit 2 are underway.

•

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

POWER PLANTS – NOMINAL GENERATING CAPACITY AND FUEL TYPE

			MW	Fuel Type

Canadian Power
	Western Power
		Sheerness	756	Coal
		Coolidge	575	Natural gas
		Sundance A	560	Coal
		Sundance B⁽¹⁾	353	Coal
		MacKay River	165	Natural gas
		Carseland	80	Natural gas
		Bear Creek	80	Natural gas
		Redwater	40	Natural gas
		Cancarb	27	Natural gas

			2,636

	Eastern Power
		Halton Hills	683	Natural gas
		Bécancour	550	Natural gas
		Cartier Wind⁽²⁾	365	Wind
		Portlands Energy⁽³⁾	275	Natural gas
		Grandview	90	Natural gas

			1,963

	Bruce⁽⁴⁾		2,480	Nuclear

			7,079

U.S. Power
	Ravenswood		2,480	Natural gas/oil
	TC Hydro		583	Hydro
	Ocean State Power		560	Natural gas
	Kibby Wind		132	Wind

			3,755

Total Nominal Generating Capacity			10,834

⁽¹⁾: Represents TCPL's 50 per cent share of the Sundance B power plant output.
⁽²⁾: Represents TCPL's 62 per cent share of the total 590 MW project, including 111 MW under construction.
⁽³⁾: Represents TCPL's 50 per cent share of the total 550 MW facility.
⁽⁴⁾: Represents TCPL's 48.8 per cent proportionate interest in Bruce A and 31.6 per cent proportionate interest in Bruce B, including 733 MW for Bruce A Units 1 and 2.

38 MANAGEMENT'S DISCUSSION AND ANALYSIS

ENERGY – RESULTS

Year ended December 31 (millions of dollars)	2011		2010		2009

Canadian Power
Western Power⁽¹⁾	489		220		279
Eastern Power⁽²⁾	314		231		220
Bruce Power	252		298		352
General, administrative and support costs	(43	)	(38	)	(39	)

Canadian Power Comparable EBITDA⁽³⁾	1,012		711		812
Depreciation and amortization	(276	)	(242	)	(227	)

Canadian Power Comparable EBIT⁽³⁾	736		469		585

U.S. Power (in U.S. dollars)
Northeast Power⁽⁴⁾	314		335		210
General, administrative and support costs	(41	)	(32	)	(40	)

U.S. Power Comparable EBITDA⁽³⁾	273		303		170
Depreciation and amortization	(109	)	(116	)	(92	)

U.S. Power Comparable EBIT⁽³⁾	164		187		78
Foreign exchange	(4	)	7		8

U.S. Power Comparable EBIT⁽³⁾ (in Canadian dollars)	160		194		86

Natural Gas Storage
Alberta Storage	89		140		173
General, administrative and support costs	(6	)	(8	)	(9	)

Natural Gas Storage Comparable EBITDA⁽³⁾	83		132		164
Depreciation and amortization	(14	)	(15	)	(14	)

Natural Gas Storage Comparable EBIT⁽³⁾	69		117		150

Energy Business Development Comparable EBITDA and EBIT⁽³⁾	(25	)	(32	)	(37	)

Energy Comparable EBIT⁽³⁾	940		748		784

Summary:
Energy Comparable EBITDA⁽³⁾	1,338		1,125		1,131
Depreciation and amortization	(398	)	(377	)	(347	)

Energy Comparable EBIT⁽³⁾	940		748		784

⁽¹⁾: Includes Coolidge effective May 2011.

MANAGEMENT'S DISCUSSION AND ANALYSIS 39

⁽²⁾: Includes Montagne-Sèche and phase one of Gros-Morne, Halton Hills, and Portlands Energy effective November 2011, September 2010 and April 2009, respectively.
⁽³⁾: Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.
⁽⁴⁾: Includes phase one and two of Kibby Wind effective October 2009 and October 2010, respectively.

ENERGY – FINANCIAL ANALYSIS

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

Western Power As at December 31, 2011, Western Power owned or had the rights to approximately 2,600 MW of power supply in Alberta and the western U.S. from its three long-term PPAs, five natural gas-fired cogeneration facilities and a simple-cycle, natural gas peaking facility in Arizona.

The current operating power supply portfolio of Western Power in Alberta comprises approximately 1,700 MW of low-cost, baseload, coal-fired generation through the three long-term PPAs and approximately 400 MW of natural gas-fired cogeneration power plants with capacity ranging from 27 MW to 165 MW. This supply portfolio includes some of the lowest cost and most competitive power generation in the Alberta market area. The Sheerness and Sundance B PPAs expire in 2020, while the Sundance A PPA expires in 2017. As described further in the Energy – Opportunities and Developments section of this MD&A, no volumes were delivered under the Sundance A PPA in 2011. A portion of the expected output from the Western Power facilities is sold under long-term contracts and the remaining output is subject to fluctuations in the price of power and natural gas.

Western Power in Alberta relies on its two integrated functions, marketing and plant operations, to generate earnings. The marketing function, based in Calgary, Alberta, purchases and resells electricity sourced through the PPAs, markets uncommitted volumes from the cogeneration facilities, and purchases and resells power and natural gas to maximize the value of the cogeneration facilities. The marketing function is critical for optimizing Energy's return from its portfolio of power supply and managing risks associated with uncontracted volumes. A portion of Energy's power is sold into the spot market to ensure supply in case of unexpected plant outages. The overall amount of spot market volumes is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management helps to minimize costs in situations where TCPL would otherwise have to purchase electricity in the open market to fulfil its contractual sales obligations. To reduce exposure to spot market prices in Alberta, as at December 31, 2011, Western Power had entered into fixed-price power sales contracts to sell approximately 8,400 gigawatt hours (GWh) in 2012 and 6,200 GWh in 2013.

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

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

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

40 MANAGEMENT'S DISCUSSION AND ANALYSIS

Bécancour's entire power output is supplied to Hydro-Québec under a 20-year power purchase contract expiring in 2026. Steam produced from this facility is sold to an industrial customer for use in commercial processes. Electricity generation at the Bécancour power plant has been suspended since January 2008 as a result of an agreement entered into with Hydro-Québec. Under the agreement, while energy production and payments are suspended, TCPL continues to receive capacity payments similar to those that would have been received under the normal course of operation.

The Montagne-Sèche and phase one of Gros-Morne Cartier Wind farms were placed in service November 2011, bringing the total generating capacity of the in-service Cartier Wind farms to 479 MW. Output from these wind farms is supplied to Hydro-Québec under 20-year power purchase contracts.

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

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

Eastern Power is focused on selling power under long-term contracts. Eastern Power sales volumes were 100 per cent sold under contract in 2011 and are expected to be fully contracted going forward.

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

Year ended December 31 (millions of dollars)		2011		2010		2009

Revenues
	Western power⁽²⁾	1,081		714		788
	Eastern power⁽³⁾	475		330		281
	Other⁽⁴⁾	70		84		86

		1,626		1,128		1,155

Commodity purchases resold
	Western power	(538	)	(431	)	(451	)
	Other⁽⁴⁾⁽⁵⁾	(9	)	(26	)	(26	)

		(547	)	(457	)	(477	)

Plant operating costs and other		(276	)	(220	)	(179	)
General, administrative and support costs		(43	)	(38	)	(39	)

Comparable EBITDA⁽¹⁾		760		413		460
Depreciation and amortization		(163	)	(140	)	(138	)

Comparable EBIT⁽¹⁾		597		273		322

⁽¹⁾: Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.
⁽²⁾: Includes Coolidge effective May 2011.
⁽³⁾: Includes Montagne-Sèche and phase one of Gros-Morne, Halton Hills, and Portlands Energy effective November 2011, September 2010 and April 2009, respectively.
⁽⁴⁾: Includes sales of excess natural gas purchased for generation and sales of thermal carbon black. The net impact of derivatives used to purchase and sell natural gas to manage Western and Eastern Power's assets is presented on a net basis in Other Revenues.
⁽⁵⁾: Includes the cost of excess natural gas not used in operations.

MANAGEMENT'S DISCUSSION AND ANALYSIS 41

Western and Eastern Canadian Power Operating Statistics

Year ended December 31		2011	2010	2009

Sales Volumes (GWh)
Supply
	Generation
	Western Power⁽¹⁾	2,606	2,373	2,334
	Eastern Power⁽²⁾	3,714	2,359	1,550
	Purchased
	Sundance A & B and Sheerness PPAs⁽³⁾	7,909	10,785	10,603
	Other purchases	1,112	429	529

		15,341	15,946	15,016

Sales
	Contracted
	Western Power	9,245	10,211	9,944
	Eastern Power	3,714	2,375	1,588
Spot
	Western Power	2,382	3,360	3,484

		15,341	15,946	15,016

Plant Availability⁽⁴⁾
	Western Power⁽¹⁾⁽⁵⁾	97%	95%	93%
	Eastern Power⁽²⁾⁽⁶⁾	93%	94%	97%

⁽¹⁾: Includes Coolidge effective May 2011.
⁽²⁾: Includes Montagne-Séche and phase one of Gros-Morne, Halton Hills and Portlands Energy effective November 2011, September 2010 and April 2009, respectively.
⁽³⁾: No volumes were delivered under the Sundance A PPA in 2011.
⁽⁴⁾: Plant availability represents the percentage of time in a year that the plant is available to generate power regardless of whether it is running.
⁽⁵⁾: Excludes facilities that provide power to TCPL under PPAs.
⁽⁶⁾: Bécancour has been excluded from the availability calculation, as power generation at the facility has been suspended since 2008.

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

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

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

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

42 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

Western Power's Comparable EBITDA of $220 million and Power Revenues of $714 million in 2010 decreased $59 million and $74 million, respectively, compared to 2009 primarily due to lower overall realized power prices. Approximately 25 per cent of Western Power's sales volumes were sold in the spot market in 2010 compared to 26 per cent in 2009.

Eastern Power's Comparable EBITDA of $231 million and Power Revenues of $330 million in 2010 increased $11 million and $49 million, respectively, compared to 2009. These increases were primarily due to incremental earnings from Halton Hills and Portlands Energy, which went in service September 2010 and April 2009, respectively, partially offset by lower contracted revenue from the Bécancour facility.

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

Bruce Power Bruce Power is a nuclear power generation facility located northwest of Toronto, Ontario and comprises Bruce A and Bruce B. Bruce A has four 750 MW reactors, two of which are being refurbished. The two units being refurbished are expected to resume commercial operations in first and third quarter 2012. Bruce B has four operating reactors with a combined capacity of 3,200 MW. As at December 31, 2011, TCPL and BPC Generation Infrastructure Trust (BPC), a trust established by the Ontario Municipal Employees Retirement System (OMERS), each owned a 48.8 per cent interest in Bruce A (2010 and 2009 – 48.8 per cent). The remaining 2.4 per cent interest in Bruce A is owned by the Power Workers' Union Trust (PWU), the Society of Energy Professionals Trust (SEP) and the Bruce Power Employee Investment Trust. Bruce A subleases Units 1 to 4 from Bruce B. TCPL, OMERS and Cameco Corporation each own 31.6 per cent of Bruce B, which consists of Units 5 to 8 and the supporting site infrastructure. The remaining interest in Bruce B is owned by PWU and SEP.

MANAGEMENT'S DISCUSSION AND ANALYSIS 43

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

Bruce Power Results

(TCPL's proportionate share) Year ended December 31 (millions of dollars unless otherwise indicated)		2011		2010		2009

Revenues⁽¹⁾		817		862		883
Operating expenses		(565	)	(564	)	(531	)

Comparable EBITDA⁽²⁾		252		298		352

Bruce A Comparable EBITDA⁽²⁾		98		91		48
Bruce B Comparable EBITDA⁽²⁾		154		207		304

Comparable EBITDA⁽²⁾		252		298		352
Depreciation and amortization		(113	)	(102	)	(89	)

Comparable EBIT⁽²⁾		139		196		263

Bruce Power – Other Information
Plant availability⁽³⁾
	Bruce A	90%		81%		78%
	Bruce B	88%		91%		91%
	Combined Bruce Power	89%		88%		87%
Planned outage days
	Bruce A	60		60		56
	Bruce B	135		70		45
Unplanned outage days
	Bruce A	16		64		82
	Bruce B	24		34		47
Sales volumes (GWh)
	Bruce A	5,475		5,026		4,894
	Bruce B	7,859		8,184		7,767

		13,334		13,210		12,661

Results per MWh
	Bruce A power revenues	$66		$65		$64
	Bruce B power revenues⁽⁴⁾	$54		$58		$64
	Combined Bruce Power revenues	$57		$60		$64

⁽¹⁾: Revenues include Bruce A fuel cost recoveries of $24 million in 2011 (2010 – $29 million; 2009 – $34 million).
⁽²⁾: Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.
⁽³⁾: Plant availability represents the percentage of time in a year that the plant is available to generate power regardless of whether it is running.
⁽⁴⁾: Includes revenues received under the floor price mechanism, from contract settlements as well as volumes and revenues associated with deemed generation.

TCPL's proportionate share of Bruce Power's Comparable EBITDA decreased $46 million to $252 million in 2011 compared to 2010, primarily due to lower results at Bruce B. Comparable EBITDA in 2010 also included the net positive impact of a payment made in 2010 by Bruce B to Bruce A related to amendments made in 2009 to the agreements with the OPA. The net positive impact to TCPL from the payment reflected TCPL's higher percentage ownership in Bruce A.

44 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

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

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

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

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

Bruce A

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

Bruce A Fixed Price

		per MWh

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

Bruce B

As part of Bruce Power's contract with the OPA, all output from Bruce B Units 5 to 8 is subject to a floor price adjusted annually for inflation on April 1. Payments received under the floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. No amounts recorded in revenues were subject to repayment in 2011, 2010 or 2009.

Bruce B Floor Price

		per MWh

April 1, 2011 – March 31, 2012		$50.18
April 1, 2010 – March 31, 2011		$48.96
April 1, 2009 – March 31, 2010		$48.76

Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price. Bruce B's realized price decreased by $4 per MWh to $54 per MWh in 2011 compared to 2010, and by $6 per MWh to $58 per MWh in 2010 compared to 2009, and reflected revenues recognized from the floor

MANAGEMENT'S DISCUSSION AND ANALYSIS 45

price mechanism, contract settlements as well as volumes and revenues associated with deemed generation. The decreases reflected the expiration of higher-priced contracts entered into in previous years.

U.S. Power U.S. Power owns approximately 3,800 MW of power generation capacity, consisting of Ravenswood, TC Hydro, Ocean State Power, and Kibby Wind. Ravenswood, located in Queens, New York, is a 2,480 MW natural gas and oil-fired generating facility consisting of multiple units employing steam turbine, combined-cycle and combustion turbine technology. The TC Hydro assets include 13 hydroelectric stations housing a total of 39 hydroelectric generating units in New Hampshire, Vermont and Massachusetts with total generating capacity of 583 MW. Ocean State Power, a 560 MW natural gas-fired combined-cycle facility, is the largest power plant in Rhode Island and Kibby Wind is a 132 MW wind farm located in Maine. The first 66 MW phase of Kibby Wind was placed in service in October 2009 and the second 66 MW phase went in service in October 2010.

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

The New York Independent System Operator (NYISO) relies on a locational capacity market intended to promote investment in new and existing power resources needed to meet growing consumer demand and maintain a reliable power system. At present, a series of voluntary forward auctions and a mandatory spot demand curve price setting process are used to determine the price paid to capacity suppliers. There are two annual six-month strip forward auctions and 12 monthly forward auctions in which buyer and seller participation is optional. All remaining available capacity is required to participate in a monthly spot auction in the final week prior to each capacity month. The spot auction clears at a price based on a downward-sloping demand curve, the parameters of which are determined by the NYISO and approved by the FERC. There are separate demand curves for each of three defined capacity zones: Long Island, New York City and Rest of State. The Ravenswood capacity is located in the New York City capacity zone. Refer to the Energy – Opportunities and Development section of this MD&A for more information.

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

U.S. Power Comparable EBIT⁽¹⁾⁽²⁾

Year ended December 31 (millions of U.S. dollars)		2011		2010		2009

Revenues
	Power⁽³⁾	919		1,090		742
	Capacity	227		231		169
	Other⁽³⁾⁽⁴⁾	80		78		79

		1,226		1,399		990

Commodity purchases resold⁽³⁾		(398	)	(543	)	(309	)
Plant operating costs and other⁽⁴⁾		(514	)	(521	)	(471	)
General, administrative and support costs		(41	)	(32	)	(40	)

Comparable EBITDA⁽¹⁾		273		303		170
Depreciation and amortization		(109	)	(116	)	(92	)

Comparable EBIT⁽¹⁾		164		187		78

⁽¹⁾: Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

46 MANAGEMENT'S DISCUSSION AND ANALYSIS

⁽²⁾: Includes phases one and two of Kibby Wind as of October 2009 and October 2010, respectively.
⁽³⁾: Realized gains and losses from financial derivatives used to purchase and sell power, natural gas and fuel oil to manage U.S. Power's assets are presented on a net basis in Power Revenues.
⁽⁴⁾: Includes revenues and costs related to a third-party service agreement at Ravenswood.

U.S. Power Operating Statistics⁽¹⁾

Year ended December 31		2011	2010	2009

Physical Sales Volumes (GWh)
Supply
	Generation	6,880	6,755	5,993
	Purchased	6,018	8,899	5,310

		12,898	15,654	11,303

Plant Availability⁽²⁾		87%	86%	79%

⁽¹⁾: Includes phases one and two of Kibby Wind as of October 2009 and October 2010, respectively.
⁽²⁾: Plant availability represents the percentage of time in a year that the plant is available to generate power regardless of whether it is running.

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

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

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

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

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

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

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

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 47

Natural Gas Storage TCPL owns or has rights to 129 Bcf of non-regulated natural gas storage capacity in Alberta, including a 60 per cent ownership interest in CrossAlta. TCPL also has contracts for long-term, Alberta-based storage capacity from a third party, which expire in 2030, subject to early termination rights in 2015.

Natural Gas Storage Capacity

	Working Gas Storage Capacity (Bcf)	Maximum Injection/ Withdrawal Capacity (MMcf/d)

Edson	50	725
CrossAlta⁽¹⁾	41	550
Third-party storage	38	630

	129	1,905

⁽¹⁾: Represents TCPL's 60 per cent ownership interest in CrossAlta. Working gas storage capacity can vary due to the amount of base gas in the facility.

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

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

Market volatility creates arbitrage opportunities and TCPL's storage facilities provide customers with the ability to capture value from short-term price movements. At December 31, 2011, TCPL had contracted approximately 60 per cent of the total 129 Bcf of working gas storage capacity in 2012 and 20 per cent of storage capacity in 2013. Earnings from third-party storage capacity contracts are recognized over the terms of the contracts.

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

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

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

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

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

48 MANAGEMENT'S DISCUSSION AND ANALYSIS

ENERGY – OPPORTUNITIES AND DEVELOPMENTS

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

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

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

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

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

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

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

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

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

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

Ontario Solar In December 2011, TCPL agreed to purchase nine Ontario solar projects from Canadian Solar Solutions Inc., with a combined capacity of 86 MW, for approximately $470 million. Under the terms of the agreement, each of the nine solar projects will be developed and constructed by Canadian Solar Solutions Inc. using photovoltaic

MANAGEMENT'S DISCUSSION AND ANALYSIS 49

panels. TCPL will purchase each project once construction and acceptance testing have been completed and operations have begun under 20-year PPAs with the OPA under the Feed-In Tariff program in Ontario. TCPL anticipates the projects will be placed in service between late 2012 and mid-2013, subject to regulatory approvals.

Bécancour In June 2011, Hydro-Québec notified TCPL it would exercise its option to extend the agreement to suspend all electricity generation from the Bécancour power plant throughout 2012. Under the terms of the suspension agreement, Hydro-Québec has the option, subject to certain conditions, to extend the suspension on an annual basis until such time as regional electricity demand levels recover. TCPL will continue to receive capacity payments under the agreement similar to those that would have been received under the normal course of operation while energy production and payments are suspended.

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

During third quarter 2011, the demand curve reset process was completed following the FERC's acceptance of the NYISO's September 22, 2011 compliance filing. This resulted in increased demand curve rates that apply going forward to 2014. Until the above noted NYISO actions relative to new unit pricing are resolved, capacity prices are expected to remain volatile.

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

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

ENERGY – BUSINESS RISKS

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

Sales of uncontracted power volumes into the spot market in Alberta and the U.S. northeast can be subject to price volatility, directly affecting earnings. To mitigate this risk, TCPL commits a portion of its supply to medium-term to long-term sales contracts while retaining an amount of unsold supply to mitigate the financial impact of unexpected plant outages and to provide flexibility in managing the Company's portfolio of wholly owned assets. This unsold supply is subsequently sold under shorter-term forward arrangements or into the spot market and is exposed to fluctuating power and natural gas market prices. As power sales contracts expire, new forward contracts are entered into at prevailing market prices.

Under an agreement with the OPA, Bruce B volumes are subject to a floor price mechanism. When the spot market price is above the floor price, Bruce B's non-contracted volumes are subject to spot price volatility. When spot prices are below the floor price, Bruce B receives the floor price for all of its output. Bruce B also enters into third party fixed-price contracts where it receives the difference between the contract price and spot price. All Bruce A output is sold into the

50 MANAGEMENT'S DISCUSSION AND ANALYSIS

Ontario wholesale power spot market under a fixed-price contract with the OPA. All Bruce A output will be subject to spot market pricing effective June 1, 2012 until the restart of both Units 1 and 2 is complete.

Energy's natural gas storage business is subject to fluctuating natural gas seasonal spreads generally determined by the differential in natural gas prices in the traditional summer injection and winter withdrawal seasons.

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

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

Weather Extreme temperature and weather events in North America often create price volatility and variable demand for power and natural gas. These events may also restrict the availability of power and natural gas. Seasonal changes in temperature can also affect the efficiency and output capability of natural gas-fired power plants. Variability in wind speeds impact the earnings of Energy's wind assets.

Hydrology TCPL's power operations are subject to hydrology risk arising from the ownership of hydroelectric power generation facilities in the northeastern U.S. Weather changes, weather events, local river management and potential dam failures at these plants or upstream facilities pose potential risks to the Company.

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

Regulation of Power Markets TCPL operates in both regulated and deregulated power markets. As power markets evolve across North America, there is the potential for regulatory bodies to implement new rules that could negatively affect TCPL as a generator and marketer of electricity. These may be in the form of market rule changes, changes in the interpretation and application of market rules by regulators, price caps, emission controls, unfair cost allocations to generators and out-of-market actions taken by others to build excess generation, all of which negatively affect the price of capacity or energy, or both. In addition, TCPL's development projects rely on an orderly permitting process and any disruption to that process can have negative effects on project schedules and costs. TCPL is an active participant in formal and informal regulatory proceedings and takes legal action where required.

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 51

ENERGY – OUTLOOK

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

Ontario's 2011 average power demand was down 0.5 per cent compared to 2010. New renewable energy projects came in service in 2011 and the IESO projects a further 2,500 MW of new and refurbished power supply additions by early 2013. This increase in supply, combined with lower natural gas prices plus weak 2011 Ontario economic growth of about two per cent resulted in a decrease in the year-over-year average hourly Ontario energy price from $36/MWh in 2010 to $30/MWh in 2011. The IESO forecasts a return to power demand growth in 2012, however, future power demand growth rates are expected to be modest, as a full return of the energy intensive industries lost in the recession is not expected. TCPL's existing energy assets in Ontario are largely insulated from changes in the market price of power through contracts with the OPA.

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

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

Earnings TCPL expects that results from its Energy operations in 2012 will be higher than those in 2011. There will be a positive earnings impact from a full year of Coolidge, Montagne-Sèche and the first phase of Gros-Morne, which all came in service during 2011. Additional earnings from Bruce Power will also be realized with the return to service of Unit 2, which is expected in first quarter 2012, followed by Unit 1 which is expected in third quarter 2012. It is also anticipated that the nine solar projects TCPL agreed to purchase in late 2011 will come in service between late 2012 and mid-2013 pending certain conditions and approvals. Output from these plants, as well as a significant portion of output from Energy's other assets, has been sold under long-term contracts and provides a stable earnings base for the Energy business.

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

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

Other factors such as plant availability, regulatory changes, weather, currency movements and overall stability of the energy industry can also affect 2012 EBIT. Refer to the Energy – Business Risks section in this MD&A for a complete discussion of these and other factors affecting the Energy Outlook.

52 MANAGEMENT'S DISCUSSION AND ANALYSIS

CORPORATE

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

OTHER INCOME STATEMENT ITEMS

COMPARABLE INTEREST EXPENSE

Year Ended December 31 (millions of dollars)		2011		2010		2009

Comparable Interest on long-term debt⁽¹⁾
	Canadian dollar-denominated	490		514		548
	U.S. dollar-denominated	734		680		645
	Foreign exchange	(7	)	20		92

		1,217		1,214		1,285
Other interest and amortization		131		127		59
Capitalized interest		(302	)	(587	)	(358	)

Comparable Interest Expense		1,046		754		986

⁽¹⁾: Includes interest on Junior Subordinated Notes.

Comparable Interest Expense increased in 2011 by $292 million to $1,046 million compared to 2010. This increase was primarily due to decreased capitalized interest upon placing Keystone and Coolidge in service in 2011 and Halton Hills in service in the latter part of 2010. Comparable Interest on long-term debt increased in 2011 compared to 2010 primarily due to new debt issues of US$1.0 billion in September 2010 and US$1.25 billion in June 2010. This was offset by the impact of a weaker U.S. dollar and the decrease in interest expense on Canadian dollar-denominated debt from debt maturities. Other Interest and Amortization Expense in 2011 was positively affected by increased gains from changes in the fair value of derivatives used to manage TCPL's exposure to fluctuating interest rates.

Comparable Interest Expense in 2010 decreased $232 million to $754 million from $986 million in 2009. Interest on Canadian dollar-denominated debt decreased in 2010 compared to 2009 primarily due to debt maturities. Interest on U.S. dollar-denominated debt increased in 2010 compared to 2009 due to new debt issues of US$1.0 billion in September 2010, US$1.25 billion in June 2010 and US$2.0 billion in January 2009, partially offset by the impact of a weaker U.S. dollar. Other Interest and Amortization Expense in 2010 was negatively affected by additional financing charges on committed credit facilities and increased losses from changes in the fair value of derivatives used to manage TCPL's exposure to fluctuating interest rates. Interest Expense was positively impacted by higher capitalization of interest in 2010 relating to the Company's larger capital spending program primarily for the construction of Keystone and refurbishment and restart of Bruce A Units 1 and 2.

Comparable Interest Income and Other was $60 million in 2011 compared to $94 million and $119 million in 2010 and 2009, respectively. The decrease in 2011 compared to 2010 was primarily due to lower gains from derivatives used to manage the Company's exposure to foreign exchange rate fluctuations. The decrease in 2010 compared to 2009 was primarily due to the positive impact of a weakening U.S. dollar on the translation of U.S. dollar working capital balances throughout each year and gains in 2010 on derivatives used to manage foreign exchange fluctuations.

Comparable Income Taxes were $566 million, $385 million and $395 million in 2011, 2010, and 2009, respectively. The increase of $181 million in 2011 compared to 2010 was primarily due to increased pre-tax earnings and higher positive income tax adjustments in 2010 compared to 2011. In 2011 and 2010, the Company recorded a benefit in Current Income Taxes with an offsetting provision in Future Income Taxes as a result of bonus depreciation for U.S. income tax purposes on the Bison pipeline which was placed in service in January 2011 and the Wood River/Patoka and Cushing Extension sections of Keystone which were placed in operational service in June 2010 and February 2011, respectively. The decrease of $10 million in 2010 compared to 2009 was primarily due to increased pre-tax earnings offset by higher positive income tax adjustments in 2010.

MANAGEMENT'S DISCUSSION AND ANALYSIS 53

Non-Controlling Interests were $107 million in 2011 compared to $93 million and $74 million in 2010 and 2009, respectively. The $14 million increase in 2011 compared to 2010 was primarily due to the sale of a 25 per cent interest in GTN and Bison to TC PipeLines, LP and reduction in the Company's ownership interest in TC PipeLines, LP in May 2011 partially offset by the impact of a weaker US dollar in 2011. The increase in 2010 compared to 2009 was primarily due to increased TC PipeLines, LP earnings as a result of higher revenues from Northern Border and the acquisition by TC PipeLines, LP of North Baja, partially offset by the impact of a weaker US dollar in 2010.

LIQUIDITY AND CAPITAL RESOURCES

TCPL believes that its financial position remains sound as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, and provide for planned growth. TCPL's liquidity is underpinned by predictable cash flow from operations, available cash balances and unutilized committed revolving bank lines of US$1.0 billion, $2.0 billion, US$1.0 billion and US$300 million, maturing in November 2012, October 2016, October 2012 and February 2013, respectively. These facilities also support the Company's three commercial paper programs. In addition, at December 31, 2011, TCPL's proportionate share of unutilized capacity on committed bank facilities at TCPL-operated affiliates was $0.1 billion with maturity dates in 2012 and 2016. As at December 31, 2011, TCPL had capacity of $1.25 billion and US$4.0 billion under its Canadian debt and U.S. debt shelf prospectuses, respectively. TCPL's liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section in this MD&A.

SUMMARIZED CASH FLOW

Year ended December 31 (millions of dollars)	2011	2010		2009

Funds generated from operations⁽¹⁾	3,572	3,279		3,044
Decrease/(Increase) in operating working capital	282	(256	)	(88	)

Net Cash Provided by Operations	3,854	3,023		2,956

⁽¹⁾: Refer to the Non-GAAP Measures section in this MD&A for further discussion of Funds Generated from Operations.

HIGHLIGHTS

Investing Activities

•: Capital expenditures and acquisitions, including assumed debt, totalled approximately $15 billion over the three-year period ending December 31, 2011.

Dividends

•: TCPL's Board of Directors declared a dividend for the quarter ending March 31, 2012 in an aggregate amount equal to the quarterly dividend to be paid on TransCanada's issued and outstanding common shares at the close of business on March 30, 2012. The dividend is payable on April 30, 2012. The Board of Directors also declared a dividend of $0.70 per share on TCPL's Series U and Series Y preferred shares for the period ending April 30, 2012 and May 1, 2012, respectively. The dividend for the Series U and Series Y preferred shares is payable on April 30, 2012 and May 1, 2012, respectively, to shareholders of record at the close of business on March 30, 2012.

CASH FLOW AND CAPITAL RESOURCES

Cash Generated from Operations

Net Cash Provided by Operations was $3.9 billion in 2011 compared to $3.0 billion and $3.0 billion in 2010 and 2009, respectively. Net Cash Provided by Operations reflects Funds Generated from Operations, net of changes in operating working capital.

54 MANAGEMENT'S DISCUSSION AND ANALYSIS

Funds Generated from Operations

Funds Generated from Operations were $3.6 billion in 2011 compared to $3.3 billion and $3.0 billion in 2010 and 2009, respectively. The increase in 2011 compared to 2010 was primarily due to increased cash from earnings. This increase was net of lower current income tax benefits from bonus depreciation for U.S. tax purposes recognized in 2011 compared to 2010. The increase in 2010 compared to 2009 was primarily due to the current income tax benefit generated from bonus depreciation for U.S. tax purposes on Keystone assets placed in service in June 2010.

As at December 31, 2011, TCPL's current liabilities were $5.9 billion and current assets were $4.4 billion resulting in a working capital deficiency of $1.5 billion. The Company believes this shortfall can be managed through its ability to generate cash flow from operations, access to the unutilized committed revolving bank lines in excess of $4.0 billion, discussed above, as well as its ongoing access to capital markets.

Investing Activities

Capital expenditures totalled $3.3 billion in 2011 compared to $5.0 billion in 2010 and $5.4 billion in 2009. Expenditures in 2011, 2010 and 2009 related primarily to the completion of the Wood River/Patoka and Cushing Extension Sections of Keystone, advancement of Keystone XL, the refurbishment and restart of Units 1 and 2 at Bruce A, construction of other new pipeline and power facilities, and the expansion and maintenance of existing pipelines.
In August 2009, the Company purchased ConocoPhillips' remaining interest of approximately 20 per cent in Keystone for US$553 million plus the assumption of US$197 million of short-term debt. In the first seven months of 2009, TCPL solely funded $1.3 billion of cash calls for Keystone, resulting in the Company acquiring an incremental increase in ownership of approximately 18 per cent for $313 million.

Financing Activities

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

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

At December 31, 2011, total committed revolving and demand credit facilities of $5.1 billion were available to support the Company's commercial paper programs and for general corporate purposes. These unsecured credit facilities included the following:

•: a $2.0 billion committed, syndicated, revolving, extendible credit facility, maturing October 2016. The facility was fully available at December 31, 2011 and supports TCPL's Canadian commercial paper program;
•: a US$300 million committed, syndicated, revolving credit facility maturing February 2013. At December 31, 2011, this facility was fully available. This facility is part of an initial US$1.0 billion TransCanada PipeLine USA Ltd. (TCPL USA) credit facility established in 2007 which has since been reduced through term loan repayments of US$200 million in August 2011 and US$500 million in January 2012;
•: a US$1.0 billion committed, syndicated, revolving, extendible TransCanada Keystone Pipeline, LP credit facility, maturing November 2012. The facility was fully available at December 31, 2011 and supports a TCPL USA U.S. dollar commercial paper program dedicated to funding a portion of capital expenditures for Keystone;
•: a US$1.0 billion committed, syndicated, revolving, extendible TCPL USA credit facility, maturing October 2012. The facility was fully available at December 31, 2011 and supports a TCPL U.S. dollar commercial paper program that was established in December 2011; and

MANAGEMENT'S DISCUSSION AND ANALYSIS 55

•: demand lines totalling $802 million, which support the issuance of letters of credit and provide additional liquidity. At December 31, 2011, the Company had used approximately $468 million of these demand lines for letters of credit.

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

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

Related Party Debt Financing

Related party transactions consist of amounts due to and from TransCanada as well as accrued interest income and expense.

In December 2011, TransCanada issued discount notes of $2.8 billion, maturing in June 2012, to TCPL. Interest on the notes is equivalent to current commercial paper rates. These notes were used for general corporate purposes.

TransCanada has established a $3.5 billion, unsecured credit facility agreement with TCPL, bearing interest at Reuters prime plus 75 basis points. Funds advanced under this agreement will be used to repay indebtedness, make partner contributions to Bruce A, and for working capital and general corporate purposes. At December 31, 2011, $0.7 million was outstanding on this credit facility (2010 – $2.7 billion). This credit agreement matures on December 15, 2012.

In September 2010, TCPL increased its demand revolving credit facility with TransCanada to $2.0 billion from $1.5 billion or its U.S. dollar equivalent amount. The facility bears interest at the Royal Bank of Canada prime rate per annum or the U.S. base rate per annum and will be used for general corporate purposes. At December 31, 2011, $1.4 billion was outstanding on this facility (2010 – $1.2 billion).

In 2011, Interest Expense included $140 million (2010 – $70 million; 2009 – $52 million) of interest expense and $35 million (2010 – $19 million; 2009 – $20 million) of interest income as a result of transactions with TransCanada. At December 31, 2011 Accounts Payable included $2 million of interest payable to TransCanada (2010 – $6 million).

2011 Long-Term Debt Financing Activities

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

2011 Equity Financing Activities

In December 2011, TCPL issued 56.3 million common shares to TransCanada for proceeds of $2.4 billion. The proceeds of these issues were used partially to fund capital projects, for general corporate purposes and to repay short-term debt of TCPL.

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

56 MANAGEMENT'S DISCUSSION AND ANALYSIS

Dividend Reinvestment and Share Purchase Plan

TransCanada's Board of Directors has authorized the issuance of common shares to participants in TransCanada's Dividend Reinvestment and Share Purchase Plan (DRP). Under this plan, eligible holders of common and preferred shares of TransCanada and preferred shares of TCPL may reinvest their dividends and make optional cash payments to obtain TransCanada common shares. TransCanada reserves the right to satisfy its DRP obligations by issuing common shares from treasury at a discount of up to five per cent or by purchasing shares on the open market. Commencing with the dividends declared in April 2011, common shares obtained with reinvested cash dividends are satisfied with shares acquired on the open market at 100 per cent of the weighted average purchase price. Previously, common shares obtained with reinvested cash dividends were satisfied with shares issued from treasury at a discount to the average market price in the five days before dividend payment. The discount was set at three per cent in 2009 and 2010, and was reduced to two per cent commencing with the dividends declared in February 2011.

Dividends

Cash dividends on common and preferred shares amounting to $1.2 billion were paid in 2011 (2010 – $1.1 billion; 2009 – $998 million). The increase in dividends paid in 2011 compared to 2010 was primarily due to a greater number of common shares outstanding.

In February 2012, TCPL's Board of Directors declared a dividend for the quarter ending March 31, 2012 in an aggregate amount equal to the quarterly dividend to be paid on TransCanada's issued and outstanding common shares at the close of business on March 30, 2012. In addition, the Board of Directors declared regular dividends of $0.70 per share on TCPL's preferred Series U and Series Y shares payable to shareholders of record at the close of business on March 30, 2012.

CONTRACTUAL OBLIGATIONS

Obligations and Commitments

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

CONTRACTUAL OBLIGATIONS

		Payments Due by Period

Year ended December 31 (millions of dollars)	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years

Long-term debt⁽¹⁾	20,204	950	1,926	2,467	14,861
Capital lease obligations	194	18	42	57	77
Operating leases⁽²⁾	735	79	152	143	361
Purchase obligations	9,152	1,650	2,905	1,568	3,029
Other long-term liabilities reflected on the balance sheet	911	17	35	39	820

	31,196	2,714	5,060	4,274	19,148

⁽¹⁾: Includes Junior Subordinated Notes and Long-Term Debt of Joint Ventures, excluding capital lease obligations.
⁽²⁾: Represents future annual payments, net of sub-lease receipts, for various premises, services and equipment. The operating lease agreements for premises, services and equipment expire at various dates through 2052 with an option to renew certain lease agreements for one to 10 years.

MANAGEMENT'S DISCUSSION AND ANALYSIS 57

TCPL's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Future payments under these PPAs have been excluded from operating leases in the above table, as these payments are dependent upon plant availability among other factors. TCPL's share of power purchased under the PPAs in 2011 was $394 million (2010 – $363 million; 2009 – $384 million).

At December 31, 2011, scheduled principal repayments and interest payments related to long-term debt and the Company's proportionate share of the long-term debt of joint ventures were as follows:

PRINCIPAL REPAYMENTS

		Payments Due by Period

Year ended December 31 (millions of dollars)	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years

Long-term debt	18,567	935	1,874	2,311	13,447
Junior subordinated notes	1,009	–	–	–	1,009
Long-term debt of joint ventures	628	15	52	156	405

	20,204	950	1,926	2,467	14,861

INTEREST PAYMENTS

		Payments Due by Period

Year ended December 31 (millions of dollars)	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years

Long-term debt	16,541	1,180	2,227	1,989	11,145
Junior subordinated notes⁽¹⁾	355	65	129	129	32
Long-term debt of joint ventures	343	48	89	77	129

	17,239	1,293	2,445	2,195	11,306

⁽¹⁾: Payments were calculated assuming the notes would be redeemed after 10 years.

58 MANAGEMENT'S DISCUSSION AND ANALYSIS

At December 31, 2011, the Company's approximate future purchase obligations were as follows:

PURCHASE OBLIGATIONS⁽¹⁾

		Payments Due by Period

Year ended December 31 (millions of dollars)	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years

Natural Gas Pipelines
Transportation by others⁽²⁾	482	130	133	108	111
Capital expenditures⁽³⁾⁽⁴⁾	250	248	2	–	–
Other	1	1	–	–	–
Oil Pipelines
Capital expenditures⁽³⁾⁽⁵⁾	992	98	894	–	–
Other	48	4	8	8	28
Energy
Commodity purchases⁽⁶⁾	5,121	666	1,201	1,221	2,033
Capital expenditures⁽³⁾⁽⁷⁾	290	234	56	–	–
Other⁽⁸⁾	1,928	254	587	231	856
Corporate
Information technology and other	40	15	24	–	1

	9,152	1,650	2,905	1,568	3,029

⁽¹⁾: The amounts in this table exclude funding contributions to pension plans.
⁽²⁾: Rates are based primarily on known 2011 levels. Beyond 2011, demand rates are subject to change. The purchase obligations in the table are based on known or contracted demand volumes only and exclude commodity charges incurred when volumes flow.
⁽³⁾: Amounts are estimates and are subject to variability based on timing of construction and project enhancements. The Company expects to fund capital projects with cash from operations, the issuance of senior debt and, if required, subordinated capital, and through portfolio management.
⁽⁴⁾: Capital expenditures primarily relate to the construction costs of the Alberta System expansion, Guadalajara and other natural gas pipeline projects.
⁽⁵⁾: Capital expenditures primarily relate to Keystone XL.
⁽⁶⁾: Commodity purchases include fixed and variable components and excludes derivatives. The variable components are estimates and are subject to variability in plant production, market prices and regulatory tariffs.
⁽⁷⁾: Capital expenditures primarily relate to TCPL's share of the construction and development costs of Bruce Power and Cartier Wind.
⁽⁸⁾: Includes estimates of certain amounts that are subject to change depending on plant-fired hours, the consumer price index, actual plant maintenance costs, plant salaries and changes in regulated rates for transportation. This includes the purchase obligation for Ontario Solar.

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

In 2012, TCPL expects to make funding contributions of approximately $119 million to its defined benefit pension plans (DB Plan) and approximately $31 million to the Company's other post-retirement benefit plans, savings plan and defined contribution pension plans. In addition to these contributions, the Company expects to provide a $48 million letter of credit in 2012 to the DB Plan. In 2011, the Company made total cash funding contributions of $93 million and provided a $27 million letter of credit to the DB Plan. TCPL's proportionate share of cash funding contributions expected to be made by joint ventures to their respective pension and other post-retirement benefit plans in 2012 is approximately $73 million and $7 million, respectively, compared to total contributions of $59 million in 2011.

The next actuarial valuation for the Company's pension and other post-retirement benefit plans will be carried out as at January 1, 2013. Based on current market conditions, TCPL expects funding requirements for these plans to continue at

MANAGEMENT'S DISCUSSION AND ANALYSIS 59

the anticipated 2012 level for the next several years to amortize solvency deficiencies in addition to normal costs. The Company's 2012 net benefit cost is expected to increase from 2011 primarily due to a lower projected discount rate. However, future net benefit costs and the amount of funding contributions will be dependent on various factors, including investment returns achieved on plan assets, the level of interest rates, changes to plan design and actuarial assumptions, actual plan experience versus projections and amendments to pension plan regulations and legislation. Increases in the level of required plan funding are not expected to have a material impact on the Company's liquidity.

Bruce Power

Bruce A has signed commitments to third-party suppliers related to refurbishing and restarting Units 1 and 2. TCPL's share of these signed commitments is $95 million. The Company expects $88 million and $7 million to be paid in 2012 and 2013, respectively.

Ontario Solar

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

Contingencies

TCPL is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2011, the Company had accrued approximately $49 million (2010 – $59 million) related to operating facilities, which represents the estimated amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue.

TCPL and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.

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

Guarantees

TCPL and its joint venture partners on Bruce Power, Cameco Corporation and BPC, have severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, a lease agreement and contractor services. The guarantees have terms ranging from 2018 to perpetuity. In addition, TCPL and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the OPA to refurbish and restart Bruce A power generation units. The guarantees have terms ending in 2018 and 2019. TCPL's share of the potential exposure under these Bruce A and Bruce B guarantees was estimated to be $863 million at

60 MANAGEMENT'S DISCUSSION AND ANALYSIS

December 31, 2011. The fair value of these Bruce Power guarantees at December 31, 2011 is estimated to be $29 million. The Company's exposure under certain of these guarantees is unlimited.

In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, PPA payments and the payment of liabilities. TCPL's share of the potential exposure under these assurances was estimated at December 31, 2011 to range from $182 million to a maximum of $498 million. The fair value of these guarantees at December 31, 2011 is estimated to be $7 million, which has been included in Deferred Amounts. For certain of these entities, any payments made by TCPL under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

FINANCIAL RISKS AND FINANCIAL INSTRUMENTS

Risk Management Overview

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

Risk management strategies, policies and limits are designed to ensure TCPL's risks and related exposures are in line with the Company's business objectives and risk tolerance. Risks are managed within limits ultimately established by the Company's Board of Directors, implemented by senior management and monitored by risk management and internal audit personnel. The Board of Directors' Audit Committee oversees how management monitors compliance with financial risk management policies and procedures, and oversees management's review of the adequacy of the risk management framework. Internal audit personnel assist the Audit Committee in its oversight role by performing regular and ad-hoc reviews of risk management controls and procedures, the results of which are reported to the Audit Committee.

Market Risk

The Company constructs and invests in large infrastructure projects, purchases and sells energy commodities, issues short-term and long-term debt, including amounts in foreign currencies, and invests in foreign operations. These activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which affect the Company's earnings and the value of the financial instruments it holds.

The Company uses derivatives as part of its overall risk management strategy to manage the exposure to market risk that results from these activities. Derivative contracts used to manage market risk generally consist of the following:

•: Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TCPL enters into foreign exchange and commodity forwards and futures to mitigate the impact of volatility in foreign exchange rates and commodity prices.
•: Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices.
•: Options – contractual agreements to convey the right, but not the obligation, of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices.

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 61

Commodity Price Risk

The Company is exposed to commodity price movements as part of its normal business operations, particularly in relation to the prices of electricity and natural gas. A number of strategies are used to mitigate these exposures, including the following:

•: Subject to its overall risk management strategy, the Company commits a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to mitigate operational and price risks in its asset portfolio.
•: The Company purchases a portion of the natural gas required for its power plants or enters into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin.
•: The Company's power sales commitments are fulfilled through power generation or purchased through contracts, thereby reducing the Company's exposure to fluctuating commodity prices.
•: The Company enters into offsetting or back-to-back positions using derivative financial instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.

The Company assesses its commodity contracts and derivative instruments used to manage commodity risk to determine the appropriate accounting treatment. Contracts, with the exception of leases, have been assessed to determine whether they or certain aspects of them meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but fair value accounting is not required, as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's expected purchase, sale or usage requirements and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain exemptions.

Natural Gas Storage Commodity Price Risk

TCPL manages its exposure to seasonal natural gas price spreads in its non-regulated Natural Gas Storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TCPL simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to natural gas price movements. Fair value adjustments recorded each period on proprietary natural gas inventory in storage and on these forward contracts are not representative of the amounts that will be realized on settlement.

Foreign Exchange and Interest Rate Risk

Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates.

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

The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to its debt and other U.S. dollar-denominated transactions, and to manage the foreign exchange rate exposures of the Alberta System and Foothills operations. Certain of the realized gains and losses on these derivatives are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers in accordance with the terms of the shipping agreements.

TCPL has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk.

62 MANAGEMENT'S DISCUSSION AND ANALYSIS

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At December 31, 2011, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $10 billion (US$9.8 billion) (2010 – $9.8 billion (US$9.8 billion)) and a fair value of $12.7 billion (US$12.5 billion) (2010 – $11.3 billion (US$11.4 billion)). At December 31, 2011, $79 million (December 31, 2010 – nil) was included in Other Current Assets, $66 million (December 31, 2010 – $181 million) was included in Intangibles and Other Assets, $15 million (December 31, 2010 – nil) was included in Accounts Payable, and $41 million (December 31, 2010 – nil) was included in Deferred Amounts for the fair value of the forwards and swaps used to hedge the Company's net U.S. dollar investment in foreign operations.

The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows:

Asset/(Liability)

		2011			2010
December 31 (millions of dollars)		Fair Value⁽¹⁾		Notional or Principal Amount	Fair Value⁽¹⁾	Notional or Principal Amount

U.S. dollar cross-currency swaps
	(maturing 2012 to 2018)	93		US 3,850	179	US 2,800
U.S. dollar forward foreign exchange contracts
	(maturing 2012)	(4	)	US 725	2	US 100

		89		US 4,575	181	US 2,900

⁽¹⁾: Fair values equal carrying values.

VaR Analysis

TCPL uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its liquid open positions. VaR represents the potential change in pre-tax earnings over a given holding period for a specified confidence level. The VaR number used by TCPL is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its liquid open positions will not exceed the reported VaR. The VaR methodology is a statistically calculated, probability-based approach that takes into consideration market volatilities as well as risk diversification by recognizing offsetting positions and correlations among products and markets. Risks are measured across all products and markets, and risk measures are aggregated to arrive at a single VaR number.

There is currently no uniform industry methodology for estimating VaR. The use of VaR has limitations because it is based on historical correlations and volatilities in commodity prices, interest rates and foreign exchange rates, and assumes that future price movements will follow a statistical distribution. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR.

TCPL's estimation of VaR includes wholly owned subsidiaries and incorporates relevant risks associated with each market or business unit. The calculation does not include the regulated natural gas pipelines as the nature of the rate-regulated pipeline business reduces the impact of market risks. TCPL's Board of Directors has established a VaR limit, which is monitored on an ongoing basis as part of the Company's risk management policy. TCPL's consolidated VaR was $12 million at December 31, 2011 (2010 – $12 million).

MANAGEMENT'S DISCUSSION AND ANALYSIS 63

Counterparty Credit Risk

Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Company.

Counterparty credit risk is managed through established credit management techniques, including conducting financial and other assessments to establish and monitor a counterparty's creditworthiness, setting exposure limits, monitoring exposures against these limits, using contract netting arrangements and obtaining financial assurances where warranted. In general, financial assurances include guarantees, letters of credit and cash. The Company monitors and manages its concentration of counterparty credit risk on an ongoing basis. The Company believes these measures minimize its counterparty credit risk but there is no certainty that they will protect it against all material losses.

TCPL's maximum counterparty credit exposure with respect to financial instruments at the Balance Sheet date, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts receivable and other, and Available for sale assets in the Non-Derivative Financial Instruments Summary table located in the Fair Values section of this note. The majority of counterparty credit exposure is with counterparties that are investment grade or the exposure is supported by financial assurances provided by investment grade parties. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2011, there were no significant amounts past due or impaired, and there were no significant credit losses during the year.

At December 31, 2011, the Company had a credit risk concentration of $274 million (2010 – $317 million) due from a counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.

TCPL has significant credit and performance exposures to financial institutions as they provide committed credit lines and cash deposit facilities, critical liquidity in the foreign exchange derivative, interest rate derivative and energy wholesale markets, and letters of credit to mitigate TCPL's exposure to non-creditworthy counterparties.

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

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

Liquidity Risk

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

Management continuously forecasts cash flows for a period of 12 months to identify financing requirements. These requirements are then managed through a combination of committed and demand credit facilities and access to capital markets, as discussed in the Capital Management section of this note.

64 MANAGEMENT'S DISCUSSION AND ANALYSIS

respectively. The Company has also maintained continuous access to the Canadian commercial paper market on competitive terms and recently initiated a commercial paper program in the U.S.

Capital Management

The primary objective of capital management is to ensure TCPL has strong credit ratings to support its businesses and maximize shareholder value. In 2011, the overall objective and policy for managing capital remained unchanged from the prior year.

TCPL manages its capital structure in a manner consistent with the risk characteristics of the underlying assets. The Company's management considers its capital structure to consist of net debt, Non-Controlling Interests and Equity. Net debt comprises Notes Payable, Long-Term Debt and Junior Subordinated Notes less Cash and Cash Equivalents. Net debt only includes obligations that the Company controls and manages. Consequently, it does not include Cash and Cash Equivalents, Notes Payable and Long-Term Debt of TCPL's joint ventures.

The total capital managed by the Company was as follows:

December 31 (millions of dollars)	2011		2010

Notes payable	1,863		2,081
Due (from)/to TransCanada Corporation, net	(750	)	1,340
Long-term debt	18,567		17,922
Junior subordinated notes	1,009		985
Cash and cash equivalents	(630	)	(648	)

Net Debt	20,059		21,680

Equity attributable to non-controlling interests	1,076		768
Equity attributable to controlling interests	18,462		15,747

Total Equity	19,538		16,515

	39,597		38,195

Fair Values

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

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 65

Non-Derivative Financial Instruments Summary

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

	2011		2010

December 31 (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value

Financial Assets⁽¹⁾
Cash and cash equivalents	740	740	752	752
Accounts receivable and other⁽²⁾⁽³⁾	1,595	1,639	1,564	1,604
Due from TransCanada Corporation	750	750	1,363	1,363
Available for sale assets⁽²⁾	23	23	20	20

	3,108	3,152	3,699	3,739

Financial Liabilities⁽¹⁾⁽³⁾
Notes payable	1,880	1,880	2,092	2,092
Accounts payable and deferred amounts⁽⁴⁾	1,536	1,536	1,444	1,444
Due to TransCanada Corporation	–	–	2,703	2,703
Accrued interest	375	375	361	361
Long-term debt	18,567	23,757	17,922	21,523
Junior subordinated notes	1,009	1,027	985	992
Long-term debt of joint ventures	822	940	866	971

	24,189	29,515	26,373	30,086

⁽¹⁾: Consolidated Net Income in 2011 included losses of $13 million (2010 – losses of $8 million) for fair value adjustments related to interest rate swap agreements on US$350 million (2010 – US$250 million) of Long-Term Debt. There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.
⁽²⁾: At December 31, 2011, the Consolidated Balance Sheet included financial assets of $1,284 million (2010 – $1,280 million) in Accounts Receivable, $41 million (2010 – $40 million) in Other Current Assets and $293 million (2010 – $264 million) in Intangibles and Other Assets.
⁽³⁾: Recorded at amortized cost, except for $350 million (2010 – $250 million) of Long-Term Debt that is adjusted to fair value.
⁽⁴⁾: At December 31, 2011, the Consolidated Balance Sheet included financial liabilities of $1,494 million (2010 – $1,414 million) in Accounts Payable and $42 million (2010 – $30 million) in Deferred Amounts.

66 MANAGEMENT'S DISCUSSION AND ANALYSIS

The following tables detail the remaining contractual maturities for TCPL's non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2011:

Contractual Repayments of Financial Liabilities⁽¹⁾
		Payments Due by Period

(millions of dollars)	Total	2012	2013 and 2014	2015 and 2016	2017 and Thereafter

Notes payable	1,880	1,880	–	–	–
Long-term debt	18,567	935	1,874	2,311	13,447
Junior subordinated notes	1,009	–	–	–	1,009
Long-term debt of joint ventures	822	33	94	213	482

	22,278	2,848	1,968	2,524	14,938

⁽¹⁾: The anticipated timing of settlement of derivative contracts is presented in the Derivatives Financial Instrument Summary in this note.

Interest Payments on Financial Liabilities

		Payments Due by Period

(millions of dollars)	Total	2012	2013 and 2014	2015 and 2016	2017 and Thereafter

Long-term debt	16,541	1,180	2,227	1,989	11,145
Junior subordinated notes	355	65	129	129	32
Long-term debt of joint ventures	343	48	89	77	129

	17,239	1,293	2,445	2,195	11,306

MANAGEMENT'S DISCUSSION AND ANALYSIS 67

Derivative Financial Instruments Summary

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

			2011

December 31 (all amounts in millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest

Derivative Financial Instruments Held for Trading⁽¹⁾
Fair Values⁽²⁾
	Assets		$213		$176		$3		$22
	Liabilities		$(212	)	$(212	)	$(14	)	$(22	)
Notional Values
	Volumes⁽³⁾
		Purchases	23,500		103		–		–
		Sales	23,158		82		–		–
	Canadian dollars		–		–		–		684
	U.S. dollars		–		–		US 1,269		US 250
	Cross-currency		–		–		47/US 37		–
Net unrealized (losses)/gains in the year⁽⁴⁾			$(3	)	$(50	)	$(4	)	$1
Net realized gains/(losses) in the year⁽⁴⁾			$58		$(74	)	$10		$10
Maturity dates			2012-2018		2012-2016		2012		2012-2016
Derivative Financial Instruments in Hedging Relationships⁽⁵⁾⁽⁶⁾
Fair Values⁽²⁾
	Assets		$42		$3		$–		$13
	Liabilities		$(277	)	$(22	)	$(38	)	$(1	)
Notional Values
	Volumes⁽³⁾
		Purchases	17,188		8		–		–
		Sales	9,217		–		–		–
	U.S. dollars		–		–		US 91		US 600
	Cross-currency		–		–		136/US 100		–
Net realized losses in the year⁽⁴⁾			$(150	)	$(17	)	$–		$(16	)
Maturity dates			2012-2017		2012-2013		2012-2014		2012-2015

⁽¹⁾: All derivative financial instruments in the held for trading classification have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
⁽²⁾: Fair values equal carrying values.
⁽³⁾: Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.
⁽⁴⁾: Realized and unrealized gains and losses on held for trading derivative financial instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.
⁽⁵⁾: All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $13 million and a notional amount of US$350 million. In 2011, net realized gains on fair value hedges were $7 million and were included in Interest Expense. In 2011, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.
⁽⁶⁾: In 2011, Net Income included losses of $3 million for changes in the fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. In 2011, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur. No amounts have been excluded from the assessment of hedge effectiveness.

68 MANAGEMENT'S DISCUSSION AND ANALYSIS

The anticipated timing of settlement of the derivative contracts assumes constant commodity prices, interest rates and foreign exchange rates from December 31, 2011. Settlements will vary based on the actual value of these factors at the date of settlement. The anticipated timing of settlement of these contracts is as follows:

(millions of dollars)		Total		2012		2013 and 2014		2015 and 2016		2017 and Thereafter

Derivative financial instruments held for trading
	Assets	414		282		123		9		–
	Liabilities	(460	)	(292	)	(151	)	(17	)	–
Derivative financial instruments in hedging relationships
	Assets	217		121		91		5		–
	Liabilities	(408	)	(208	)	(135	)	(50	)	(15	)

		(237	)	(97	)	(72	)	(53	)	(15	)

MANAGEMENT'S DISCUSSION AND ANALYSIS 69

Derivative Financial Instruments Summary

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

			2010

December 31 (all amounts in millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest

Derivative Financial Instruments Held for Trading⁽¹⁾
Fair Values⁽²⁾
	Assets		$169		$144		$8		$20
	Liabilities		$(129	)	$(173	)	$(14	)	$(21	)
Notional Values
	Volumes⁽³⁾
		Purchases	15,610		158		–		–
		Sales	18,114		96		–		–
	Canadian dollars		–		–		–		736
	U.S. dollars		–		–		US 1,479		US 250
	Cross-currency		–		–		47/US 37		–
Net unrealized (losses)/gains in the year⁽⁴⁾			$(32	)	$27		$4		$43
Net realized gains/(losses) in the year⁽⁴⁾			$77		$(42	)	$36		$(74	)
Maturity dates			2011-2015		2011-2015		2011-2012		2011-2016
Derivative Financial Instruments in Hedging Relationships⁽⁵⁾⁽⁶⁾
Fair Values⁽²⁾
	Assets		$112		$5		$–		$8
	Liabilities		$(186	)	$(19	)	$(51	)	$(26	)
Notional Values
	Volumes⁽³⁾
		Purchases	16,071		17		–		–
		Sales	10,498		–		–		–
	U.S. dollars		–		–		US 120		US 1,125
	Cross-currency		–		–		136/US 100		–
Net realized losses in the year⁽⁴⁾			$(9	)	$(35	)	$–		$(33	)
Maturity dates			2011-2015		2011-2013		2011-2014		2011-2015

⁽¹⁾: All derivative financial instruments in the held-for-trading classification have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
⁽²⁾: Fair values equal carrying values.
⁽³⁾: Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.
⁽⁴⁾: Realized and unrealized gains and losses on held-for-trading derivative financial instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.
⁽⁵⁾: All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $8 million and a notional amount of US$250 million. In 2010, net realized gains on fair value hedges were $4 million and were included in Interest Expense. In 2010, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.
⁽⁶⁾: In 2010, Net Income included a gain of $1 million for changes in the fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. In 2010, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur. No amounts have been excluded from the assessment of hedge effectiveness.

70 MANAGEMENT'S DISCUSSION AND ANALYSIS

Balance Sheet Presentation of Derivative Financial Instruments

The fair value of the derivative financial instruments in the Company's Balance Sheet was as follows:

December 31 (millions of dollars)	2011		2010

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

Derivative Financial Instruments of Joint Ventures

Included in the Derivative Financial Instruments Summary tables are amounts related to power derivatives used by one of the Company's joint ventures to manage commodity price risk. The Company's proportionate share of the fair value of these power derivatives was $35 million at December 31, 2011 (2010 – $48 million). These contracts mature from 2012 to 2018. The Company's proportionate share of the notional sales volumes of power associated with this exposure was 2,979 GWh at December 31, 2011 (2010 – 3,772 GWh). The Company's proportionate share of the notional purchased volumes of power associated with this exposure was 1,595 GWh at December 31, 2011 (2010 – 2,322 GWh).

Derivatives in Cash Flow Hedging Relationships

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

	Cash Flow Hedges

	Power				Natural Gas				Foreign Exchange		Interest

Year ended December 31 (millions of Canadian dollars, pre-tax)	2011		2010		2011		2010		2011	2010	2011		2010

Change in fair value of derivative instruments recognized in OCI (effective portion)	(252	)	(79	)	(59	)	(26	)	5	10	(1	)	(137	)
Reclassification of gains and losses on derivative instruments from AOCI to Net Income (effective portion)	61		(7	)	100		(21	)	–	–	43		32

Credit Risk Related Contingent Features

Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at December 31, 2011, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $110 million (2010 – $92 million), for which the Company has provided collateral of $28 million (2010 – $4 million) in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on December 31, 2011, the Company would have been required to provide additional collateral of $82 million (2010 – $88 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative financial instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

MANAGEMENT'S DISCUSSION AND ANALYSIS 71

Fair Value Hierarchy

The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. In Level I, the fair value of assets and liabilities is determined by reference to quoted prices in active markets for identical assets and liabilities. In Level II, determination of the fair value of assets and liabilities includes valuations using inputs, other than quoted prices, for which all significant inputs are observable, directly or indirectly. This category includes fair value determined using valuation techniques, such as option pricing models and extrapolation using observable inputs. In Level III, determination of the fair value of assets and liabilities is based on inputs that are not readily observable and are significant to the overall fair value measurement. Long-dated commodity transactions in certain markets are included in this category. Long-dated commodity prices are derived with a third-party modelling tool that uses market fundamentals to derive long-term prices.

There were no transfers between Level I and Level II in 2011 or 2010. Financial assets and liabilities measured at fair value, including both current and non-current portions, are categorized as follows:

		Quoted Prices in Active Markets (Level I)				Significant Other Observable Inputs (Level II)				Significant Unobservable Inputs (Level III)				Total

December 31 (millions of dollars, pre-tax)		2011		2010		2011		2010		2011		2010		2011		2010

Natural Gas Inventory		–		–		29		49		–		–		29		49
Derivative Financial Instrument Assets:
	Interest rate contracts	–		–		35		28		–		–		35		28
	Foreign exchange contracts	11		10		131		179		–		–		142		189
	Power commodity contracts	–		–		244		269		2		5		246		274
	Gas commodity contracts	124		93		55		56		–		–		179		149
Derivative Financial Instrument Liabilities:
	Interest rate contracts	–		–		(23	)	(47	)	–		–		(23	)	(47	)
	Foreign exchange contracts	(13	)	(11	)	(89	)	(54	)	–		–		(102	)	(65	)
	Power commodity contracts	–		–		(465	)	(299	)	(15	)	(8	)	(480	)	(307	)
	Gas commodity contracts	(208	)	(178	)	(26	)	(15	)	–		–		(234	)	(193	)
Non-Derivative Financial Instruments:
	Available-for-sale assets	23		20		–		–		–		–		23		20

		(63	)	(66	)	(109	)	166		(13	)	(3	)	(185	)	97

72 MANAGEMENT'S DISCUSSION AND ANALYSIS

The following table presents the net change in the Level III fair value category:

(millions of dollars, pre-tax)	Derivatives⁽¹⁾

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

Balance at December 31, 2010	(3	)
New contracts⁽²⁾	1
Settlements	1
Transfers out of Level III⁽³⁾⁽⁴⁾	(1	)
Change in unrealized gains recorded in Net Income	1
Change in fair value of derivative instruments recorded in OCI	(12	)

Balance at December 31, 2011	(13	)

⁽¹⁾: The fair value of derivative assets and liabilities is presented on a net basis.
⁽²⁾: At December 31, 2011, the total amount of net gains included in Net Income attributable to derivatives that were entered into during the year and still held at the reporting date was nil (2010 – $1 million).
⁽³⁾: Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable.
⁽⁴⁾: As contracts near maturity, they are transferred out of Level III and into Level II.

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

OTHER RISKS

Development Projects and Acquisitions

TCPL continues to focus on growing its Natural Gas Pipelines, Oil Pipelines and Energy operations through greenfield development projects and acquisitions. TCPL capitalizes costs incurred on certain of its projects during the development period prior to construction when the project meets specific criteria and is expected to proceed through to completion. The related capital costs of a project that does not proceed through to completion are expensed at the time it is discontinued to the extent that these costs and underlying materials cannot be utilized on another project. There is a risk with respect to TCPL's acquisition of assets and operations that certain commercial opportunities and operational synergies may not materialize as expected and that the assets would subsequently be subject to an impairment write-down.

Asset Commissioning

Although each of TCPL's newly-constructed assets goes through rigorous acceptance testing prior to being placed in service, there is a risk that these assets will have lower than expected availability or performance, especially in their first year of operations.

Operational and Other Business Risks

There are a number of operating risks associated with TCPL's pipelines and energy businesses including: labour disputes; the breakdown or failure of equipment; acts of terror; and catastrophic events such as natural disasters. The occurrence

MANAGEMENT'S DISCUSSION AND ANALYSIS 73

or continuance of any of these events could impact earnings through the costs associated with remediation or a reduction in revenues.

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

Health, Safety and Environment Risk Management

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

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

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

The safety and integrity of the Company's existing and newly-developed infrastructure is also a top priority. All new assets are designed, constructed and commissioned with full consideration given to safety and integrity, and are brought in service only after all necessary requirements have been satisfied. The Company expects to spend approximately $322 million in 2012 for pipeline integrity on the pipelines it operates, an increase of approximately $78 million over 2011 primarily due to increased levels of in-line pipeline inspection on all systems. Under the approved regulatory models in Canada, non-capital pipeline integrity expenditures on NEB-regulated pipelines are treated on a flow-through basis and, as a result, these expenditures have no impact on TCPL's earnings. Under the Keystone contracts, pipeline integrity expenditures are recovered through the tolling mechanism and, as a result, these expenditures have no impact on TCPL's earnings. TCPL's pipeline safety record in 2011 continued to be better than industry benchmarks. TCPL experienced two pipeline breaks in 2011 on its operated pipelines. The first break occurred in a remote part of Northern Ontario on the Canadian Mainline pipeline system. The second break occurred in a remote part of Wyoming on the Bison pipeline system.

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

74 MANAGEMENT'S DISCUSSION AND ANALYSIS

Environment

TCPL's facilities are subject to stringent federal, state, provincial, and local environmental statutes and regulations governing environmental protection, including, but not limited to, air emissions, water quality, wastewater discharges and waste management. Such laws and regulations generally require facilities to obtain or comply with a wide variety of environmental registrations, licences, permits and other approvals and requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements and/or the issuance of orders respecting future operations. TCPL has ongoing inspection programs designed to keep all of its facilities in compliance with environmental requirements.

At December 31, 2011, TCPL recorded liabilities of approximately $69 million (2010 – $84 million) for remediation obligations and compliance costs associated with certain environmental regulations. The Company believes it has considered all necessary contingencies and established appropriate reserves for environmental liabilities; however, there is the risk that unforeseen matters may arise requiring the Company to set aside additional amounts.

The Company owns assets in four regions, Alberta, Québec, B.C., and the Northeastern U.S., where regulations exist to address industrial greenhouse gas (GHG) emissions. TCPL has procedures in place to comply with these regulations.

In Alberta, under the Specified Gas Emitters Regulation, industrial facilities emitting GHG emissions over an intensity threshold level are required to reduce the intensity of GHG emissions by 12 per cent below an average baseline. TCPL's Alberta-based facilities are subject to this regulation, as are the Sundance and Sheerness coal-fired power facilities with which TCPL has certain rights under the PPAs. TCPL has a program in place to manage the compliance costs incurred by these assets as a result of the regulation. Compliance costs on the Alberta System are recovered through tolls paid by customers. Some of the compliance costs from the Company's power generation facilities in Alberta are recovered through market pricing and contract flow-through provisions. TCPL has estimated and recorded GHG emissions related costs of $13 million for 2011 (2010 – $22 million), after contracted cost recovery.

In Québec, the natural gas distributor collects the hydrocarbon royalty on behalf of the provincial government through a green fund contribution charge on gas consumed. In 2011, the cost pertaining to the Bécancour facility arising from the hydrocarbon royalty was less than $1 million as a result of an agreement between TCPL and Hydro-Québec to temporarily suspend the facility's power generation.

The carbon tax in B.C., which came into effect in mid-2008, applies to carbon dioxide (CO₂) emissions from fossil fuel combustion. Compliance costs for fuel combustion at the Company's compressor and meter stations in B.C. are recovered through tolls paid by customers. Costs related to the carbon tax in 2011 were approximately $3 million (2010 – $4 million). The cost per tonne of CO₂ will be increased in July 2012 to $30 from $25.

States in the northeastern U.S. that are members of the Regional Greenhouse Gas Initiative (RGGI) implemented a CO₂ cap-and-trade program for electricity generators effective in January 2009. Under the RGGI, both the Ravenswood and OSP generation facilities were required to submit allowances following the end of the first compliance period on December 31, 2011. TCPL participated in the quarterly auctions of allowances for the Ravenswood and Ocean State Power generation facilities and incurred related costs of $4 million in 2011 (2010 – $5 million). These costs were generally recovered through the power market and the net impact on TCPL was not significant.

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

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

The Company's operations are subject to various environmental laws and regulations that establish compliance and remediation obligations. Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and penalties resulting from any failure to comply, and potential limitations on operations. Remediation obligations can result in significant costs associated with the investigation and remediation of

MANAGEMENT'S DISCUSSION AND ANALYSIS 75

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

•: uncertainties in estimating pollution control and clean up costs, including at sites where only preliminary site investigation or agreements have been completed;
•: the potential discovery of new contaminated sites or additional information at existing contaminated sites;
•: the uncertainty in quantifying the Company's liability under environmental laws that impose joint and several liability on all potentially responsible parties;
•: the evolving nature of environmental laws and regulations, including the interpretation and enforcement of them; and
•: the potential for litigation on existing or discontinued assets.

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

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

In addition to those climate change policies already in place, there are also federal, regional, state, and provincial initiatives currently in development. While recent political and economic events may significantly affect the scope and timing of new policies, TCPL anticipates that most of the Company's facilities in Canada and the U.S. are or will be subject to federal and/or regional climate change regulations to manage industrial GHG emissions.

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

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

Future Abandonment Costs

Depending on specific operating jurisdictions, the Company may have obligations to abandon its facilities in accordance with applicable laws and regulations.

76 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

The NEB's LMCI deals with pipeline abandonment, including related financial issues. The goal of this initiative is for all pipeline companies regulated under the National Energy Board Act (Canada) to begin collecting and setting aside funds to cover future abandonment costs by mid-2014. In its May 2009 decision, the NEB established several filing deadlines relating to the financial issues, including deadlines for preparing and filing an estimate of the abandonment costs to be used to begin collecting funds, developing a proposal for collecting these funds through tolls or some other satisfactory method and developing a proposed process to set aside the funds collected. TCPL filed its estimates of abandonment costs for its Canadian oil and natural gas pipelines in November 2011, as required by the NEB decision. These costs would be recovered from shippers through tolls in accordance with the NEB's determination that abandonment costs are a legitimate cost of providing service and are recoverable upon NEB approval from users of the system. The specific toll impacts have not yet been determined as they will be the subject of a subsequent NEB filing in late 2012. In addition, as the actual timing of retirements for the assets is indeterminable, the Company has not recorded amounts for ARO.

For the foreseeable future, the Company intends to operate and maintain these assets as long as supply and demand exists for hydroelectric power generation, natural gas and oil. The Company continues to evaluate its obligations related to future abandonment costs and to monitor developments that could impact the amounts it records.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As at December 31, 2011, an evaluation of the effectiveness of TCPL's disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the SEC was carried out under the supervision and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that, as at December 31, 2011, the design and operation of TCPL's disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by the Company in reports filed with, or submitted to, securities regulatory authorities is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and were effective to provide reasonable assurance that such information is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws.

Management's Annual Report on Internal Control over Financial Reporting

Internal control over financial reporting is a process designed by or under the supervision of senior management and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and preparation of consolidated financial statements for external purposes in accordance with CGAAP, including a reconciliation to U.S. generally accepted accounting principles (U.S. GAAP).

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting, no matter how well designed, has inherent limitations and can only provide reasonable assurance with respect to the preparation and fair presentation of published financial statements. Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in

MANAGEMENT'S DISCUSSION AND ANALYSIS 77

Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on this evaluation, management concluded that internal control over financial reporting was effective as at December 31, 2011, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

In 2011, there was no change in TCPL's internal control over financial reporting that materially affected or is reasonably likely to materially affect TCPL's internal control over financial reporting.

CEO and CFO Certifications

TCPL's President and Chief Executive Officer and Chief Financial Officer have filed with the SEC and the Canadian securities regulators certifications regarding the quality of TCPL's public disclosures relating to its fiscal 2011 reports filed with the SEC and the Canadian securities regulators.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

To prepare financial statements that conform with CGAAP, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses, since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. TCPL regularly assesses the assets and liabilities associated with these estimates and assumptions. A summary of TCPL's significant accounting policies can be found in Note 2 to the Consolidated Financial Statements. The Company believes the following accounting policies and estimates require it to make assumptions about highly uncertain matters and changes in these estimates could have a material impact on the Company's financial information.

Rate-Regulated Accounting

The Company accounts for the impacts of rate regulation in accordance with CGAAP. The following three criteria must be met to use these accounting principles:

•: the rates for regulated services or activities must be established by or subject to approval by a regulator;
•: the regulated rates must be designed to recover the cost of providing the services or products; and
•: it must be reasonable to assume that rates set at levels to recover the cost can be charged to and collected from customers in view of the demand for services or products and the level of direct and indirect competition.

The Company's management believes all three of these criteria have been met with respect to each of the regulated natural gas pipelines accounted for using rate-regulated accounting (RRA) principles. The most significant impact from the use of these accounting principles is that the timing of recognition of certain Natural Gas Pipelines expenses and revenues in the regulated businesses may differ from that otherwise expected under CGAAP in order to appropriately reflect the economic impact of the regulators' decisions regarding the Company's revenues and tolls. At December 31, 2011, the Company reported regulatory assets of $0.2 billion and $1.4 billion in Other Current Assets and Regulatory Assets, respectively (2010 – $0.3 billion and $1.5 billion, respectively), and regulatory liabilities of $0.1 billion and $0.3 billion in Accounts Payable and Regulatory Liabilities, respectively (2010 – $0.1 billion and $0.3 billion, respectively).

Financial Instruments and Hedges

Financial Instruments

The Company initially records all financial instruments on the Balance Sheet at fair value. Subsequent measurement of the financial instruments is based on their classification as held for trading, available for sale, held-to-maturity investments, loans and receivables, and other financial liabilities.

78 MANAGEMENT'S DISCUSSION AND ANALYSIS

Held for trading derivative financial assets and liabilities consist of swaps, options, forwards and futures with changes in the fair value recorded in Net Income. The available for sale classification includes non-derivative financial assets that are designated as available for sale or are not included in the other three classifications with changes in the fair value recorded in Other Comprehensive (Loss)/Income (OCI). Trade receivables, loans and other receivables with fixed or determinable payments that are not quoted in an active market are classified as loans and receivables and are measured at amortized cost using the effective interest method, net of any impairment. The Company does not have any held-to-maturity investments. Other financial liabilities consist of liabilities not classified as held for trading and are recognized at amortized cost using the effective interest method.

Hedges

In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item. Changes in fair value of the hedged and hedging items are recognized in Net Income.

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in Net Income in the same financial category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in Accumulated Other Comprehensive (Loss)/Income (AOCI) are reclassified to Net Income during the periods when the variability in cash flows of the hedged item affects Net Income. Gains and losses on derivatives are reclassified immediately to Net Income from AOCI when the hedged item is sold or terminated early, or when it is probable the anticipated transaction will not occur.

The Company also enters into cash flow hedges and fair value hedges for activities subject to rate regulation in Canada. The gains and losses arising from changes in the fair value of these hedges can be recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as Regulatory Assets or Regulatory Liabilities on behalf of the ratepayers. When the hedges are settled, the realized gains and losses are refunded to or collected from the ratepayers in subsequent years.

In hedging the foreign currency exposure of a net investment in a self-sustaining foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in Net Income. The amounts recognized previously in AOCI are reclassified to Net Income in the event the Company reduces its investment in a foreign operation.

The fair value of financial instruments and hedges, where fair value does not approximate carrying value, is primarily derived from market values adjusted for credit risk, which can fluctuate widely from period to period. Since the changes in fair value are recorded through earnings in certain circumstances, fluctuations can result in variability in Net Income.

Depreciation and Amortization Expense

TCPL's Plant, Property and Equipment are depreciated on a straight-line basis over their estimated useful lives once they are ready for their intended use. The estimation of useful lives requires management's judgement regarding the period of time the assets will be in use based on third-party engineering studies, experience and industry practice. The initial payment for the Company's PPAs is deferred and amortized on a straight-line basis over the terms of the contracts, which expire in 2017 and 2020.

Natural gas pipeline and compression equipment is depreciated at annual rates ranging from one per cent to six per cent. Oil pipeline and pumping equipment is depreciated at annual rates ranging from approximately two per cent to 2.5 per cent. Metering and other plant equipment are depreciated at various rates. Major power generation and natural gas storage plant, equipment and structures in the Energy business are depreciated by major component on a

MANAGEMENT'S DISCUSSION AND ANALYSIS 79

straight-line basis over estimated service lives at average annual rates ranging from two per cent to 20 per cent. Nuclear power generation assets under capital lease are recorded initially at the present value of minimum lease payments at the inception of the lease and amortized on a straight-line basis over the shorter of their useful life and the remaining lease term. Other Energy equipment is depreciated at various rates. Corporate Plant, Property and Equipment are depreciated on a straight-line basis over estimated useful lives at average annual rates ranging from three per cent to 20 per cent.

Depreciation and Amortization Expense in 2011 was $1,528 million (2010 – $1,354 million; 2009 – $1,377 million) and was recorded in Natural Gas Pipelines, Oil Pipelines, Energy and Corporate. In Natural Gas Pipelines, depreciation rates are approved by regulators when applicable and depreciation expense is recoverable based on the cost of providing the services or products. If regulators permit recovery of depreciation through rates charged to customers, a change in the estimate of the useful lives of plant, property and equipment in the Natural Gas Pipelines segment will have no material impact on TCPL's Net Income but will directly affect Funds Generated from Operations. PPA amortization expense of $58 million was included in Energy's Depreciation and Amortization expense for 2009 through 2011.

Impairment of Long-Lived Assets and Goodwill

The Company reviews long-lived assets such as plant, property and equipment, as well as intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

At December 31, 2011, the Company reported Goodwill of $3.7 billion (2010 – $3.6 billion). Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. An initial test is done by comparing the fair value of the operations, which includes goodwill, to the book value of each reporting unit. If the fair value is less than book value, an impairment is indicated and a second test is performed to measure the amount of the impairment. In the second test, the implied fair value of the goodwill is calculated by deducting the fair value of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of the goodwill, an impairment charge is recorded.

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

•: discount rates;
•: commodity and capacity prices;
•: market supply and demand assumptions;
•: growth opportunities;
•: output levels;
•: competition from other companies; and
•: regulatory changes.

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

80 MANAGEMENT'S DISCUSSION AND ANALYSIS

ACCOUNTING CHANGES

CHANGES IN ACCOUNTING POLICIES FOR 2011

Business Combinations

Effective January 1, 2011, the Company adopted CICA Handbook Section 1582 "Business Combinations", which is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, expensing of acquisition costs, and increased disclosure. Adoption of this standard had no effect on the financial statements as at and for the year ended December 31, 2011.

Consolidated Financial Statements and Non-Controlling Interests

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

FUTURE ACCOUNTING CHANGES

U.S. GAAP

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

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

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

Fair Value Measurement

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 81

Intangibles – Goodwill and Other

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

Balance Sheet Offsetting/Netting

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

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA⁽¹⁾

		2011

(unaudited) (millions of dollars except per share amounts)		Fourth	Third	Second	First

Revenues		2,360	2,393	2,143	2,243
Net Income Attributable to Common Shares		371	377	348	408
Share Statistics
	Net income per share – basic and diluted	$0.54	$0.56	$0.51	$0.60

		2010

(unaudited) (millions of dollars except per share amounts)		Fourth	Third	Second	First

Revenues		2,057	2,129	1,923	1,955
Net Income Attributable to Common Shares		271	381	287	295
Share Statistics
	Net income per share – basic and diluted	$0.40	$0.57	$0.43	$0.46

⁽¹⁾: The selected quarterly consolidated financial data has been prepared in accordance with GAAP.

Factors Affecting Quarterly Financial Information

In Natural Gas Pipelines, which consists primarily of the Company's investments in regulated pipelines and regulated natural gas storage facilities, annual revenues and net income fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable with fluctuations resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput volumes on U.S. pipelines, acquisitions and divestitures, and developments outside of the normal course of operations.

In Oil Pipelines, which consists of the Company's investment in a regulated crude oil pipeline, annual revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable with fluctuations resulting from changes in the amount of spot volumes transported and the associated rate charged. Spot volumes transported are

82 MANAGEMENT'S DISCUSSION AND ANALYSIS

affected by customer demand, market pricing, planned and unplanned outages of refineries, terminals and pipeline facilities, and developments outside of the normal course of operations.

In Energy, which consists primarily of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities, quarter-over-quarter revenues and net income are affected by seasonal weather conditions, customer demand, market prices, capacity prices and payments, planned and unplanned plant outages, acquisitions and divestitures, certain fair value adjustments and developments outside of the normal course of operations.

Significant developments that affected EBIT and Net Income in 2011 and 2010 were as follows:

•: Fourth Quarter 2011 EBIT excluded net unrealized after-tax gains of $9 million ($9 million pre-tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.
•: Third Quarter 2011 Energy's EBIT included the positive impact of higher prices for Western Power. EBIT included net unrealized losses of $47 million pre-tax ($33 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.
•: Second Quarter 2011 Natural Gas Pipelines' EBIT included incremental earnings from Guadalajara, which was placed in service in June 2011. Energy's EBIT included incremental earnings from Coolidge, which was placed in service in May 2011. EBIT included net unrealized losses of $5 million pre-tax ($4 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.
•: First Quarter 2011 Natural Gas Pipelines' EBIT included incremental earnings from Bison, which was placed in service in January 2011. Oil Pipelines began recording EBIT for the Wood River/Patoka and Cushing Extension sections of Keystone in February 2011. EBIT included net unrealized losses of $17 million pre-tax ($10 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.
•: Fourth Quarter 2010 Natural Gas Pipelines' EBIT decreased as a result of recording a $146 million pre-tax ($127 million after-tax) valuation provision for advances to the APG for the MGP. Energy's EBIT included contributions from the second phase of Kibby Wind, which was placed in service in October 2010, and net unrealized gains of $22 million pre-tax ($12 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.
•: Third Quarter 2010 Natural Gas Pipelines' EBIT increased as a result of recording nine months of incremental earnings related to the Alberta System 2010 - 2012 Revenue Requirement Settlement, which resulted in a $33 million increase to Net Income. Energy's EBIT included contributions from Halton Hills, which was placed in service in September 2010, and net unrealized gains of $4 million pre-tax ($3 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.
•: Second Quarter 2010 Energy's EBIT included net unrealized gains of $15 million pre-tax ($10 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities. Net Income reflected a decrease of $58 million after tax due to losses in 2010 compared to gains in 2009 for interest rate and foreign exchange rate derivatives that did not qualify as hedges for accounting purposes and the translation of U.S. dollar-denominated working capital balances.
•: First Quarter 2010 Energy's EBIT included net unrealized losses of $49 million pre-tax ($32 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

MANAGEMENT'S DISCUSSION AND ANALYSIS 83

FOURTH QUARTER 2011 HIGHLIGHTS

Reconciliation of Non-GAAP Measures

		Natural Gas Pipelines				Oil Pipelines			Energy				Corporate				Total

Three months ended December 31 (unaudited) (millions of dollars)		2011		2010		2011		2010	2011		2010		2011		2010		2011		2010

Comparable EBITDA		739		737		179		–	295		301		(29	)	(33	)	1,184		1,005
Depreciation and amortization		(251	)	(241	)	(35	)	–	(100	)	(103	)	(4	)	–		(390	)	(344	)

Comparable EBIT		488		496		144		–	195		198		(33	)	(33	)	794		661

Other Income Statement Items
Comparable interest expense																	(276	)	(189	)
Interest expense of joint ventures																	(15	)	(15	)
Comparable interest income and other																	8		61
Comparable income taxes																	(116	)	(99	)
Net income attributable to non-controlling interests																	(28	)	(28	)
Preferred share dividends																	(5	)	(5	)

Comparable Earnings																	362		386
Specific items (net of tax):
	Valuation provision for MGP																–		(127	)
	Risk management activities⁽¹⁾																9		12

Net Income Attributable to Common Shares																	371		271

Three months ended December 31 (unaudited) (millions of dollars)		2011		2010

Comparable Interest Income and Other		8		61
Specific item:
	Risk management activities⁽¹⁾	35		–

Interest Income and Other		43		61

Comparable Income Taxes		(116	)	(99	)
Specific items:
	Valuation provision for MGP	–		19
	Risk management activities⁽¹⁾	–		(10	)

Income Taxes Expense		(116	)	(90	)

⁽¹⁾: Three months ended December 31

(unaudited) (millions of dollars)	2011		2010

Risk Management Activities Gains/(Losses):
U.S. Power derivatives	(33	)	24
Natural Gas Storage proprietary inventory and derivatives	7		(2	)
Foreign exchange derivatives	35		–
Income taxes attributable to risk management activities	–		(10	)

Risk Management Activities	9		12

Comparable Earnings in fourth quarter 2011 were $362 million compared to $386 million for the same period in 2010. Comparable Earnings in fourth quarter 2011 excluded net unrealized after-tax gains of $9 million ($9 million pre-tax) (2010 – $12 million after-tax gains; $22 million pre-tax) resulting from changes in the fair value of certain risk

84 MANAGEMENT'S DISCUSSION AND ANALYSIS

management activities. Comparable Earnings in fourth quarter 2010 also excluded the $127 million after tax ($146 million pre-tax) valuation provision on advances to the APG for the MGP.

Comparable Earnings decreased $24 million in fourth quarter 2011 compared to the same period in 2010 and included the following:

•: decreased Comparable EBIT from Natural Gas Pipelines reflecting lower incentive earnings from the Canadian Mainline and the Alberta System and lower revenues from certain U.S. Pipelines partially offset by incremental earnings from Bison and Guadalajara which were placed in service in January and June 2011, respectively;
•: Oil Pipelines Comparable EBIT as the Company commenced recording earnings from Keystone in February 2011;
•: decreased Comparable EBIT from Energy reflecting lower Bruce A and B volumes and higher operating costs as well as lower realized prices at Bruce B, lower contributions from U.S. Power and lower Natural Gas Storage revenues partially offset by higher realized prices in Western Power and incremental earnings from the start-up of Coolidge in May 2011;
•: increased Comparable Interest Expense primarily due to decreased capitalized interest upon placing Keystone and other new assets in service in 2011;
•: decreased Comparable Interest Income and Other, reflecting higher realized losses in 2011 on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income compared to gains in 2010; and
•: increased Comparable Income Taxes due to higher positive income tax adjustments which reduced income taxes in fourth quarter 2010.

TCPL's Net Income Attributable to Common Shares was $371 million in fourth quarter 2011 compared to $271 million in fourth quarter 2010.

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

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

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

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

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

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

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

Comparable EBITDA from the remainder of the U.S. Natural Gas Pipelines was US$145 million in fourth quarter 2011 compared to US$128 million for the same period in 2010. The increases were primarily due to incremental earnings

MANAGEMENT'S DISCUSSION AND ANALYSIS 85

from the Guadalajara pipeline, which was placed in service in June 2011. In addition, lower general, administrative and support costs increased EBITDA in fourth quarter 2011, offset by lower earnings from Great Lakes and Portland.

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

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

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

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

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

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

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

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

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

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

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

Comparable Interest Expense in fourth quarter 2011 increased $87 million to $276 million from $189 million in fourth quarter 2010. The increase primarily reflected lower capitalized interest upon placing Keystone and other new assets in service in 2011.

Comparable Interest Income and Other in fourth quarter 2011 decreased $53 million to $8 million from income of $61 million in fourth quarter 2010. The decrease in fourth quarter reflected realized losses in 2011 compared to gains

86 MANAGEMENT'S DISCUSSION AND ANALYSIS

in 2010 on derivatives used to manage the Company's net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Comparable Income Taxes were $116 million in fourth quarter 2011 compared to $99 million for the same period in 2010. The increase was primarily due to higher positive income tax adjustments that reduced income taxes in fourth quarter 2010 compared to 2011.

SHARE INFORMATION

At February 8, 2012, TCPL had 739 million common shares, four million Series U preferred shares and four million Series Y preferred shares issued and outstanding.

OTHER INFORMATION

Additional information relating to TCPL, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada PipeLines Limited.

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 87

GLOSSARY OF TERMS

AFUDC		Allowance for funds used during construction
Alaska Pipeline Project		A proposed natural gas pipeline extending from Prudhoe Bay, Alaska to either Alberta or Valdez, Alaska
Alberta System		A natural gas transmission system in Alberta and B.C.
AOCI		Accumulated Other Comprehensive (Loss)/Income
ANR		A natural gas transmission system extending from producing fields located primarily in Texas, Oklahoma, the Gulf of Mexico and U.S. midcontinent region to markets located primarily in Wisconsin, Michigan, Illinois, Indiana and Ohio, and regulated underground natural gas storage facilities in Michigan
APG		Aboriginal Pipeline Group
ARO		Asset retirement obligation
ATWACC		After-tax weighted average cost of capital
AUC		Alberta Utilities Commission
B.C.		British Columbia
bbl/d		Barrel(s) per day
Bcf		Billion cubic feet
Bcf/d		Billion cubic feet per day
Bear Creek		A natural gas-fired cogeneration plant near Grande Prairie, Alberta
Bécancour		A natural gas-fired cogeneration plant near Trois-Rivières, Québec
Bison		A natural gas pipeline extending from the Powder River Basin in Wyoming to Northern Border in North Dakota
Bison LLC		Bison Pipeline LLC
BPC		BPC Generation Infrastructure Trust
BPRIA		Bruce Power Refurbishment Implementation Agreement
Bruce A		A partnership interest in a nuclear power generation facility consisting of Units 1 to 4 of Bruce Power
Bruce B		A partnership interest in a nuclear power generation facility consisting of Units 5 to 8 of Bruce Power
Bruce Power		A nuclear power generation facility located northwest of Toronto, Ontario (Bruce A and Bruce B, collectively)
Canadian Mainline		A natural gas transmission system extending from the Alberta/Saskatchewan border east into Québec
Cancarb		A waste-heat fuelled power plant and the Cancarb thermal carbon black facility in Medicine Hat, Alberta
CAPP		Canadian Association of Petroleum Producers
Carseland		A natural gas-fired cogeneration plant near Carseland, Alberta
Cartier Wind		Five wind farms in Gaspé, Québec, four plus the first phase of the fifth which are operational and phase two of the fifth under construction
CFE		Comisión Federal de Electricidad
CGAAP		Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants Handbook
CICA		Canadian Institute of Chartered Accountants
CO₂		Carbon dioxide
Coolidge		A simple-cycle, natural gas-fired peaking power generation station in Coolidge, Arizona
COSO		Committee of Sponsoring Organizations of the Treadway Commission
CrossAlta		An underground natural gas storage facility near Crossfield, Alberta
CSP		Contingent Support Payments
Cushing Extension		A crude oil pipeline extending from Steele City, Nebraska to Cushing, Oklahoma
DB Plans		Defined benefit pension plans
DC Plans		Defined contribution pension plans
DOS		U.S. Department of State
DRP		Dividend Reinvestment and Share Purchase Plan
EBIT		Earnings before interest and taxes
EBITDA		Earnings before interest, taxes, depreciation and amortization
Edson		An underground natural gas storage facility near Edson, Alberta
EPA		Environmental Protection Agency (U.S.)
ExxonMobil		Exxon Mobil Corporation
FASB		Financial Accounting Standards Board
FCM		Forward Capacity Market
FEIS		Final Environmental Impact Statement
FERC		Federal Energy Regulatory Commission (U.S.)

88 MANAGEMENT'S DISCUSSION AND ANALYSIS

Foothills		A natural gas transmission system extending from central Alberta to the B.C./U.S. border and to the Saskatchewan/U.S. border
Fracking		Multi-stage hydraulic fracturing
Gas Pacifico		A natural gas transmission system extending from Loma de la Lata, Argentina to Concepción, Chile
GHG		Greenhouse gas
Grandview		A natural gas-fired cogeneration plant in Saint John, New Brunswick
Great Lakes		A natural gas transmission system that connects to the Canadian Mainline and serves markets in Eastern Canada and the northeastern and midwestern U.S.
GTN		A natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border, traversing Idaho, Washington and Oregon
GTN LLC		Gas Transmission Northwest LLC
Guadalajara		A natural gas pipeline in Mexico extending from Manzanillo, Colima to Guadalajara, Jalisco
GWh		Gigawatt hours
Halton Hills		A natural gas-fired, combined-cycle power plant in Halton Hills, Ontario
HOEP		Hourly Ontario energy price
HSE		Health, safety and environment
IASB		International Accounting Standards Board
IESO		Independent Electricity System Operator
IFRS		International Financial Reporting Standards
INNERGY		An industrial natural gas marketing company based in Concepción, Chile
Iroquois		A natural gas transmission system that connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to the northeastern U.S.
ISO		International Organization for Standardization
Keystone		The crude oil pipeline system which extends from Hardisty, Alberta to the U.S. markets and includes the Wood River/Patoka, the Cushing Extension and Keystone XL
Keystone XL		A proposed extension and expansion of the Keystone oil pipeline to the U.S. Gulf Coast, which includes the construction of a new crude oil pipeline from Cushing, Oklahoma to the U.S. Gulf Coast, the expansion of existing facilities at Hardisty, Alberta and the construction of a new crude oil pipeline from Hardisty, Alberta to Steele City, Nebraska
Kibby Wind		A wind farm located in Kibby and Skinner townships in northwestern Franklin County, Maine
km		Kilometre(s)
LMCI		Land Matters Consultation Initiative
LNG		Liquefied natural gas
MacKay River		A natural gas-fired cogeneration plant near Fort McMurray, Alberta
MD&A		Management's Discussion and Analysis
Mackenzie Gas Project (MGP)		A proposed natural gas pipeline extending from a point near Inuvik, Northwest Territories to the northern border of Alberta
MMcf/d		Million cubic feet per day
MOP		Maximum operating pressure
MW		Megawatt(s)
MWh		Megawatt hours
NCC		North Central Corridor
NEB		National Energy Board
NEXT		Natural Gas Liquids Extraction Model
NGTL		NOVA Gas Transmission Ltd.
NID		National Interest Determination
North Baja		A natural gas transmission system extending from Arizona to the Baja California, Mexico/California border
Northern Border		A natural gas transmission system extending from a point near Monchy, Saskatchewan to the U.S. Midwest
NYISO		New York Independent System Operator
OCI		Other Comprehensive (Loss)/Income
OM&A		Operating, maintenance and administration
OMERS		Ontario Municipal Employees Retirement System
OPA		Ontario Power Authority
Ocean State Power		A natural gas-fired, combined-cycle plant in Burrillville, Rhode Island
PHMSA		Pipeline and Hazardous Materials Safety Administration

MANAGEMENT'S DISCUSSION AND ANALYSIS 89

PJM Interconnection (PJM)		A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia
Portland		A natural gas transmission system extending from a point near East Hereford, Québec to the northeastern U.S.
Portlands Energy		A natural gas-fired, combined-cycle power plant in Toronto, Ontario
PPA		Power purchase arrangement
PWU		Power Workers' Union Trust
Ravenswood		A natural gas and oil-fired generating facility consisting of multiple units employing steam turbine, combined-cycle and combustion turbine technology located in Queens, New York
Redwater		A natural gas-fired cogeneration plant near Redwater, Alberta
Restructuring Proposal		Canadian Mainline 2012 Tolls Application and Restructuring Proposal
RGGI		Regional Greenhouse Gas Initiative
ROE		Rate of return on common equity
RRA		Rate-regulated accounting
SEC		Securities and Exchange Commission (U.S.)
SEP		Society of Energy Professionals Trust
Sheerness		A coal-fired power generating facility near Hanna, Alberta
Sundance A		A coal-fired power generating facility near Wabamun, Alberta
Sundance B		A coal-fired power generating facility near Wabamun, Alberta
Tamazunchale		A natural gas pipeline in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi
TC Hydro		Hydroelectric generation assets in New Hampshire, Vermont and Massachusetts
TC Keystone		TransCanada Keystone Pipeline, LP
Tcf		Trillion cubic feet
TCPL		TransCanada PipeLines Limited or the Company
TCPL USA		TransCanada PipeLine USA Ltd.
TQM		A natural gas transmission system that connects with the Canadian Mainline near the Québec/Ontario border and transports natural gas to markets in Québec, and connects with Portland
TransAlta		TransAlta Corporation
TransCanada		TransCanada Corporation
TransGas		A natural gas transmission system extending from Mariquita to Cali in Colombia
Tuscarora		A natural gas transmission system extending from Malin, Oregon to Wadsworth, Nevada
U.S.		United States
U.S. GAAP		U.S. generally accepted accounting principles
VaR		Value-at-Risk
Ventures LP		A natural gas transmission system in Alberta supplying natural gas to the oil sands region of northern Alberta and to a petrochemical complex at Joffre, Alberta
WCI		Western Climate Initiative
WCSB		Western Canada Sedimentary Basin
Wood River/Patoka		A crude oil pipeline extending from Hardisty, Alberta to U.S. markets at Wood River and Patoka in Illinois
Zephyr		A proposed power transmission line project originating in Wyoming and terminating in Nevada

90 MANAGEMENT'S DISCUSSION AND ANALYSIS

Report of
Management

The consolidated financial statements and Management's Discussion and Analysis (MD&A) included in this Annual Report are the responsibility of the management of TransCanada PipeLines Limited (TCPL or the Company) and have been approved by the Board of Directors of the Company. The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook (CGAAP) and include amounts that are based on estimates and judgements. The MD&A is based on the Company's financial results. It compares the Company's financial and operating performance in 2011 to that in 2010, and highlights significant changes between 2010 and 2009. The MD&A should be read in conjunction with the consolidated financial statements and accompanying notes. Financial information contained elsewhere in this Annual Report is consistent with the consolidated financial statements.

Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Management has designed and maintains a system of internal control over financial reporting, including a program of internal audits to carry out its responsibility. Management believes these controls provide reasonable assurance that financial records are reliable and form a proper basis for the preparation of financial statements. The internal control over financial reporting include management's communication to employees of policies that govern ethical business conduct.

Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal controls over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management concluded, based on its evaluation, that internal control over financial reporting are effective as of December 31, 2011, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

The Board of Directors is responsible for reviewing and approving the financial statements and MD&A and ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Board of Directors carries out these responsibilities primarily through the Audit Committee, which consists of independent, non-management directors. The Audit Committee meets with management at least five times a year and meets independently with internal and external auditors and as a group to review any significant accounting, internal control and auditing matters in accordance with the terms of the Charter of the Audit Committee, which is set out in the Annual Information Form. The Audit Committee's responsibilities include overseeing management's performance in carrying out its financial reporting responsibilities and reviewing the Annual Report, including the consolidated financial statements and MD&A, before these documents are submitted to the Board of Directors for approval. The internal and independent external auditors have access to the Audit Committee without the requirement to obtain prior management approval.

The Audit Committee approves the terms of engagement of the independent external auditors and reviews the annual audit plan, the Auditors' Report and the results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholders.

The shareholders have appointed KPMG LLP as independent external auditors to express an opinion as to whether the consolidated financial statements present fairly, in all material respects, the Company's consolidated financial position, results of operations and cash flows in accordance with CGAAP. The report of KPMG LLP outlines the scope of its examination and its opinion on the consolidated financial statements.


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

TRANSCANADA PIPELINES LIMITED 91

Independent
Auditors'
Report

To the Shareholders of TransCanada PipeLines Limited

We have audited the accompanying consolidated financial statements of TransCanada PipeLines Limited, which comprise the consolidated balance sheets as at December 31, 2011 and 2010, the consolidated statements of income, comprehensive income, accumulated other comprehensive income, equity and cash flows for each of the years in the three-year period ended December 31, 2011, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of TransCanada PipeLines Limited as at December 31, 2011 and 2010 and its consolidated results of operations and its consolidated cash flows for each of the years in the three-year period ended December 31, 2011 in accordance with Canadian generally accepted accounting principles.


		Chartered Accountants Calgary, Canada
		February 13, 2012

92 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED INCOME

Year ended December 31 (millions of dollars)	2011		2010		2009

Revenues	9,139		8,064		8,181
Operating and Other Expenses
Plant operating costs and other	3,449		3,114		3,213
Commodity purchases resold	941		1,017		831
Depreciation and amortization	1,528		1,354		1,377
Valuation provision for MGP (Note 9)	–		146		–

	5,918		5,631		5,421

Financial Charges/(Income)
Interest expense (Note 13)	1,044		754		986
Interest expense of joint ventures (Note 14)	55		59		64
Interest income and other	(55	)	(94	)	(119	)

	1,044		719		931

Income before Income Taxes	2,177		1,714		1,829

Income Tax Expense/(Recovery) (Note 12)
Current	193		(142	)	32
Future	351		507		344

	544		365		376

Net Income	1,633		1,349		1,453
Net Income Attributable to Non-Controlling Interests (Note 16)	107		93		74

Net Income Attributable to Controlling Interests	1,526		1,256		1,379
Preferred Share Dividends (Note 18)	22		22		22

Net Income Attributable to Common Shares	1,504		1,234		1,357

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

CONSOLIDATED FINANCIAL STATEMENTS 93

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED COMPREHENSIVE INCOME

Year ended December 31 (millions of dollars)	2011		2010		2009

Net Income	1,633		1,349		1,453

Other Comprehensive Income/(Loss), Net of Income Taxes
Change in foreign currency translation gains and losses on investments in foreign operations⁽¹⁾	113		(180	)	(471	)
Change in fair value of derivative instruments to hedge the net investments in foreign operations⁽²⁾	(73	)	89		258
Change in fair value of derivative instruments designated as cash flow hedges⁽³⁾	(203	)	(141	)	75
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges⁽⁴⁾	127		(7	)	(15	)

Other Comprehensive Loss	(36	)	(239	)	(153	)

Comprehensive Income	1,597		1,110		1,300
Comprehensive Income Attributable to Non-Controlling Interests	118		99		81

Comprehensive Income Attributable to Controlling Interests	1,479		1,011		1,219
Preferred Share Dividends	22		22		22

Comprehensive Income Attributable to Common Shares	1,457		989		1,197

⁽¹⁾: Net of income tax recovery of $29 million in 2011 (2010 – $65 million expense; 2009 – $92 million expense).
⁽²⁾: Net of income tax recovery of $28 million in 2011 (2010 – $37 million expense; 2009 – $124 million expense).
⁽³⁾: Net of income tax recovery of $104 million in 2011 (2010 – $95 million recovery; 2009 – $7 million expense).
⁽⁴⁾: Net of income tax expense of $77 million in 2011 (2010 – $21 million expense; 2009 – $9 million expense).

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

94 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED CASH FLOWS

Year ended December 31 (millions of dollars)	2011		2010		2009

Cash Generated from Operations
Net income	1,633		1,349		1,453
Depreciation and amortization	1,528		1,354		1,377
Future income taxes (Note 12)	351		507		344
Employee future benefits funding in excess of expense (Note 20)	(3	)	(69	)	(111	)
Valuation provision for MGP (Note 9)	–		146		–
Other	63		(8	)	(19	)

	3,572		3,279		3,044
Decrease/(increase) in operating working capital (Note 22)	282		(256	)	(88	)

Net cash provided by operations	3,854		3,023		2,956

Investing Activities
Capital expenditures (Note 4)	(3,274	)	(5,036	)	(5,417	)
Deferred amounts and other	(14	)	(384	)	(571	)
Acquisitions, net of cash acquired (Note 23)	–		–		(902	)

Net cash used in investing activities	(3,288	)	(5,420	)	(6,890	)

Financing Activities
Dividends on common and preferred shares (Notes 17 and 18)	(1,185	)	(1,109	)	(998	)
Distributions paid to non-controlling interests	(109	)	(90	)	(78	)
Advances (to)/from parent (Note 26)	(2,090	)	116		932
Notes payable (repaid)/issued, net	(218	)	474		(244	)
Long-term debt issued, net of issue costs	1,622		2,371		3,267
Repayment of long-term debt	(1,272	)	(494	)	(1,005	)
Long-term debt of joint ventures issued	48		177		226
Repayment of long-term debt of joint ventures	(102	)	(254	)	(246	)
Common shares issued, net of issue costs	2,401		987		1,676
Partnership units of subsidiary issued, net of issue costs (Note 23)	321		–		193

Net cash (used in)/provided by financing activities	(584	)	2,178		3,723

Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	6		(8	)	(110	)

Decrease in Cash and Cash Equivalents	(12	)	(227	)	(321	)
Cash and Cash Equivalents
Beginning of year	752		979		1,300

Cash and Cash Equivalents
End of year	740		752		979

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

CONSOLIDATED FINANCIAL STATEMENTS 95

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED BALANCE SHEET

December 31 (millions of dollars)	2011	2010

ASSETS
Current Assets
Cash and cash equivalents	740	752
Accounts receivable	1,284	1,280
Due from TransCanada Corporation (Note 26)	750	1,363
Inventories	416	425
Other	1,184	857

	4,374	4,677
Plant, Property and Equipment (Note 5)	38,262	36,244
Goodwill (Note 6)	3,650	3,570
Regulatory Assets (Note 7)	1,405	1,512
Intangibles and Other Assets (Note 9)	2,032	2,123

	49,723	48,126

LIABILITIES
Current Liabilities
Notes payable (Note 10)	1,880	2,092
Accounts payable	2,636	2,276
Accrued interest	375	361
Current portion of long-term debt (Note 13)	935	894
Current portion of long-term debt of joint ventures (Note 14)	33	65

	5,859	5,688
Due to TransCanada Corporation (Note 26)	–	2,703
Regulatory Liabilities (Note 7)	303	314
Deferred Amounts (Note 11)	805	694
Future Income Taxes (Note 12)	3,788	3,398
Long-Term Debt (Note 13)	17,632	17,028
Long-Term Debt of Joint Ventures (Note 14)	789	801
Junior Subordinated Notes (Note 15)	1,009	985

	30,185	31,611

EQUITY
Controlling interests	18,462	15,747
Non-controlling interests (Note 16)	1,076	768

	19,538	16,515

	49,723	48,126

Commitments, Contingencies and Guarantees (Note 24)

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

On behalf of the Board:


Russell K. Girling Director		Kevin E. Benson Director

96 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED ACCUMULATED OTHER COMPREHENSIVE (LOSS)/INCOME

(millions of dollars)	Currency Translation Adjustments		Cash Flow Hedges and Other		Total

Balance at January 1, 2009	(379	)	(93	)	(472	)
Change in foreign currency translation gains and losses on investments in foreign operations⁽¹⁾	(471	)	–		(471	)
Change in fair value of derivative instruments to hedge the net investments in foreign operations⁽²⁾	258		–		258
Change in fair value of derivative instruments designated as cash flow hedges⁽³⁾	–		77		77
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges⁽⁴⁾	–		(24	)	(24	)

Balance at December 31, 2009	(592	)	(40	)	(632	)
Change in foreign currency translation gains and losses on investments in foreign operations⁽¹⁾	(180	)	–		(180	)
Change in fair value of derivative instruments to hedge the net investments in foreign operations⁽²⁾	89		–		89
Change in fair value of derivative instruments designated as cash flow hedges⁽³⁾	–		(137	)	(137	)
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges⁽⁴⁾	–		(17	)	(17	)

Balance at December 31, 2010	(683	)	(194	)	(877	)
Change in foreign currency translation gains and losses on investments in foreign operations⁽¹⁾	113		–		113
Change in fair value of derivative instruments to hedge the net investments in foreign operations⁽²⁾	(73	)	–		(73	)
Change in fair value of derivative instruments designated as cash flow hedges⁽³⁾	–		(204	)	(204	)
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges⁽⁴⁾⁽⁵⁾	–		117		117

Balance at December 31, 2011	(643	)	(281	)	(924	)

⁽¹⁾: Net of income tax recovery of $29 million in 2011 (2010 – $65 million expense; 2009 – $92 million expense).
⁽²⁾: Net of income tax recovery of $28 million in 2011 (2010 – $37 million expense; 2009 – $124 million expense).
⁽³⁾: Net of income tax recovery of $104 million in 2011 (2010 – $95 million recovery; 2009 – $7 million expense).
⁽⁴⁾: Net of income tax expense of $77 million in 2011 (2010 – $21 million expense; 2009 – $9 million expense).
⁽⁵⁾: Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net Income in 2012 are estimated to be $181 million ($116 million, net of tax). These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

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

CONSOLIDATED FINANCIAL STATEMENTS 97

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED EQUITY

Year ended December 31 (millions of dollars)		2011		2010		2009

Common Shares
Balance at beginning of year		11,636		10,649		8,973
Proceeds from shares issued (Note 17)		2,401		987		1,676

Balance at end of year		14,037		11,636		10,649

Preferred Shares
Balance at beginning and end of year		389		389		389

Contributed Surplus
Balance at beginning of year		341		335		284
Dilution gain from TC PipeLines, LP units issued (Note 23)		30		–		–
Other		5		6		4
Increased ownership in TC PipeLines, LP (Note 23)		–		–		47

Balance at end of year		376		341		335

Retained Earnings
Balance at beginning of year		4,258		4,131		3,789
Net income attributable to controlling interests		1,526		1,256		1,379
Common share dividends		(1,178	)	(1,107	)	(1,015	)
Preferred share dividends		(22	)	(22	)	(22	)

Balance at end of year		4,584		4,258		4,131

Accumulated Other Comprehensive (Loss)/Income
Balance at beginning of year		(877	)	(632	)	(472	)
Other comprehensive loss		(47	)	(245	)	(160	)

Balance at end of year		(924	)	(877	)	(632	)

Equity Attributable to Controlling Interests		18,462		15,747		14,872

Equity Attributable to Non-Controlling Interests
Balance at beginning of year		768		785		805
Net income attributable to non-controlling interests
	TC PipeLines, LP	101		87		66
	Portland	6		6		8
Other comprehensive income attributable to non-controlling interests		11		6		7
Sale of TC PipeLines, LP units
	Proceeds, net of issue costs	321		–		193
	Decrease in TCPL's ownership	(50	)	–		(29	)
Distributions to non-controlling interests		(109	)	(90	)	(78	)
Foreign exchange and other		28		(26	)	(187	)

Balance at end of year		1,076		768		785

Total Equity		19,538		16,515		15,657

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

98 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 DESCRIPTION OF TCPL'S BUSINESS

TransCanada PipeLines Limited (TCPL or the Company) is a wholly owned subsidiary of TransCanada Corporation (TransCanada) and is a leading North American energy company which operates in three business segments, Natural Gas Pipelines, Oil Pipelines and Energy, each of which offers different products and services.

Natural Gas Pipelines

The Natural Gas Pipelines segment consists of the Company's investments in regulated natural gas pipelines and regulated natural gas storage facilities. Through its Natural Gas Pipelines segment, TCPL owns and operates:

•: a natural gas transmission system extending from the Alberta/Saskatchewan border east into Québec (Canadian Mainline);
•: a natural gas transmission system in Alberta and northeastern British Columbia (B.C.) (Alberta System);
•: a natural gas transmission system extending from producing fields primarily located in Texas, Oklahoma, the Gulf of Mexico and Louisiana to markets primarily located in Wisconsin, Michigan, Illinois, Ohio and Indiana, and to regulated natural gas storage facilities in Michigan (ANR);
•: a natural gas transmission system extending from central Alberta to the B.C./Idaho border and to the Saskatchewan/Montana border (Foothills);
•: natural gas transmission systems in Alberta that supply natural gas to the oil sands region of northern Alberta and to a petrochemical complex at Joffre, Alberta (Ventures LP);
•: a natural gas transmission system in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi (Tamazunchale); and
•: a natural gas transmission system in Mexico extending from Manzanillo, Colima to Guadalajara, Jalisco (Guadalajara).

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

•

a 53.6 per cent direct ownership interest in a natural gas transmission system that connects to the Canadian Mainline and serves markets in eastern Canada and the northeastern and midwestern United States (U.S.) (Great Lakes);

•

a 75 per cent direct ownership interest in a natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border (GTN);

•

a 75 per cent direct ownership interest in a natural gas transmission system extending from the Powder River Basin in Wyoming to Northern Border in North Dakota (Bison);

•

a 61.7 per cent interest in a natural gas transmission system that extends from a point near East Hereford, Québec, to the northeastern U.S. (Portland);

•

a 50 per cent interest in a natural gas transmission system that connects with the Canadian Mainline near the Québec/Ontario border and transports natural gas to markets in Québec and to the Portland system (TQM); and

•

a 33.3 per cent controlling interest in TC PipeLines, LP, which has the following ownership interests in pipelines operated by TCPL:

•: a 46.4 per cent interest in Great Lakes, in which TCPL has a combined 69 per cent effective ownership interest through TC PipeLines, LP and a direct interest described above;
•: a 50 per cent interest in a natural gas transmission system extending from a point near Monchy, Saskatchewan, to the U.S. Midwest (Northern Border), in which TCPL has a 16.7 per cent effective ownership interest through TC PipeLines, LP;
•: a 25 per cent interest in GTN, in which TCPL has a combined 83.3 per cent effective ownership interest through TC PipeLines, LP and a direct interest described above;
•: a 25 per cent interest in Bison, in which TCPL has a combined 83.3 per cent effective ownership interest through TC PipeLines, LP and a direct interest described above;
•: a 100 per cent interest in a natural gas transmission system extending from Arizona to Baja California at the Mexico/California border (North Baja), in which TCPL has a 33.3 per cent effective ownership interest through TC PipeLines, LP; and
•: a 100 per cent interest in a natural gas transmission system extending from Malin, Oregon, to Wadsworth, Nevada (Tuscarora), in which TCPL has a 33.3 per cent effective ownership interest through TC PipeLines, LP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 99

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

•: a 44.5 per cent interest in a natural gas transmission system that connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to customers in the northeastern U.S. (Iroquois);
•: a 46.5 per cent interest in a natural gas transmission system extending from Mariquita to Cali in Colombia (TransGas); and
•: a 30 per cent interest in a natural gas transmission system extending from Loma de la Lata, Argentina to Concepción, Chile (Gas Pacifico), and in an industrial natural gas marketing company based in Concepción (INNERGY).

Oil Pipelines

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

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

Energy

The Energy segment primarily consists of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities. Through its Energy segment, the Company owns and operates:

•: a natural gas and oil-fired generating facility in Queens, New York, consisting of multiple units employing steam turbine, combined-cycle and combustion turbine technology (Ravenswood);
•: a natural gas-fired, combined-cycle power plant in Halton Hills, Ontario (Halton Hills);
•: hydroelectric generation assets located in New Hampshire, Vermont and Massachusetts (TC Hydro);
•: a natural gas-fired peaking facility located near Phoenix, Arizona (Coolidge);
•: a natural gas-fired, combined-cycle plant in Burrillville, Rhode Island (Ocean State Power);
•: a natural gas-fired cogeneration plant near Trois-Rivières, Québec (Bécancour);
•: natural gas-fired cogeneration plants in Alberta at Carseland, Redwater, Bear Creek and MacKay River;
•: a wind farm located in Kibby and Skinner townships in northwestern Franklin County, Maine (Kibby Wind);
•: a natural gas-fired cogeneration plant near Saint John, New Brunswick (Grandview);
•: a waste-heat fuelled power plant and the Cancarb thermal carbon black facility in Medicine Hat, Alberta (Cancarb);
•: a natural gas storage facility near Edson, Alberta (Edson); and
•: a 60 per cent interest in an underground natural gas storage facility near Crossfield, Alberta (CrossAlta).

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

•: a 48.8 per cent partnership interest and a 31.6 per cent partnership interest in the nuclear power generation facilities of Bruce A and Bruce B (collectively Bruce Power), respectively, located near Tiverton, Ontario;
•: a 62 per cent interest in the Baie-des-Sables, Anse-à-Valleau, Carleton, Montagne-Sèche and Gros-Morne wind farms in Gaspé, Québec (Cartier Wind). All wind farms are in service with the exception of the second phase of Gros-Morne, which is currently under construction; and
•: a 50 per cent interest in a natural gas-fired, combined-cycle plant in Toronto, Ontario (Portlands Energy).

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

•: 756 megawatts (MW) of generating capacity from the Sheerness power facility near Hanna, Alberta;
•: a 50 per cent interest in ASTC Power Partnership, which has a PPA in place for 100 per cent of the production from the Sundance B power facilities near Wabamun, Alberta; and
•: 100 per cent of the production of the Sundance A power facilities near Wabamun, Alberta.

100 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 ACCOUNTING POLICIES

The Company's consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook (CGAAP) as discussed further in Note 3. Amounts are stated in Canadian dollars unless otherwise indicated. Certain comparative figures have been reclassified to conform with the current year's presentation.

In preparing these financial statements, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies summarized below.

Basis of Presentation

The consolidated financial statements include the accounts of TCPL and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TCPL proportionately consolidates its share of the accounts of joint ventures in which the Company is able to exercise joint control. TCPL uses the equity method of accounting for investments over which the Company is able to exercise significant influence.

Regulation

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

The NEB and the FERC regulate construction and operations of Keystone; however, RRA is not applicable to Keystone and, as a result, the regulators' decisions regarding operations and tolls on Keystone generally do not have an impact on timing of recognition of revenues and expenses.

Revenue Recognition

Canadian Natural Gas Pipelines

Revenues from Canadian natural gas pipelines subject to rate regulation are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline rates are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include an appropriate return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are not subject to risks related to variances in revenues and most costs. These variances are subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines are periodically subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than otherwise required to account for the incentives. Revenues are recognized on firm contracted capacity over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to the NEB's decision on rates for a specified period reflect the NEB's last approved return on equity. Adjustments to revenue are recorded when the NEB decision is received.

U.S. Natural Gas Pipelines

Revenues from U.S. natural gas pipelines subject to rate regulation are recorded in accordance with FERC rules and regulations. The Company's U.S. natural gas pipeline revenues are generally based on quantity of gas delivered or contracted capacity. Revenues are recognized on firm contracted capacity over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made.

Oil Pipelines

The Company's oil pipeline revenues are generated from the transportation of crude oil and contractual arrangements for committed capacity. Transportation revenues are recognized in the period the product is delivered. Transportation revenues are based on actual volumes and reflect adjustments to rates to reflect under-recovery or over-recovery of certain transportation costs. Revenues earned from contracted capacity arrangements are recognized in the period in which the capacity is made available.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 101

Energy

i) Power

Revenues from the Company's power business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, which are earned monthly, and revenues earned through the use of energy derivative contracts. The accounting for energy derivative contracts is described in the Financial Instruments section of this note.

ii) Natural Gas Storage

Revenues earned from providing natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Forward contracts for the purchase or sale of natural gas, as well as proprietary natural gas inventory in storage, are recorded at fair value with changes in fair value recorded in Revenues.

Cash and Cash Equivalents

The Company's Cash and Cash Equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

Inventories

Inventories primarily consist of materials and supplies, including spare parts and fuel, and are carried at the lower of average cost and net realizable value. The Company values its proprietary natural gas inventory in storage at fair value, measured using a weighted average of forward prices for the following four months, which represents the estimated withdrawal period, less selling costs. To record inventory at fair value, TCPL has designated its natural gas storage business as a broker/trader business that purchases and sells natural gas on a back-to-back basis. The Company records its net proprietary natural gas storage sales and purchases in Revenues. All changes in the fair value of proprietary natural gas inventory in storage are reflected in Inventories and in Revenues.

Plant, Property and Equipment

Natural Gas Pipelines

Plant, property and equipment for natural gas pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to six per cent, and metering and other plant equipment are depreciated at various rates. The cost of overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. This allowance is reflected as an increase in the cost of the assets in Plant, Property and Equipment. The equity component of AFUDC is a non-cash item. Interest is capitalized during construction of non-regulated natural gas pipelines.

When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove a plant from service, net of any salvage proceeds, are also recorded in accumulated depreciation.

Oil Pipelines

Plant, property and equipment for oil pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from approximately two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction. When oil pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings.

Energy

Power generation and natural gas storage plant, equipment and structures are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Nuclear power generation assets under capital lease are recorded initially at the present value of minimum lease payments at the inception of the lease and amortized on a straight-line basis over the shorter of their useful life and the remaining lease term. Other equipment is depreciated at various rates. The cost of overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When Energy retires plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings.

102 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Corporate

Corporate plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent.

Impairment of Long-Lived Assets

The Company reviews long-lived assets, such as plant, property and equipment, and intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

Acquisitions and Goodwill

The Company accounts for business acquisitions using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair value at the date of acquisition. Goodwill is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. An initial test is done by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second test is performed to measure the amount of the impairment. In the second test, the implied fair value of goodwill is calculated by deducting the fair value of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded.

Power Purchase Arrangements

A PPA is a long-term contract for the purchase or sale of power on a predetermined basis. The PPAs under which TCPL buys power are accounted for as operating leases. The initial payments for the Company's PPAs were recognized in Intangibles and Other Assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TCPL records the margin earned from the subleases as a component of Revenues.

Income Taxes

The Company uses the liability method of accounting for income taxes. This method requires the recognition of future income tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future income tax assets and liabilities are measured using enacted or substantively enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.

Foreign Currency Translation

The Company's foreign operations are self-sustaining and are translated into Canadian dollars using the current rate method. Under this method, assets and liabilities are translated at the period-end exchange rates and revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. Translation adjustments are reflected in Other Comprehensive Income/(Loss) (OCI).

Exchange gains and losses on monetary assets and liabilities are recorded in income except for exchange gains and losses on the foreign currency debt related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

Financial Instruments

The Company initially records all financial instruments on the Balance Sheet at fair value. Where possible, fair value is determined by reference to quoted market prices. In the absence of quoted prices, other pricing and valuation techniques are used that maximize the use of observable data. The entity's own credit risk and the credit risk of its counterparties are taken into consideration when measuring the fair value of financial assets and financial liabilities. Subsequent measurement of financial instruments is based on their classification. Financial assets are classified into the following categories: held for trading, available for sale, held-to-maturity investments, and loans and receivables. Financial liabilities are classified as held for trading or as other financial liabilities.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 103

Held for trading derivative financial assets and liabilities consist of swaps, options, forwards and futures. A financial asset or liability may be designated as held for trading when it is entered into with the intention of generating a profit. The Company has not designated any of its non-derivative financial assets or liabilities as held for trading. Commodity held for trading financial instruments are initially recorded at their fair value and changes to fair value are included in Revenues. Realized gains and losses on derivatives used to manage the Company's operating assets are presented on a net basis in Revenues. Changes in the fair value of interest rate held for trading instruments are recorded in Interest Expense and changes in the fair value of foreign exchange rate held for trading instruments are recorded in Interest Income and Other. Realized gains and losses are included in the same financial statement category as their underlying position upon settlement of the financial instrument.

The available for sale classification includes non-derivative financial assets that are designated as available for sale or are not included in any of the other three classifications. TCPL's available for sale financial instruments include fixed-income securities held for self-insurance. These instruments are accounted for initially at their fair value and changes to fair value are recorded through OCI. Gains and losses from the settlement of available for sale financial assets is included in Interest Income and Other.

The held-to-maturity classification consists of non-derivative financial assets that are accounted for at their amortized cost using the effective interest method. The Company does not have any held-to-maturity financial assets.

Trade receivables, loans and other receivables with fixed or determinable payments that are not quoted in an active market are classified as loans and receivables and are measured at amortized cost using the effective interest method, net of any impairment. The Company's loans and receivables include trade accounts receivable, interest-bearing and non-interest-bearing third-party loans, and notes receivable. Interest and other income earned from these financial assets are recorded in Interest Income and Other.

Other financial liabilities consist of liabilities not classified as held for trading. Items in this financial instrument category are recognized at amortized cost using the effective interest method. Interest costs are included in Interest Expense and in Interest Expense of Joint Ventures.

The Company uses derivatives and other financial instruments to manage its exposure to changes in foreign currency exchange rates, interest rates and energy commodity prices. The Company also uses a combination of derivatives and U.S. dollar-denominated debt to manage the foreign currency exposure of its foreign operations.

All derivatives are recorded on the balance sheet at fair value, with the exception of non-financial derivatives that were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's expected normal purchase, sale or usage requirements. Derivatives used in hedging relationships are discussed further in the Hedges section of this note.

Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are recorded separately, they are included in Net Income.

The recognition of gains and losses on the derivatives used to manage the Canadian natural gas regulated pipelines exposures is determined through the regulatory process. The gains and losses on derivatives accounted for as part of RRA are deferred in Regulatory Assets or Regulatory Liabilities.

Transaction costs are defined as incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. The Company offsets long-term debt transaction costs against the associated debt and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of tolling mechanisms.

The Company records the fair value of its portion of material joint and several guarantees. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to an investment account, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Deferred Amounts.

Hedges

The Company applies hedge accounting to arrangements that qualify for hedge accounting treatment, which include fair value and cash flow hedges, and hedges of foreign currency exposures of net investments in self-sustaining foreign operations. Documentation is prepared at the inception of each hedging arrangement in order to qualify for hedge accounting treatment. In addition, the Company performs an assessment of effectiveness at the inception of the contract and at each reporting date. Hedge accounting is discontinued prospectively when the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination or cancellation.

In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in Net Income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is

104 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

effective, are offset by changes in the fair value of the hedging item, which are also recorded in Net Income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest Income and Other and Interest Expense, respectively. When hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net Income over the remaining term of the original hedging relationship.

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in Net Income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in Accumulated Other Comprehensive (Loss)/Income (AOCI) are reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, during the periods when the variability in cash flows of the hedged item affects Net Income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to Net Income from AOCI when the hedged item is sold or terminated early, or when it is probable the anticipated transaction will not occur.

The Company also enters into cash flow hedges and fair value hedges for activities subject to rate regulation in Canada. The gains and losses arising from changes in the fair value of these hedges can be recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as Regulatory Assets or Regulatory Liabilities. When the hedges are settled, the realized gains or losses are refunded to or collected from the ratepayers in subsequent years.

Asset Retirement Obligations

The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.

Environmental Liabilities

The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.

Emission allowances or credits purchased for compliance are recorded on the Balance Sheet at historical cost and expensed when they are utilized. Compliance payments are expensed when incurred. Allowances granted to or internally generated by TCPL are not attributed a value for accounting purposes. When required, TCPL accrues emission liabilities on the Balance Sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and recorded in Revenues.

Employee Benefit and Other Plans

The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a Savings Plan and other post-employment benefit plans. Contributions made by the Company to the DC Plans and Savings Plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-employment benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.

The DB Plans' assets are measured at fair value. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized over the average remaining service period of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.

The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 105

Certain of the Company's joint ventures sponsor DB Plans. The Company records its proportionate share of expenses, funding contributions and accrued benefit assets and liabilities related to these plans.

NOTE 3 ACCOUNTING CHANGES

Changes in Accounting Policies for 2011

Business Combinations

Consolidated Financial Statements and Non-Controlling Interests

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

Future Accounting Changes

United States Generally Accepted Accounting Principles

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

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

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

Fair Value Measurement

Intangibles – Goodwill and Other

106 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheet Offsetting/Netting

NOTE 4 SEGMENTED INFORMATION

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

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

Year ended December 31, 2011 (millions of dollars)

Natural Gas
Pipelines

Oil Pipelines

Energy

Corporate

Total

Revenues

4,500

827

3,812

–

9,139

Plant operating costs and other

(1,533

)

(240

)

(1,590

)

(86

)

(3,449

)

Commodity purchases resold

–

(941

)

–

(941

)

Depreciation and amortization

(986

)

(130

)

(398

)

(14

)

(1,528

)

1,981

457

883

(100

)

3,221

Interest expense

(1,044

)

Interest expense of joint ventures

(55

)

Interest income and other

Income tax expense

(544

)

Net Income

1,633

Net Income Attributable to Non-Controlling Interests

(107

)

Net Income Attributable to Controlling Interests

1,526

Preferred Share Dividends

(22

)

Net Income Attributable to Common Shares

1,504

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 107

Year ended December 31, 2010 (millions of dollars)	Natural Gas Pipelines		Oil Pipelines	Energy		Corporate		Total

Revenues	4,373		–	3,691		–		8,064
Plant operating costs and other⁽¹⁾	(1,458	)	–	(1,557	)	(99	)	(3,114	)
Commodity purchases resold	–		–	(1,017	)	–		(1,017	)
Depreciation and amortization	(977	)	–	(377	)	–		(1,354	)
Valuation provision for MGP	(146	)	–	–		–		(146	)

	1,792		–	740		(99	)	2,433

Interest expense								(754	)
Interest expense of joint ventures								(59	)
Interest income and other								94
Income tax expense								(365	)

Net Income								1,349
Net Income Attributable to Non-Controlling Interests								(93	)

Net Income Attributable to Controlling Interests								1,256
Preferred Share Dividends								(22	)

Net Income Attributable to Common Shares								1,234

⁽¹⁾: In 2010, Natural Gas Pipelines included $17 million of general, administrative and support costs relating to Keystone.

Year ended December 31, 2009 (millions of dollars)	Natural Gas Pipelines		Oil Pipelines	Energy		Corporate		Total

Revenues	4,729		–	3,452		–		8,181
Plant operating costs and other	(1,607	)	–	(1,489	)	(117	)	(3,213	)
Commodity purchases resold	–		–	(831	)	–		(831	)
Depreciation and amortization	(1,030	)	–	(347	)	–		(1,377	)

	2,092		–	785		(117	)	2,760

Interest expense								(986	)
Interest expense of joint ventures								(64	)
Interest income and other								119
Income tax expense								(376	)

Net Income								1,453
Net Income Attributable to Non-Controlling Interests								(74	)

Net Income Attributable to Controlling Interests								1,379
Preferred Share Dividends								(22	)

Net Income Attributable to Common Shares								1,357

TOTAL ASSETS

December 31 (millions of dollars)	2011	2010

Natural Gas Pipelines	23,669	23,629
Oil Pipelines	9,439	8,501
Energy	14,276	12,966
Corporate	2,339	3,030

	49,723	48,126

108 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

GEOGRAPHIC INFORMATION

Year ended December 31 (millions of dollars)	2011	2010	2009

Revenues⁽¹⁾
Canada – domestic	4,836	4,368	5,079
Canada – export	1,087	838	756
United States and other	3,216	2,858	2,346

	9,139	8,064	8,181

⁽¹⁾: Revenues are attributed based on the country in which the product or service originated.

December 31 (millions of dollars)	2011	2010

Plant, Property and Equipment
Canada	22,349	21,561
United States and other	15,913	14,683

	38,262	36,244

CAPITAL EXPENDITURES

Year ended December 31 (millions of dollars)	2011	2010	2009

Natural Gas Pipelines	935	1,196	965
Oil Pipelines	1,204	2,696	2,939
Energy	1,127	1,129	1,487
Corporate	8	15	26

	3,274	5,036	5,417

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 109

NOTE 5 PLANT, PROPERTY AND EQUIPMENT

		2011			2010

December 31 (millions of dollars)		Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Natural Gas Pipelines⁽¹⁾
Canadian Mainline
	Pipeline	8,785	4,958	3,827	8,768	4,730	4,038
	Compression	3,362	1,765	1,597	3,385	1,651	1,734
	Metering and other	383	175	208	381	167	214

		12,530	6,898	5,632	12,534	6,548	5,986
	Under construction	28	–	28	14	–	14

		12,558	6,898	5,660	12,548	6,548	6,000

Alberta System
	Pipeline	6,701	3,062	3,639	6,528	2,917	3,611
	Compression	1,778	1,109	669	1,707	1,045	662
	Metering and other	931	409	522	909	378	531

		9,410	4,580	4,830	9,144	4,340	4,804
	Under construction	368	–	368	71	–	71

		9,778	4,580	5,198	9,215	4,340	4,875

ANR
	Pipeline	858	47	811	858	96	762
	Compression	510	72	438	507	74	433
	Metering and other	576	81	495	548	74	474

		1,944	200	1,744	1,913	244	1,669
	Under construction	20	–	20	7	–	7

		1,964	200	1,764	1,920	244	1,676

Joint Ventures and Others
	GTN	1,612	370	1,242	1,557	319	1,238
	Great Lakes	1,581	741	840	1,540	698	842
	Foothills	1,630	1,005	625	1,650	975	675
	Northern Border	1,288	644	644	1,252	608	644
	Other⁽²⁾	3,132	720	2,412	2,913	633	2,280

		9,243	3,480	5,763	8,912	3,233	5,679

		33,543	15,158	18,385	32,595	14,365	18,230

Oil Pipelines
Keystone
	Pipeline	4,904	80	4,824	–	–	–
	Pumping equipment	1,502	38	1,464	–	–	–
	Tanks and other	548	15	533	–	–	–

		6,954	133	6,821	–	–	–
Under construction⁽³⁾		2,433	–	2,433	8,184	–	8,184

		9,387	133	9,254	8,184	–	8,184

Energy
Nuclear⁽⁴⁾		1,712	630	1,082	1,586	536	1,050
Natural Gas – Ravenswood		1,799	220	1,579	1,710	144	1,566
Natural Gas – Other⁽⁵⁾		3,337	708	2,629	2,767	588	2,179
Hydro		620	90	530	599	69	530
Wind⁽⁶⁾		843	88	755	659	65	594
Natural Gas Storage		454	78	376	423	67	356
Other		163	94	69	160	96	64

		8,928	1,908	7,020	7,904	1,565	6,339
Under construction – Nuclear⁽⁷⁾		3,217	–	3,217	2,678	–	2,678
Under construction – Other⁽⁸⁾		308	–	308	728	–	728

		12,453	1,908	10,545	11,310	1,565	9,745

Corporate		129	51	78	125	40	85

		55,512	17,250	38,262	52,214	15,970	36,244

⁽¹⁾: In 2011, the Company capitalized $23 million (2010 – $35 million) relating to the equity portion of AFUDC for natural gas pipelines with a corresponding amount recorded in Interest Income and Other.
⁽²⁾: Includes in service assets of Bison, Tamazunchale, Portland, Iroquois, TQM, North Baja, Guadalajara, Tuscarora and Ventures LP, and under construction amounts of $33 million (2010 – $899 million). Bison went in service in January 2011 and Guadalajara went in service in June 2011.
⁽³⁾: Includes $2.4 billion at December 31, 2011 (2010 – $1.4 billion) relating to Keystone XL which remains subject to regulatory approvals.

110 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

⁽⁴⁾: Includes assets under capital lease relating to Bruce Power.
⁽⁵⁾: Includes facilities with long-term PPAs that are accounted for as operating leases, including Coolidge which went in service in May 2011. The cost and accumulated depreciation of these facilities were $605 million and $34 million, respectively, at December 31, 2011 (2010 – $89 million and $19 million, respectively). Revenues of $53 million were recognized in 2011 (2010 and 2009 – $15 million) through the sale of electricity under the related PPAs.
⁽⁶⁾: Includes Montagne-Sèche and phase one of Gros-Morne effective November 2011.
⁽⁷⁾: Nuclear assets under construction primarily includes expenditures for the refurbishment and restart of Bruce A.
⁽⁸⁾: Other Energy assets under construction at December 31, 2011 includes amounts for the second phase of the Gros-Morne wind farm (Cartier Wind).

NOTE 6 GOODWILL

The Company has recorded the following goodwill on its acquisitions in the U.S.:

(millions of dollars)	Natural Gas Pipelines		Energy		Total

Balance at January 1, 2010	2,891		872		3,763
Foreign exchange rate changes	(144	)	(49	)	(193	)

Balance at December 31, 2010	2,747		823		3,570
Foreign exchange rate changes	62		18		80

Balance at December 31, 2011	2,809		841		3,650

NOTE 7 RATE-REGULATED BUSINESSES

TCPL's businesses that apply RRA currently include Canadian and U.S. natural gas pipelines and regulated U.S. natural gas storage. Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities.

Canadian Regulated Operations

Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return on capital as approved by the applicable regulatory authorities.

Rates charged by TCPL's Canadian regulated pipelines are typically set through a process that involves filing an application with the regulators for a change in rates. Regulated rates are underpinned by the total annual revenue requirement, which comprises a specified annual return on capital, including debt and equity, and all necessary operating expenses, taxes and depreciation.

TCPL's Canadian regulated natural gas pipelines have generally been subject to a cost-of-service model wherein forecasted costs, including a return on capital, determine the revenues for the upcoming year. To the extent that actual costs and revenues are more or less than the forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they are incurred.

The Canadian Mainline, Alberta System, Foothills and TQM pipelines are regulated by the NEB under the National Energy Board Act (Canada). The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems.

In October 2009, the NEB issued a decision that its RH-2-94 Decision, which established a rate of return on common equity (ROE) formula that had formed the basis of determining tolls for natural gas pipelines under NEB jurisdiction since 1995, would no longer be in effect. The decision meant a company's cost of capital will now be determined by negotiations between pipeline companies and their shippers or by the NEB if a pipeline company files a cost of capital application. The decision has affected TCPL's NEB regulated pipelines. However, the Canadian Mainline continues to base its return on the RH-2-94 ROE formula in accordance with the terms of the current Canadian Mainline tolls settlement, described below.

Canadian Mainline

In 2011, the Canadian Mainline operated under its five-year settlement, which was effective January 1, 2007 to December 31, 2011. The Canadian Mainline's cost of capital for establishing tolls under the settlement reflects ROE as determined by the NEB's RH-2-94 ROE formula

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 111

on a deemed common equity of 40 per cent. The allowed ROE in 2011 for the Canadian Mainline was 8.08 per cent (2010 – 8.52 per cent). The balance of the capital structure is comprised of short and long-term debt.

The settlement also established the Canadian Mainline's fixed operating, maintenance and administration (OM&A) costs for each of the five years. Variances between actual OM&A costs and those agreed to in the settlement accrued fully to TCPL from 2007 to 2009. Variances in OM&A costs were shared equally between TCPL and its customers in 2010 and 2011. All other cost elements of the revenue requirement are treated on a flow-through basis. The settlement also allows for performance-based incentive arrangements. In 2009, the NEB approved an adjustment account, which was established to reduce tolls in 2010 under a settlement with stakeholders. In accordance with the terms of the settlement, balances in the adjustment account are to be amortized at the composite depreciation rate and included in tolls beginning in 2011.

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

Alberta System

In September 2010, the NEB approved the Alberta System's 2010 – 2012 Revenue Requirement Settlement Application. The settlement provides for a 9.70 per cent ROE on a deemed common equity of 40 per cent and fixes certain annual OM&A costs during the term. Any variances between actual costs and those agreed to in the settlement accrue to TCPL. All other costs are treated on a flow-through basis.

Foothills

In June 2010, TCPL reached an agreement to establish a cost of capital for Foothills that reflects a 9.70 per cent ROE on a deemed common equity of 40 per cent for 2010 to 2012. A component of OM&A is fixed, subject to the terms of the B.C System/Foothills Integration Settlement, and variances between actual and fixed amounts were shared with customers up to and including June 2011 when the OM&A savings cap was reached.

TQM

In November 2010, the NEB approved TQM's multi-year settlement with its interested parties regarding its annual revenue requirements for 2010 to 2012. As part of the settlement, the annual revenue requirement comprises fixed and flow-through components. The fixed component includes certain OM&A costs, return on rate base, depreciation and municipal taxes. Any variances between actual costs and those included in the fixed component accrue to TQM.

U.S. Regulated Operations

TCPL's U.S. natural gas pipelines are "natural gas companies" operating under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The Company's significant regulated U.S. natural gas pipelines are described below.

ANR

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

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

GTN

GTN is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for various services. GTN is permitted to discount or negotiate these rates on a non-discriminatory basis. GTN's rates were established pursuant to a settlement approved by the FERC in January 2008. That settlement required GTN to file a rate case within seven years of the effective date. In November 2011, the FERC approved, without modification, GTN's new settlement with its shippers regarding GTN's rates, terms and conditions of service which will become effective January 1, 2012. This new settlement provides for a four year moratorium during which GTN and the settling parties are prohibited from taking certain actions under the NGA, including filings to adjust rates. GTN is required to file for new rates to be effective January 1, 2016.

112 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Great Lakes

Great Lakes is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for its various services and permits Great Lakes to discount or negotiate rates on a non-discriminatory basis. Great Lakes rates were established pursuant to a settlement approved by the FERC in July 2010. The settlement included a moratorium on participants and customers from initiating a NGA Section 5 rate case to adjust rates prior to November 1, 2012. In addition, Great Lakes is required to file a NGA Section 4 general rate case no later than November 1, 2013.

Bison

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

Regulatory Assets and Liabilities

Year ended December 31 (millions of dollars)	2011	2010	Remaining Recovery/ Settlement Period (years)

Regulatory Assets
Future income taxes⁽¹⁾	1,178	1,256	n/a
Operating and debt-service regulatory assets⁽²⁾	172	237	1
Adjustment account⁽³⁾	82	85	31
Other⁽⁴⁾	151	174	n/a

	1,583	1,752
Less: Current portion included in Other Current Assets	178	240

	1,405	1,512

Regulatory Liabilities
Foreign exchange on long-term debt⁽⁵⁾	184	200	1- 18
Operating and debt-service regulatory liabilities⁽²⁾	135	98	1
Other⁽⁴⁾	123	150	n/a

	442	448
Less: Current portion included in Accounts Payable	139	134

	303	314

⁽¹⁾: These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.
⁽²⁾: Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar year. Pre-tax operating results in 2011 would have been $102 million higher (2010 – $51 million higher) had these amounts not been recorded as regulatory assets and liabilities.
⁽³⁾: A regulatory adjustment account of $85 million was established and agreed upon by Canadian Mainline stakeholders to reduce tolls in 2010. Amortization of the adjustment account commenced in 2011 at the composite depreciation rate.
⁽⁴⁾: Pre-tax operating results in 2011 would have been $4 million lower (2010 – $28 million higher) had these amounts not been recorded as regulatory assets and liabilities.
⁽⁵⁾: Foreign exchange on long-term debt of the Canadian Mainline, Alberta System and Foothills represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of RRA, CGAAP would have required the inclusion of these unrealized gains or losses in Net Income.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 113

NOTE 8 JOINT VENTURE INVESTMENTS

		TCPL's Proportionate Share

		Income before Income Taxes Year Ended December 31			Net Assets December 31

(millions of dollars)	Ownership Interest as at December 31, 2011	2011	2010	2009	2011	2010

Natural Gas Pipelines
Northern Border⁽¹⁾		75	69	47	429	389
Iroquois	44.5%	40	40	44	181	181
TQM	50.0%	17	16	22	82	85
Other	Various	14	16	17	32	36
Energy
Bruce A	48.8%	33	35	3	3,537	3,011
Bruce B	31.6%	77	138	236	493	505
ASTC Power Partnership	50.0%	84	41	34	58	61
Portlands Energy	50.0%	33	33	24	313	335
CrossAlta	60.0%	23	45	55	81	73
Cartier Wind⁽²⁾	62.0%	27	24	26	518	355
Other	Various	7	8	4	50	42

		430	465	512	5,774	5,073

⁽¹⁾: The results reflect a 50 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2011, TCPL had an ownership interest in TC PipeLines, LP of 33.3 per cent (2010 and 2009 – 38.2 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 16.7 per cent (2010 and 2009 – 19.1 per cent).
⁽²⁾: TCPL proportionately consolidates its 62 per cent interest in the Cartier Wind assets. The Montagne-Sèche project and phase one of the Gros-Morne wind farm were placed in service in November 2011.

Summarized Financial Information of Joint Ventures

Year ended December 31 (millions of dollars)	2011		2010		2009

Income
Revenues	1,668		1,643		1,632
Plant operating costs and other	(974	)	(913	)	(856	)
Depreciation and amortization	(212	)	(208	)	(196	)
Interest expense and other	(52	)	(57	)	(68	)

Proportionate Share of Joint Venture Income before Income Taxes	430		465		512

Year ended December 31 (millions of dollars)	2011		2010		2009

Cash Flows
Operating activities	733		678		455
Investing activities	(827	)	(722	)	(651	)
Financing activities⁽¹⁾	99		51		130
Effect of foreign exchange rate changes on cash and cash equivalents	2		(1	)	(17	)

Proportionate Share of Increase/(Decrease) in Cash and Cash Equivalents of Joint Ventures	7		6		(83	)

⁽¹⁾: Financing activities included cash outflows resulting from distributions paid to TCPL of $486 million in 2011 (2010 – $475 million; 2009 – $252 million) and cash inflows resulting from capital contributions paid by TCPL of $633 million in 2011 (2010 – $601 million; 2009 – $864 million).

114 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31 (millions of dollars)	2011		2010

Balance Sheet
Cash and cash equivalents	111		104
Other current assets	433		438
Plant, property and equipment	6,430		5,704
Intangibles and other assets/(deferred amounts), net	26		14
Current liabilities	(437	)	(387	)
Long-term debt	(789	)	(801	)
Future income taxes	–		1

Proportionate Share of Net Assets of Joint Ventures	5,774		5,073

NOTE 9 INTANGIBLES AND OTHER ASSETS

December 31 (millions of dollars)	2011	2010

Employee benefit plans (Note 20)	499	473
PPAs⁽¹⁾	482	539
Loans and advances⁽²⁾	224	241
Fair value of derivative contracts (Note 21)	213	374
Future income tax assets (Note 12)	127	97
Margin calls	104	76
Equity investments⁽³⁾	41	78
Other	342	245

	2,032	2,123

⁽¹⁾: The following amounts related to PPAs are included in Intangibles and Other Assets:

	2011			2010

December 31 (millions of dollars)	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value

Sheerness	585	234	351	585	195	390
Sundance A	225	148	77	224	133	91
Sundance B	110	56	54	110	52	58

PPAs	920	438	482	919	380	539

: Amortization expense for the PPAs was $58 million for the year ended December 31, 2011 (2010 and 2009 – $58 million). The expected annual amortization expense in each of the next five years is $58 million. The $77 million net book value related to Sundance A is expected to remain fully recoverable under the terms of the PPA regardless of the outcome of the arbitration process discussed in Note 24 "Commitments, Contingencies and Guarantees".
⁽²⁾: As at December 31, 2011, TCPL held a $265 million (2010 – $281 million) note receivable from the seller of Ravenswood which bears interest at 6.75 per cent and matures in 2039. This represents the long-term portion of that note.
⁽³⁾: The balance primarily relates to the Company's 46.5 per cent ownership interest in TransGas.

Advances to Aboriginal Pipeline Group

The Mackenzie Delta gas producers, the Aboriginal Pipeline Group (APG) and TCPL have an agreement governing TCPL's role in the Mackenzie Gas Project (MGP). The project, if successful, would result in a natural gas pipeline being constructed from Inuvik, Northwest Territories to the northern border of Alberta, where it would connect to the Alberta System. Under the agreement, TCPL agreed to finance the APG for its one-third share of project pre-development costs.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 115

At December 31, 2010, due to uncertainty with respect to the project's ultimate commercial structure and fiscal framework, the timeframes under which the project would proceed and if and when the Company's advances to the APG will be repaid, a valuation provision of $146 million was recorded on the loan to the APG. Amounts advanced to the APG in furtherance of the MGP in 2011 have been expensed.

NOTE 10 NOTES PAYABLE

	2011		2010

	Outstanding December 31	Weighted Average Interest Rate per Annum at December 31	Outstanding December 31	Weighted Average Interest Rate per Annum at December 31

	(millions of dollars)		(millions of dollars)
Canadian dollars	483	1.2%	601	1.2%
U.S. dollars (2011 – US$1,373; 2010 – US$1,499)	1,397	0.5%	1,491	0.7%

	1,880		2,092

Notes payable consists of commercial paper issued by TCPL and wholly owned subsidiaries, and draws on line-of-credit and demand facilities.

At December 31, 2011, total committed revolving and demand credit facilities of $5.1 billion were available. When drawn, interest on the lines of credit is charged at prime rates of Canadian chartered and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:

•: a $2.0 billion committed, syndicated, revolving, extendible TCPL credit facility, maturing October 2016. The facility was fully available at December 31, 2011. The cost to maintain the credit facility was $2 million in 2011 (2010 – $2 million; 2009 – $2 million);
•: a US$300 million committed, syndicated, revolving TCPL USA credit facility, guaranteed by TransCanada and maturing February 2013. At December 31, 2011, this facility was fully available. This facility is part of an initial US$1.0 billion credit facility discussed in Note 13. The cost to maintain the credit facility was $1 million in 2011 (2010 – $1 million; 2009 – $1 million);
•: a US$1.0 billion committed, syndicated, revolving, extendible TC Keystone credit facility, guaranteed by TCPL and TCPL USA and maturing November 2012. The facility was fully available at December 31, 2011. The cost to maintain the credit facility was $4 million in 2011 (2010 – $5 million; 2009 – $2 million);
•: a US$1.0 billion committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL and maturing October 2012. At December 31, 2011, this facility was fully available. The cost to maintain the credit facility was $4 million in 2011 (2010 – $4 million); and
•: demand lines totalling $802 million, which support the issuance of letters of credit and provide additional liquidity. At December 31, 2011, the Company had used approximately $468 million of these demand lines for letters of credit.

NOTE 11 DEFERRED AMOUNTS

December 31 (millions of dollars)	2011	2010

Fair value of derivative contracts (Note 21)	352	282
Employee benefit plans (Note 20)	285	251
Asset retirement obligations (Note 19)	68	65
Other	100	96

	805	694

116 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12 INCOME TAXES

Provision for Income Taxes

Year ended December 31 (millions of dollars)	2011		2010		2009

Current
Canada	195		27		(68	)
Foreign	(2	)	(169	)	100

	193		(142	)	32

Future
Canada	125		156		326
Foreign	226		351		18

	351		507		344

Income Tax Expense	544		365		376

Geographic Components of Income

Year ended December 31 (millions of dollars)	2011	2010	2009

Canada	1,068	745	1,061
Foreign	1,109	969	768

Income before Income Taxes	2,177	1,714	1,829

Reconciliation of Income Tax Expense

Year ended December 31 (millions of dollars)	2011		2010		2009

Income before Income Taxes	2,177		1,714		1,829
Federal and provincial statutory tax rate	26.5%		28.0%		29.0%
Expected income tax expense	577		480		530
Income tax differential related to regulated operations	42		8		39
Lower effective foreign tax rates	(5	)	(36	)	(63	)
Tax rate and legislative changes	–		–		(30	)
Income from equity investments and non-controlling interests	(45	)	(40	)	(37	)
Other	(25	)	(47	)	(63	)

Actual Income Tax Expense	544		365		376

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 117

Future Income Tax Assets and Liabilities

December 31 (millions of dollars)	2011	2010

Future Income Tax Assets
Operating loss carryforwards	905	494
Financial instruments	163	108
Other post-employment benefits	74	75
Deferred amounts	49	42
Other	126	125

	1,317	844

Future Income Tax Liabilities
Difference in accounting and tax bases of plant, equipment and PPAs	4,164	3,439
Taxes on future revenue requirement	299	321
Unrealized foreign exchange gains on long-term debt	133	161
Pension benefits	94	96
Other	107	77

	4,797	4,094

Net Future Income Tax Liabilities	3,480	3,250

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

December 31 (millions of dollars)	2011	2010⁽¹⁾

Future Income Tax Assets
Other current assets	256	80
Intangibles and other assets (Note 9)	127	97

	383	177

Future Income Tax Liabilities
Accounts payable	75	29
Future income taxes	3,788	3,398

	3,863	3,427

Net Future Income Tax Liabilities	3,480	3,250

⁽¹⁾: Amounts relating to deferred tax assets and liabilities as at December 31, 2010 have been reclassified to conform with current year's presentation.

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

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

Unremitted Earnings of Foreign Investments

Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Future income tax liabilities would have increased at December 31, 2011 by approximately $136 million (2010 – $105 million) if there had been a provision for these taxes.

Income Tax Payments

Income tax refunds of $85 million, net of payments made, were received in 2011 (2010 – payments, net of refunds, of $57 million; 2009 – payments, net of refunds, of $83 million).

118 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 13 LONG-TERM DEBT

2011

2010

Outstanding loan amounts
(millions of dollars)

Maturity Dates

Outstanding
December 31

Interest
Rate⁽¹⁾

Outstanding
December 31

Interest
Rate⁽¹⁾

TRANSCANADA PIPELINES LIMITED

Debentures

Canadian dollars

2014 to 2020

873

10.9%

872

10.9%

U.S. dollars (2011 and 2010 – US$600)

2012 to 2021

608

9.5%

595

9.5%

Medium-Term Notes

Canadian dollars

2013 to 2041

4,537

5.9%

4,150

6.2%

Senior Unsecured Notes

U.S. dollars (2011 and 2010 – US$8,626)⁽²⁾

2013 to 2040

8,693

5.7%

8,490

5.7%

14,711

14,107

NOVA GAS TRANSMISSION LTD.

Debentures and Notes

Canadian dollars

2014 to 2024

386

11.5%

390

11.4%

U.S. dollars (2011 and 2010 – US$375)

2012 to 2023

380

8.2%

371

8.2%

Medium-Term Notes

Canadian dollars

2025 to 2030

502

7.4%

502

7.4%

U.S. dollars (2011 and 2010 – US$33)

2026

7.5%

7.5%

1,301

1,295

TRANSCANADA PIPELINE USA LTD.

Bank Loan

U.S. dollars (2011 – US$500; 2010 – US$700)

2012

509

0.6%

696

0.5%

ANR PIPELINE COMPANY

Senior Unsecured Notes

U.S. dollars (2011 and 2010 – US$432)

2021 to 2025

438

8.9%

429

8.9%

GAS TRANSMISSION NORTHWEST CORPORATION

Senior Unsecured Notes

U.S. dollars (2011 and 2010 – US$325)

2015 to 2035

329

5.5%

322

5.5%

TC PIPELINES, LP

Unsecured Loan

U.S. dollars (2011 – US$363; 2010 – US$483)

2016

366

1.6%

480

0.8%

Senior Unsecured Notes

U.S. dollars (2011 – US$350)

2021

356

4.7%

–

722

480

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

Senior Unsecured Notes

U.S. dollars (2011 – US$373; 2010 – US$392)

2018 to 2030

379

7.8%

389

7.8%

TUSCARORA GAS TRANSMISSION COMPANY

Senior Secured Notes

U.S. dollars (2011 – US$30; 2010 – US$31)

2012 to 2017

4.4%

4.4%

PORTLAND NATURAL GAS TRANSMISSION SYSTEM

Senior Secured Notes⁽³⁾

U.S. dollars (2011 – US$147; 2010 – US$164)

2018

147

6.1%

161

6.1%

OTHER

Senior Notes

U.S. dollars (2011 – nil; 2010 – US$12)

–

7.3%

18,567

17,922

Less: Current Portion of Long-Term Debt

935

894

17,632

17,028

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 119

⁽¹⁾: Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's regulated operations, in which case the weighted average interest rate is presented as required by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates.
⁽²⁾: Includes fair value adjustments of $13 million (2010 – $8 million) for interest rate swap agreements on US$350 million of debt at December 31, 2011 (2010 – US$250 million).
⁽³⁾: Senior Secured Notes are secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

Principal Repayments

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

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

TransCanada PipeLines Limited

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

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

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

In September 2010, TCPL issued US$1.0 billion of Senior Notes maturing October 1, 2020, and bearing interest at 3.80 per cent.

In June 2010, TCPL issued US$500 million and US$750 million of Senior Notes maturing on June 1, 2015 and June 1, 2040, respectively, and bearing interest at 3.40 per cent and 6.10 per cent, respectively.

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

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

In February 2009, TCPL issued $300 million and $400 million of Medium-Term Notes maturing in February 2014 and February 2039, respectively, and bearing interest at 5.05 per cent and 8.05 per cent, respectively. Also in February 2009, TCPL retired $200 million of 4.10 per cent Medium-Term Notes.

In January 2009, TCPL issued US$750 million and US$1.25 billion of Senior Unsecured Notes maturing in January 2019 and January 2039, respectively, and bearing interest at 7.125 per cent and 7.625 per cent, respectively. Also in January 2009, TCPL retired US$227 million of 6.49 per cent Medium-Term Notes.

NOVA Gas Transmission Ltd.

Debentures issued by NOVA Gas Transmission Ltd. (NGTL) in the amount of $225 million have retraction provisions that entitle the holders to require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions were made to December 31, 2011.

TransCanada PipeLine USA Ltd.

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

120 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TC PipeLines, LP

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

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

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

Interest Expense

Year ended December 31 (millions of dollars)	2011		2010		2009

Interest on long-term debt	1,154		1,149		1,212
Interest on junior subordinated notes	63		65		73
Interest on short-term debt	123		68		41
Capitalized interest	(302	)	(587	)	(358	)
Amortization and other financial charges⁽¹⁾	6		59		18

	1,044		754		986

⁽¹⁾: Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to rising interest rates.

The Company made interest payments of $1,069 million in 2011 (2010 – $718 million; 2009 – $968 million) on long-term debt and junior subordinated notes, net of interest capitalized on construction projects.

NOTE 14 LONG-TERM DEBT OF JOINT VENTURES

			2011		2010

Outstanding loan amounts (millions of dollars)		Maturity Dates	Outstanding December 31⁽¹⁾	Interest Rate⁽²⁾	Outstanding December 31⁽¹⁾	Interest Rate⁽²⁾

NORTHERN BORDER PIPELINE COMPANY
Senior Unsecured Notes
	U.S. dollars (2011 and 2010 – US$175)	2016 to 2021	177	7.1%	174	7.1%
Bank Facility
	U.S. dollars (2011 – US$62; 2010 – US$96)	2016	62	1.6%	94	0.5%
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
Senior Unsecured Notes
	U.S. dollars (2011 – US$169; 2010 – US$178)	2019 to 2027	171	6.1%	176	6.1%
BRUCE POWER L.P. AND BRUCE POWER A L.P.
Capital Lease Obligations		2018	194	7.5%	207	7.5%
Term Loan		2031	88	7.1%	90	7.1%
TRANS QUÉBEC & MARITIMES PIPELINE INC.
Bonds		2014 to 2017	87	4.2%	87	4.2%
Term Loan		2016	30	2.2%	35	1.6%
OTHER		2012 to 2016	13	4.0%	3	2.7%

			822		866
Less: Current Portion of Long-Term Debt of Joint Ventures			33		65

			789		801

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 121

⁽¹⁾: Amounts outstanding represent TCPL's proportionate share, except for Northern Border, which reflects a 50 per cent interest as a result of the Company fully consolidating TC PipeLines, LP.
⁽²⁾: Interest rates are the effective interest rates except for those pertaining to long-term debt issued for TQM's regulated operations, in which case the weighted average interest rate is presented as required by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates.

The long-term debt of joint ventures is non-recourse to TCPL, except that TCPL has provided certain pro-rata guarantees related to the capital lease obligations of Bruce Power. The security provided with respect to the debt of each joint venture is limited to the rights and assets of the joint venture and does not extend to the rights and assets of TCPL, except to the extent of TCPL's investment. TQM has two series of bonds which mature in 2014 and 2017, respectively. The bonds are secured by the pledge of a bond and promissory note of certain affiliated entities. All security interests with respect to the TQM bonds terminate on redemption or repayment of the series of bonds maturing in 2014.

Subject to meeting certain requirements, the Bruce Power capital lease agreements provide for a series of renewals commencing January 1, 2019. The first renewal is for a period of one year and each of 12 renewals thereafter is for a period of two years.

The Company's proportionate share of principal repayments for the next five years resulting from maturities and sinking fund obligations of the non-recourse joint venture debt is approximately as follows: 2012 – $15 million; 2013 – $8 million; 2014 – $44 million; 2015 – $7 million; and 2016 – $149 million.

The Company's proportionate share of principal payments for the next five years resulting from the capital lease obligations of Bruce Power is approximately as follows: 2012 – $18 million; 2013 – $20 million; 2014 – $22 million; 2015 – $26 million; and 2016 – $31 million.

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

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

Sensitivity

A one per cent change in interest rates would have the following effect on Net Income assuming all other variables were to remain constant:

(millions of dollars)	Increase	Decrease

Effect on interest expense of variable interest rate debt	1	(1	)

Interest Expense of Joint Ventures

Year ended December 31 (millions of dollars)	2011		2010	2009

Interest on long-term debt	34		39	51
Interest on capital lease obligations	22		16	17
Short-term interest and other financial charges	(1	)	4	(4	)

	55		59	64

The Company's proportionate share of the interest payments by joint ventures was $31 million in 2011 (2010 – $42 million; 2009 – $41 million), net of interest capitalized on construction projects.

The Company's proportionate share of interest payments from the capital lease obligations of Bruce Power was $15 million in 2011 (2010 – $16 million; 2009 – $17 million).

122 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 15 JUNIOR SUBORDINATED NOTES

2011

2010

Outstanding loan amount
(millions of dollars)

Maturity
Date

Outstanding
December 31

Effective
Interest
Rate

Outstanding
December 31

Effective
Interest
Rate

TRANSCANADA PIPELINES LIMITED

U.S. dollars (2011 and 2010 – US$1,000)

2017

1,009

6.5%

985

6.5%

Junior Subordinated Notes of US$1.0 billion mature in 2067 and bear interest at 6.35 per cent per year until May 15, 2017, when interest will convert to a floating rate that is reset quarterly to the three-month London Interbank Offered Rate plus 221 basis points. The Company has the option to defer payment of interest for periods of up to 10 years without giving rise to a default and without permitting acceleration of payment under the terms of the Junior Subordinated Notes. However, the Company would be prohibited from paying dividends during any such deferral period. The Junior Subordinated Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and other obligations of TCPL. The Junior Subordinated Notes are callable at the Company's option at any time on or after May 15, 2017, at 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption. The Junior Subordinated Notes are callable earlier, in whole or in part, upon the occurrence of certain events and at the Company's option at an amount equal to the greater of 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption and an amount determined by a specified formula in accordance with the terms of the Junior Subordinated Notes.

NOTE 16 NON-CONTROLLING INTERESTS

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

December 31 (millions of dollars)	2011	2010

Non-controlling interest in TC PipeLines, LP⁽¹⁾	997	686
Non-controlling interest in Portland⁽²⁾	79	82

	1,076	768

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

Year ended December 31 (millions of dollars)	2011	2010	2009

Non-controlling interest in TC PipeLines, LP⁽¹⁾	101	87	66
Non-controlling interest in Portland⁽²⁾	6	6	8

	107	93	74

⁽¹⁾: Effective May 3, 2011, the non-controlling interest in TC PipeLines, LP increased from 61.8 per cent to 66.7 per cent due to the issuance of equity to non-controlling interests in TC PipeLines, LP associated with the sale of 25 per cent interests in GTN LLC and Bison LLC pipelines from TCPL to TC PipeLines, LP. The non-controlling interest in TC PipeLines, LP from November 18, 2009 to May 2, 2011 was 61.8 per cent, from July 1, 2009 to November 17, 2009 was 57.4 per cent, and from February 22, 2007 to June 30, 2009 was 67.9 per cent.
⁽²⁾: The non-controlling interests in Portland as at December 31, 2011 represented the 38.3 per cent interest not owned by TCPL (2010 and 2009 – 38.3 per cent).

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 123

NOTE 17 COMMON SHARES

		Number of Shares	Amount

		(thousands)	(millions of dollars)
Outstanding at January 1, 2009		597,890	8,973
	Issuance of common shares for cash	51,536	1,676

Outstanding at December 31, 2009		649,426	10,649
	Issuance of common shares for cash	26,121	987

Outstanding at December 31, 2010		675,547	11,636
	Issuance of common shares for cash	56,325	2,401

Outstanding at December 31, 2011		731,872	14,037

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares without par value.

Restriction on Dividends

Certain terms of the Company's preferred shares and debt instruments could restrict the Company's ability to declare dividends on preferred and common shares. At December 31, 2011, approximately $2.7 billion (2010 – $3.6 billion; 2009 – $2.6 billion) was available for the payment of dividends on common and preferred shares.

Cash Dividends

Cash dividends of $1.2 billion were paid in 2011 (2010 – $1.1 billion; 2009 – $976 million).

NOTE 18 PREFERRED SHARES

December 31	Number of Shares Authorized and Outstanding	Dividend Rate per Share	Redemption Price per Share	2011	2010

	(thousands)			(millions of dollars)	(millions of dollars)
Cumulative First Preferred Shares
Series U	4,000	$2.80	$50.00	195	195
Series Y	4,000	$2.80	$50.00	194	194

				389	389

The authorized number of preferred shares issuable in each series is unlimited. All of the cumulative first preferred shares are without par value.

On or after October 15, 2013, TCPL may redeem the Series U preferred shares at $50 per share, and on or after March 5, 2014, TCPL may redeem the Series Y preferred shares at $50 per share.

Dividend Reinvestment and Share Purchase Plan

124 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

dividend payment. The discount was set at three per cent in 2009 and 2010, and was reduced to two per cent commencing with the dividends declared in February 2011.

Cash Dividends

Cash dividends of $22 million or $2.80 per share were paid on the Series U and Series Y preferred shares in each of 2011, 2010 and 2009.

NOTE 19 ASSET RETIREMENT OBLIGATIONS

The scope and timing of asset retirements related to regulated oil and natural gas pipelines in the U.S. and hydroelectric power plants is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities. The Company has not recorded an amount for ARO related to the nuclear assets, as Bruce Power leases the assets and the lessor is responsible for decommissioning liabilities under the lease agreement.

Through its Land Matters Consultation Initiative, the NEB is addressing several significant issues relating to future pipeline abandonment costs for Canadian regulated pipelines. In its May 2009 decision, the NEB established several filing deadlines relating to the financial issues, including deadlines for preparing and filing an estimate of the abandonment costs to be used to begin collecting funds. TCPL filed its estimates of abandonment costs for its Canadian natural gas and oil pipelines on November 30, 2011, as required by the NEB decision. These estimates are expected to clarify the scope of ARO, however, the timing of retirements for these assets remains indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets.

ARO recognized in the Natural Gas Pipelines segment relates to non-regulated natural gas pipelines and regulated natural gas storage operations. The estimated undiscounted cash flows required to settle the ARO with respect to these operations were $63 million at December 31, 2011 (2010 – $62 million), calculated using an annual inflation rate ranging from 1.2 per cent to 4.0 per cent. The estimated fair value of this liability was $26 million at December 31, 2011 (2010 – $24 million) after discounting the estimated cash flows at rates ranging from 4.3 per cent to 11.0 per cent. At December 31, 2011, the expected timing of payment for settlement of the obligations ranged from 2012 to 2029.

ARO recognized in the Energy segment relates to certain power generation facilities and non-regulated natural gas storage facilities. The estimated undiscounted cash flows required to settle the ARO with respect to the Energy segment were $641 million at December 31, 2011 (2010 – $719 million), calculated using an annual inflation rate ranging from 2.0 per cent to 2.5 per cent. The estimated fair value of this liability was $43 million at December 31, 2011 (2010 – $42 million), after discounting the estimated cash flows at average rates ranging from 5.2 per cent to 6.8 per cent. During 2010, the economic life of certain Energy assets was extended after reviewing market trends and asset conditions. At December 31, 2011, the expected timing of payment for settlement of the obligations ranged from 2018 to 2061.

Reconciliation of Asset Retirement Obligations⁽¹⁾

(millions of dollars)	Natural Gas Pipelines		Energy		Total

Balance at January 1, 2010	24		87		111
New obligations and revisions in estimated cash flows	(1	)	(47	)	(48	)
Accretion expense	1		2		3

Balance at December 31, 2010	24		42		66
New obligations and revisions in estimated cash flows	–		(1	)	(1	)
Accretion expense	2		2		4

Balance at December 31, 2011	26		43		69

⁽¹⁾: At December 31, 2011, ARO totalling $68 million (2010 – $65 million) and $1 million (2010 – $1 million) were included in Deferred Amounts and Accounts Payable, respectively.

NOTE 20 EMPLOYEE FUTURE BENEFITS

The Company sponsors DB Plans that cover a significant majority of employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plans increase annually by a portion of the increase in the Consumer Price Index. Past service costs are amortized over the expected average remaining service life of employees, which is approximately eight years (2010 – eight years; 2009 – eight years).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 125

The Company also provides its employees with a Savings Plan in Canada, DC Plans consisting of 401(k) Plans in the U.S., and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Past service costs are amortized over the expected average remaining life expectancy of former employees, which was approximately 12 years at December 31, 2011. Contributions to the Savings Plan and DC Plans are expensed as incurred. In 2011, the Company expensed $23 million (2010 and 2009 – $21 million) for the Savings Plan and DC Plans.

Total cash payments for employee future benefits, consisting of cash contributed by the Company to the DB Plans and other benefit plans, was $93 million in 2011 (2010 – $127 million; 2009 – $168 million), including $23 million in 2011 (2010 and 2009 – $21 million) related to the Savings Plan and DC Plans. In addition to these cash payments, in 2011 the Company provided a $27 million letter of credit to the DB Plan.

The Company measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2012, and the next required valuation will be as at January 1, 2013.

	Pension Benefit Plans				Other Benefit Plans

December 31 (millions of dollars)	2011		2010		2011		2010

Change in Benefit Obligation
Benefit obligation – beginning of year	1,622		1,476		159		150
Current service cost	54		50		2		2
Interest cost	91		89		9		9
Employee contributions	4		4		1		1
Benefits paid	(71	)	(73	)	(9	)	(9	)
Actuarial loss	131		95		7		8
Transfers	–		(8	)	–		–
Foreign exchange rate changes	5		(11	)	1		(2	)

Benefit obligation – end of year	1,836		1,622		170		159

Change in Plan Assets
Plan assets at fair value – beginning of year	1,636		1,447		29		27
Actual return on plan assets	21		177		–		3
Employer contributions	62		98		8		8
Employee contributions	4		4		1		1
Benefits paid	(71	)	(73	)	(9	)	(9	)
Transfers	–		(8	)	–		–
Foreign exchange rate changes	4		(9	)	–		(1	)

Plan assets at fair value – end of year	1,656		1,636		29		29

Funded status – plan (deficit)/surplus	(180	)	14		(141	)	(130	)
Unamortized net actuarial loss	549		345		50		42
Unamortized past service costs	15		18		(3	)	(3	)

Accrued Benefit Asset/(Liability), Net of Valuation Allowance of Nil	384		377		(94	)	(91	)

The accrued benefit asset/(liability) net of valuation allowance of nil in the Company's Balance Sheet was as follows:

	Pension Benefit Plans				Other Benefit Plans

December 31 (millions of dollars)	2011		2010		2011		2010

Intangibles and Other Assets	399		380		–		–
Deferred Amounts	(15	)	(3	)	(94	)	(91	)

	384		377		(94	)	(91	)

126 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded:

	Pension Benefit Plans				Other Benefit Plans

December 31 (millions of dollars)	2011		2010		2011		2010

Benefit obligation	(1,836	)	(417	)	(170	)	(159	)
Plan assets at fair value	1,656		391		29		29

Funded Status – Plan Deficit	(180	)	(26	)	(141	)	(130	)

The Company's expected funding contributions in 2012 are approximately $119 million for the DB Plans and approximately $31 million for the other benefit plans, Savings Plan and DC Plans. In addition to these contributions, the Company expects to provide a $48 million letter of credit in 2012 to the DB Plan.

The following are estimated future benefit payments, which reflect expected future service:

(millions of dollars)	Pension Benefits	Other Benefits

2012	85	9
2013	90	9
2014	94	10
2015	99	10
2016	104	10
2017 to 2021	591	57

The rate used to discount pension and other post-employment benefit plan obligations was developed based on a yield curve of corporate AA bond yields at December 31, 2011. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-employment obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:

	Pension Benefit Plans		Other Benefit Plans

December 31	2011	2010	2011	2010

Discount rate	5.05%	5.55%	5.10%	5.65%
Rate of compensation increase	3.15%	3.20%

The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan cost were as follows:

	Pension Benefit Plans			Other Benefit Plans

Year ended December 31	2011	2010	2009	2011	2010	2009

Discount rate	5.55%	6.00%	6.65%	5.60%	6.00%	6.50%
Expected long-term rate of return on plan assets	6.95%	6.95%	6.95%	6.40%	7.80%	7.75%
Rate of compensation increase	3.10%	3.20%	3.25%

The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 127

An 8.50 per cent average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2019 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects:

(millions of dollars)	Increase	Decrease

Effect on total of service and interest cost components	1	(1	)
Effect on post-employment benefit obligation	15	(13	)

The Company's net benefit cost is as follows:

	Pension Benefit Plans						Other Benefit Plans

Year ended December 31 (millions of dollars)	2011		2010		2009		2011		2010		2009

Current service cost	54		50		45		2		2		2
Interest cost	91		89		89		9		9		9
Actual return on plan assets	(21	)	(177	)	(206	)	–		(3	)	(5	)
Actuarial loss	131		95		107		7		8		10

Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost	255		57		35		18		16		16
Difference between expected and actual return on plan assets	(93	)	68		107		(2	)	1		3
Difference between actuarial loss/(gain) recognized and actual actuarial loss/(gain) on accrued benefit obligation	(110	)	(86	)	(101	)	(5	)	(6	)	(8	)
Difference between amortization of past service costs and actual plan amendments	3		4		4		–		–		–
Amortization of transitional obligation related to regulated business	–		–		–		2		2		2

	55		43		45		13		13		13

The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:

	Percentage of Plan Assets		Target Allocations

Asset Category December 31	2011	2010	2011

Debt securities	39%	37%	35% to 60%
Equity securities	61%	63%	40% to 65%

	100%	100%

Debt securities included the Company's debt of $2 million (0.1 per cent of total plan assets) and $4 million (0.2 per cent of total plan assets) at December 31, 2011 and 2010, respectively. Equity securities included the Company's common shares of $3 million (0.2 per cent of total plan assets) and $3 million (0.2 per cent of total plan assets) at December 31, 2011 and 2010, respectively.

Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities, as well as alternative assets such as infrastructure, private equity and derivatives to diversify risk. Derivatives are not used for speculative purposes and the use of leveraged derivatives is prohibited.

All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted basis and by comparison to similar assets which are publicly traded.

128 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents plan assets for DB Plans and other post-employment benefits measured at fair value, which have been categorized into three categories based on a fair value hierarchy. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets. In Level II, determination of the fair value of assets includes valuations using inputs, other than quoted prices, for which all significant inputs are observable, directly or indirectly. This category includes fair value determined using valuation techniques, such as option pricing models and extrapolation using observable inputs. In Level III, determination of the fair value of assets is based on inputs that are not readily observable and are significant to the overall fair value measurement.

			Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio

Asset Category December 31 (millions of Canadian dollars)			2011	2010	2011	2010	2011	2010	2011	2010	2011	2010

Cash and cash equivalents			25	19	–	–	–	–	25	19	1%	1%
Equity Securities:
	Canadian		374	394	95	93	–	–	469	487	28%	29%
	U.S.		251	225	55	117	–	–	306	342	18%	21%
	International		25	31	231	199	–	–	256	230	15%	14%
Fixed Income Securities:
	Canadian Bonds:
		Federal	–	–	303	302	–	–	303	302	18%	18%
		Provincial	–	–	158	127	–	–	158	127	9%	8%
		Municipal	–	–	4	4	–	–	4	4	–	–
		Corporate	–	–	47	64	–	–	47	64	3%	4%
	U.S. Bonds:
		State	–	–	29	28	–	–	29	28	2%	2%
		Corporate	–	–	29	19	–	–	29	19	2%	1%
	International:
		Corporate	–	–	9	–	–	–	9	–	1%	–
		Mortgage Backed	–	–	30	22	–	–	30	22	2%	1%
Other Investments:
	Private Equity Funds		–	–	–	–	20	21	20	21	1%	1%

			675	669	990	975	20	21	1,685	1,665	100%	100%

The following table presents the net change in the Level III fair value category:

(millions of dollars, pre-tax)	Private Equity Funds

Balance at December 31, 2009	25
Realized and unrealized losses	(6	)
Purchases and sales	2

Balance at December 31, 2010	21
Realized and unrealized losses	(2	)
Purchases and sales	1

Balance at December 31, 2011	20

Employee Future Benefits of Joint Ventures
Certain of the Company's joint ventures sponsor DB Plans as well as post-employment benefits other than pensions, including defined life insurance and medical benefits beyond those provided by government-sponsored plans. The obligations of these plans are non-recourse to TCPL. The following amounts in this note, including those in the accompanying tables, represent TCPL's proportionate share with respect to these plans.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 129

Total cash payments for employee future benefits, consisting of cash contributed by the Company's joint ventures to DB Plans and other benefit plans was $59 million in 2011 (2010 – $58 million; 2009 – $54 million).

The Company's joint ventures measure the benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuations of the pension plans for funding purposes were as at January 1, 2012, and the next required valuations will be as at January 1, 2013.

	Pension Benefit Plans				Other Benefit Plans

December 31 (millions of dollars)	2011		2010		2011		2010

Change in Benefit Obligation
Benefit obligation – beginning of year	864		695		208		170
Current service cost	27		19		11		8
Interest cost	46		42		11		10
Employee contributions	8		7		–		–
Benefits paid	(33	)	(31	)	(4	)	(5	)
Actuarial loss	73		132		25		25

Benefit obligation – end of year	985		864		251		208

Change in Plan Assets
Plan assets at fair value – beginning of year	727		641		–		–
Actual return on plan assets	13		57		–		–
Employer contributions	53		53		6		5
Employee contributions	8		7		–		–
Benefits paid	(33	)	(31	)	(4	)	(5	)

Plan assets at fair value – end of year	768		727		2		–

Funded status – plan deficit	(217	)	(137	)	(249	)	(208	)
Unamortized net actuarial loss	317		230		71		49
Unamortized past service costs	–		–		2		2

Accrued Benefit Asset/(Liability), Net of Valuation Allowance of Nil	100		93		(176	)	(157	)

The accrued benefit asset/(liability), net of valuation allowance of nil in the Company's Balance Sheet was as follows:

	Pension Benefit Plans		Other Benefit Plans

December 31 (millions of dollars)	2011	2010	2011		2010

Intangibles and Other Assets	100	93	–		–
Deferred Amounts	–	–	(176	)	(157	)

	100	93	(176	)	(157	)

The following amounts were included in the above benefit obligation and fair value of plan assets for plans that are not fully funded:

	Pension Benefit Plans				Other Benefit Plans

December 31 (millions of dollars)	2011		2010		2011		2010

Benefit obligation	(979	)	(864	)	(251	)	(208	)
Plan assets at fair value	761		727		2		–

Funded Status – Plan Deficit	(218	)	(137	)	(249	)	(208	)

The expected total funding contributions of the Company's joint ventures in 2012 are approximately $73 million for the pension benefit plans and approximately $7 million for the other benefit plans.

130 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following are estimated future benefit payments, which reflect expected future service:

(millions of dollars)	Pension Benefits	Other Benefits

2012	37	7
2013	38	8
2014	40	8
2015	42	9
2016	44	10
2017 to 2021	310	60

The significant weighted average actuarial assumptions adopted in measuring the benefit obligations of the Company's joint ventures were as follows:

	Pension Benefit Plans		Other Benefit Plans

December 31	2011	2010	2011	2010

Discount rate	4.75%	5.25%	4.60%	5.10%
Rate of compensation increase	3.50%	3.50%

The significant weighted average actuarial assumptions adopted in measuring the net benefit plan costs of the Company's joint ventures were as follows:

	Pension Benefit Plans			Other Benefit Plans

Year ended December 31	2011	2010	2009	2011	2010	2009

Discount rate	5.25%	6.00%	6.75%	5.10%	5.80%	6.40%
Expected long-term rate of return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	3.50%	3.50%	3.50%

(millions of dollars)	Increase	Decrease

Effect on total of service and interest cost components	4	(3	)
Effect on post-employment benefit obligation	35	(28	)

The Company's proportionate share of net benefit cost of joint ventures is as follows:

	Pension Benefit Plans						Other Benefit Plans

Year ended December 31 (millions of dollars)	2011		2010		2009		2011		2010		2009

Current service cost	27		19		16		11		8		5
Interest cost	46		42		40		11		10		9
Actual return on plan assets	(13	)	(57	)	(63	)	–		–		–
Actuarial loss/(gain)	73		132		68		25		25		27

Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost	133		136		61		47		43		41
Difference between expected and actual return on plan assets	(38	)	12		25		–		–		–
Difference between actuarial loss/(gain) recognized and actual actuarial loss/(gain) on accrued benefit obligation	(62	)	(128	)	(67	)	(22	)	(24	)	(28	)

	33		20		19		25		19		13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 131

The weighted average asset allocations and target allocations by asset category in the pension plans of the Company's joint ventures were as follows:

Asset Category	Percentage of Plan Assets		Target Allocations

December 31	2011	2010	2011

Debt securities	45%	41%	40%
Equity securities	55%	59%	60%

	100%	100%

Debt securities included the Company's debt of $1 million (0.2 per cent of total plan assets) and $1 million (0.2 per cent of total plan assets) at December 31, 2011 and 2010, respectively. Equity securities included the Company's common shares of $4 million (0.6 per cent of total plan assets) and $4 million (0.5 per cent of total plan assets) at December 31, 2011 and 2010, respectively.

The assets of the joint ventures' pension plans are managed on a going concern basis subject to legislative restrictions. The plans' investment policies are to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plans' participants.

NOTE 21 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

Market Risk

•: Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TCPL enters into foreign exchange and commodity forwards and futures to mitigate the impact of volatility in foreign exchange rates and commodity prices.
•: Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices.
•: Options – contractual agreements to convey the right, but not the obligation, of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices.

132 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Commodity Price Risk

•: Subject to its overall risk management strategy, the Company commits a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to mitigate operational and price risks in its asset portfolio.
•: The Company purchases a portion of the natural gas required for its power plants or enters into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin.
•: The Company's power sales commitments are fulfilled through power generation or purchased through contracts, thereby reducing the Company's exposure to fluctuating commodity prices.
•: The Company enters into offsetting or back-to-back positions using derivative financial instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.

Natural Gas Storage Commodity Price Risk

Foreign Exchange and Interest Rate Risk

Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates.

TCPL has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk.

Net Investment in Self-Sustaining Foreign Operations

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 133

The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows:

2011

2010

Asset/(Liability)
December 31 (millions of dollars)

Fair Value⁽¹⁾

Notional or Principal Amount

Fair Value⁽¹⁾

Notional or Principal Amount

U.S. dollar cross-currency swaps
(maturing 2012 to 2018)

US 3,850

179

US 2,800

U.S. dollar forward foreign exchange contracts (maturing 2012)

(4)

US 725

US 100

US 4,575

181

US 2,900

⁽¹⁾: Fair values equal carrying values.

VaR Analysis

TCPL's estimation of VaR includes wholly owned subsidiaries and incorporates relevant risks associated with each market or business unit. The calculation does not include the regulated natural gas pipelines, as the nature of the rate-regulated pipeline business reduces the impact of market risks. TCPL's Board of Directors has established a VaR limit, which is monitored on an ongoing basis as part of the Company's risk management policy. TCPL's consolidated VaR was $12 million at December 31, 2011 (2010 – $12 million).

Counterparty Credit Risk

134 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and permitted under contractual terms. As part of its ongoing operations, TCPL must balance its market and counterparty credit risks when making business decisions.

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

Liquidity Risk

At December 31, 2011, the Company had unutilized committed revolving bank lines of US$1.0 billion, US$1.0 billion, US$300 million and $2.0 billion maturing in October 2012, November 2012, February 2013 and October 2016, respectively. The Company has also maintained continuous access to the Canadian commercial paper market on competitive terms and recently initiated a commercial paper program in the U.S.

Capital Management

The total capital managed by the Company was as follows:

December 31 (millions of dollars)	2011		2010

Notes payable	1,863		2,081
Due (from)/to TransCanada Corporation, net	(750	)	1,340
Long-term debt	18,567		17,922
Junior subordinated notes	1,009		985
Cash and cash equivalents	(630	)	(648	)

Net Debt	20,059		21,680

Equity attributable to non-controlling interests	1,076		768
Equity attributable to controlling interests	18,462		15,747

Total Equity	19,538		16,515

	39,597		38,195

Fair Values

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 135

Non-Derivative Financial Instruments Summary

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

	2011		2010

December 31 (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value

Financial Assets⁽¹⁾
Cash and cash equivalents	740	740	752	752
Accounts receivable and other⁽²⁾⁽³⁾	1,595	1,639	1,564	1,604
Due from TransCanada Corporation	750	750	1,363	1,363
Available for sale assets⁽²⁾	23	23	20	20

	3,108	3,152	3,699	3,739

Financial Liabilities⁽¹⁾⁽³⁾
Notes payable	1,880	1,880	2,092	2,092
Accounts payable and deferred amounts⁽⁴⁾	1,536	1,536	1,444	1,444
Due to TransCanada Corporation	–	–	2,703	2,703
Accrued interest	375	375	361	361
Long-term debt	18,567	23,757	17,922	21,523
Junior subordinated notes	1,009	1,027	985	992
Long-term debt of joint ventures	822	940	866	971

	24,189	29,515	26,373	30,086

⁽¹⁾: Consolidated Net Income in 2011 included losses of $13 million (2010 – losses of $8 million) for fair value adjustments related to interest rate swap agreements on US$350 million (2010 – US$250 million) of Long-Term Debt. There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.
⁽²⁾: At December 31, 2011, the Consolidated Balance Sheet included financial assets of $1,284 million (2010 – $1,280 million) in Accounts Receivable, $41 million (2010 – $40 million) in Other Current Assets and $293 million (2010 – $264 million) in Intangibles and Other Assets.
⁽³⁾: Recorded at amortized cost, except for $350 million (2010 – $250 million) of Long-Term Debt that is adjusted to fair value.
⁽⁴⁾: At December 31, 2011, the Consolidated Balance Sheet included financial liabilities of $1,494 million (2010 – $1,414 million) in Accounts Payable and $42 million (2010 – $30 million) in Deferred Amounts.

The following tables detail the remaining contractual maturities for TCPL's non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2011:

Contractual Repayments of Financial Liabilities⁽¹⁾

	Payments Due by Period

(millions of dollars)	Total	2012	2013 and 2014	2015 and 2016	2017 and Thereafter

Notes payable	1,880	1,880	–	–	–
Long-term debt	18,567	935	1,874	2,311	13,447
Junior subordinated notes	1,009	–	–	–	1,009
Long-term debt of joint ventures	822	33	94	213	482

	22,278	2,848	1,968	2,524	14,938

⁽¹⁾: The anticipated timing of settlement of derivative contracts is presented in the Derivatives Financial Instrument Summary in this note.

136 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Interest Payments on Financial Liabilities

	Payments Due by Period

(millions of dollars)	Total	2012	2013 and 2014	2015 and 2016	2017 and Thereafter

Long-term debt	16,541	1,180	2,227	1,989	11,145
Junior subordinated notes	355	65	129	129	32
Long-term debt of joint ventures	343	48	89	77	129

	17,239	1,293	2,445	2,195	11,306

Derivative Financial Instruments Summary

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

			2011

December 31 (all amounts in millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest

Derivative Financial Instruments Held for Trading⁽¹⁾
Fair Values⁽²⁾
	Assets		$213		$176		$3		$22
	Liabilities		$(212	)	$(212	)	$(14	)	$(22	)
Notional Values
	Volumes⁽³⁾
		Purchases	23,500		103		–		–
		Sales	23,158		82		–		–
	Canadian dollars		–		–		–		684
	U.S. dollars		–		–		US 1,269		US 250
	Cross-currency		–		–		47/US 37		–
Net unrealized (losses)/gains in the year⁽⁴⁾			$(3	)	$(50	)	$(4	)	$1
Net realized gains/(losses) in the year⁽⁴⁾			$58		$(74	)	$10		$10
Maturity dates			2012-2018		2012-2016		2012		2012-2016
Derivative Financial Instruments in Hedging Relationships⁽⁵⁾⁽⁶⁾
Fair Values⁽²⁾
	Assets		$42		$3		$–		$13
	Liabilities		$(277	)	$(22	)	$(38	)	$(1	)
Notional Values
	Volumes⁽³⁾
		Purchases	17,188		8		–		–
		Sales	9,217		–		–		–
	U.S. dollars		–		–		US 91		US 600
	Cross-currency		–		–		136/US 100		–
Net realized losses in the year⁽⁴⁾			$(150	)	$(17	)	$–		$(16	)
Maturity dates			2012-2017		2012-2013		2012-2014		2012-2015

⁽¹⁾: All derivative financial instruments in the held for trading classification have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
⁽²⁾: Fair values equal carrying values.
⁽³⁾: Volumes for power and natural gas derivatives are in GWh and billion cubic feet (Bcf), respectively.
⁽⁴⁾: Realized and unrealized gains and losses on held for trading derivative financial instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.
⁽⁵⁾: All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $13 million and a notional amount of US$350 million. In 2011, net realized gains on fair value hedges were $7 million and were included in Interest Expense. In 2011, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.
⁽⁶⁾: In 2011, Net Income included losses of $3 million for changes in the fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. In 2011, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur. No amounts have been excluded from the assessment of hedge effectiveness.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 137

(millions of dollars)		Total		2012		2013 and 2014		2015 and 2016		2017 and Thereafter

Derivative financial instruments held for trading
	Assets	414		282		123		9		–
	Liabilities	(460	)	(292	)	(151	)	(17	)	–
Derivative financial instruments in hedging relationships
	Assets	217		121		91		5		–
	Liabilities	(408	)	(208	)	(135	)	(50	)	(15	)

		(237	)	(97	)	(72	)	(53	)	(15	)

Derivative Financial Instruments Summary

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

			2010

December 31 (all amounts in millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest

Derivative Financial Instruments Held for Trading⁽¹⁾
Fair Values⁽²⁾
	Assets		$169		$144		$8		$20
	Liabilities		$(129	)	$(173	)	$(14	)	$(21	)
Notional Values
	Volumes⁽³⁾
		Purchases	15,610		158		–		–
		Sales	18,114		96		–		–
	Canadian dollars		–		–		–		736
	U.S. dollars		–		–		US 1,479		US 250
	Cross-currency		–		–		47/US 37		–
Net unrealized (losses)/gains in the year⁽⁴⁾			$(32	)	$27		$4		$43
Net realized gains/(losses) in the year⁽⁴⁾			$77		$(42	)	$36		$(74	)
Maturity dates			2011-2015		2011-2015		2011-2012		2011-2016
Derivative Financial Instruments in Hedging Relationships⁽⁵⁾⁽⁶⁾
Fair Values⁽²⁾
	Assets		$112		$5		$–		$8
	Liabilities		$(186	)	$(19	)	$(51	)	$(26	)
Notional Values
	Volumes⁽³⁾
		Purchases	16,071		17		–		–
		Sales	10,498		–		–		–
	U.S. dollars		–		–		US 120		US 1,125
	Cross-currency		–		–		136/US 100		–
Net realized losses in the year⁽⁴⁾			$(9	)	$(35	)	$–		$(33	)
Maturity dates			2011-2015		2011-2013		2011-2014		2011-2015

⁽¹⁾: All derivative financial instruments in the held-for-trading classification have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
⁽²⁾: Fair values equal carrying values.
⁽³⁾: Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.
⁽⁴⁾: Realized and unrealized gains and losses on held-for-trading derivative financial instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial

138 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

⁽⁵⁾: All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $8 million and a notional amount of US$250 million. In 2010, net realized gains on fair value hedges were $4 million and were included in Interest Expense. In 2010, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.
⁽⁶⁾: In 2010, Net Income included a gain of $1 million for changes in the fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. In 2010, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur. No amounts have been excluded from the assessment of hedge effectiveness.

Balance Sheet Presentation of Derivative Financial Instruments

The fair value of the derivative financial instruments in the Company's Balance Sheet was as follows:

December 31 (millions of dollars)	2011		2010

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

Derivative Financial Instruments of Joint Ventures

Included in the Derivative Financial Instruments Summary tables are amounts related to power derivatives used by one of the Company's joint ventures to manage commodity price risk. The Company's proportionate share of the fair value of these power derivatives was $35 million at December 31, 2011 (2010 – $48 million). These contracts mature from 2012 to 2018. The Company's proportionate share of the notional sales volumes of power associated with this exposure was 2,979 gigawatt hours (GWh) at December 31, 2011 (2010 – 3,772 GWh). The Company's proportionate share of the notional purchased volumes of power associated with this exposure was 1,595 GWh at December 31, 2011 (2010 – 2,322 GWh).

Derivatives in Cash Flow Hedging Relationships

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

	Cash Flow Hedges

	Power				Natural Gas				Foreign Exchange		Interest

Year ended December 31 (millions of Canadian dollars, pre-tax)	2011		2010		2011		2010		2011	2010	2011		2010

Change in fair value of derivative instruments recognized in OCI (effective portion)	(252	)	(79	)	(59	)	(26	)	5	10	(1	)	(137	)
Reclassification of gains and losses on derivative instruments from AOCI to Net Income (effective portion)	61		(7	)	100		(21	)	–	–	43		32

Credit Risk Related Contingent Features

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 139

Fair Value Hierarchy

		Quoted Prices in Active Markets (Level I)				Significant Other Observable Inputs (Level II)				Significant Unobservable Inputs (Level III)				Total

December 31 (millions of dollars, pre-tax)		2011		2010		2011		2010		2011		2010		2011		2010

Natural Gas Inventory		–		–		29		49		–		–		29		49
Derivative Financial Instrument Assets:
	Interest rate contracts	–		–		35		28		–		–		35		28
	Foreign exchange contracts	11		10		131		179		–		–		142		189
	Power commodity contracts	–		–		244		269		2		5		246		274
	Gas commodity contracts	124		93		55		56		–		–		179		149
Derivative Financial Instrument Liabilities:
	Interest rate contracts	–		–		(23	)	(47	)	–		–		(23	)	(47	)
	Foreign exchange contracts	(13	)	(11	)	(89	)	(54	)	–		–		(102	)	(65	)
	Power commodity contracts	–		–		(465	)	(299	)	(15	)	(8	)	(480	)	(307	)
	Gas commodity contracts	(208	)	(178	)	(26	)	(15	)	–		–		(234	)	(193	)
Non-Derivative Financial Instruments:
	Available-for-sale assets	23		20		–		–		–		–		23		20

		(63	)	(66	)	(109	)	166		(13	)	(3	)	(185	)	97

The following table presents the net change in the Level III fair value category:

(millions of dollars, pre-tax)	Derivatives⁽¹⁾

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

Balance at December 31, 2010	(3	)
New contracts⁽²⁾	1
Settlements	1
Transfers out of Level III⁽³⁾⁽⁴⁾	(1	)
Change in unrealized gains recorded in Net Income	1
Change in fair value of derivative instruments recorded in OCI	(12	)

Balance at December 31, 2011	(13	)

⁽¹⁾: The fair value of derivative assets and liabilities is presented on a net basis.
⁽²⁾: At December 31, 2011, the total amount of net gains included in Net Income attributable to derivatives that were entered into during the year and still held at the reporting date was nil (2010 – $1 million).

140 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

⁽³⁾: Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable.
⁽⁴⁾: As contracts near maturity, they are transferred out of Level III and into Level II.

NOTE 22 CHANGES IN OPERATING WORKING CAPITAL

Year ended December 31 (millions of dollars)	2011		2010		2009

(Increase)/decrease in accounts receivable	(15	)	(312	)	315
Decrease/(increase) in inventories	27		70		(19	)
Increase in other current assets	(21	)	(87	)	(249	)
Increase/(decrease) in accounts payable	274		92		(153	)
Increase/(decrease) in accrued interest	17		(19	)	18

Decrease/(Increase) in Operating Working Capital	282		(256	)	(88	)

NOTE 23 ACQUISITIONS AND DISPOSITIONS

Natural Gas Pipelines

TC PipeLines, LP

On May 3, 2011, TCPL completed the sale of a 25 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an aggregate purchase price of US$605 million which included US$81 million of long-term debt, or 25 per cent of GTN LLC's outstanding debt. GTN LLC and Bison LLC own the GTN and Bison natural gas pipelines, respectively.

On May 3, 2011, TC PipeLines, LP completed an underwritten public offering of 7,245,000 common units, including 945,000 common units purchased by the underwriters upon full exercise of an over-allotment option, at US$47.58 per unit. Net proceeds of approximately US$331 million from this offering were used to partially fund the acquisition. The acquisition was also funded by draws of US$61 million on TC PipeLines, LP's bridge loan facility and US$125 million on its US$250 million senior revolving credit facility.

As part of this offering, TCPL made a capital contribution of approximately US$7 million to maintain its two per cent general partnership interest in TC PipeLines, LP and did not purchase any other units. As a result of the common units offering, TCPL's ownership in TC PipeLines, LP decreased from 38.2 per cent to 33.3 per cent and an after-tax dilution gain of $30 million ($50 million pre-tax) was recorded in Contributed Surplus.

In November 2009, TC PipeLines, LP completed an offering of five million common units at a price of US$38.00 per unit, resulting in net proceeds to TC PipeLines, LP of US$182 million. TCPL contributed an additional US$3.8 million to maintain its general partnership interest but did not purchase any other units. Upon completion of this offering, the Company's ownership interest in TC PipeLines, LP decreased to 38.2 per cent and the Company recognized an after-tax dilution gain of $18 million ($29 million pre-tax) in income.

In July 2009, TCPL sold North Baja to TC PipeLines, LP. As part of the transaction, the Company agreed to amend its general partner incentive distribution rights arrangement with TC PipeLines, LP. TCPL received aggregate consideration totalling approximately US$395 million from TC PipeLines, LP, including US$200 million in cash and 6,371,680 common units of TC PipeLines, LP. As a result of this transaction, TCPL recorded no gain or loss and its ownership in TC PipeLines, LP increased to 42.6 per cent. The Company's increased ownership in TC PipeLines, LP also resulted in a decrease in Non-Controlling Interests and an increase in Contributed Surplus.

Oil Pipelines

Keystone

In August 2009, TCPL purchased the remaining ownership interest in Keystone of approximately 20 per cent for US$553 million plus the assumption of US$197 million of short-term debt. The acquisition increased the Company's ownership interest in Keystone to 100 per cent and was recorded in Plant, Property and Equipment. TCPL began fully consolidating Keystone upon this acquisition.

In 2009, prior to August, TCPL funded $1.3 billion of cash calls for Keystone, resulting in the Company acquiring an increase in ownership from 62 per cent to 80 per cent for $313 million. The Company proportionately consolidated the Keystone partnerships prior to August 2009.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 141

NOTE 24 COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

Operating Leases

Future annual payments, net of sub-lease receipts, under the Company's operating leases for various premises, services and equipment are approximately as follows:

Year ended December 31 (millions of dollars)	Minimum Lease Payments	Amounts Recoverable under Sub-leases		Net Payments

2012	87	(8	)	79
2013	85	(7	)	78
2014	81	(7	)	74
2015	76	(5	)	71
2016	75	(3	)	72
2017 and thereafter	363	(2	)	361

	767	(32	)	735

The operating lease agreements for premises, services and equipment expire at various dates through 2052, with an option to renew certain lease agreements for periods of one year to 10 years. Net rental expense on operating leases in 2011 was $79 million (2010 – $80 million; 2009 – $64 million).

TCPL's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Future payments under these PPAs have been excluded from operating leases in the above table, as these payments are dependent upon plant availability and other factors. TCPL's share of payments under the PPAs in 2011 was $394 million (2010 – $363 million; 2009 – $384 million). The generating capacities and expiry dates of the PPAs are as follows:

	Megawatts	Expiry Date

Sundance A	560	December 31, 2017
Sundance B	353	December 31, 2020
Sheerness	756	December 31, 2020

Other Commitments

At December 31, 2011, TCPL was committed to Natural Gas Pipelines capital expenditures totalling approximately $250 million, primarily related to construction costs of the Alberta System and Guadalajara.

At December 31, 2011, the Company was committed to Oil Pipelines capital expenditures totalling approximately $992 million, primarily related to construction costs of Keystone XL.

At December 31, 2011, the Company was committed to Energy capital expenditures totalling approximately $290 million and includes TCPL's share of capital costs of Bruce Power and Cartier Wind.

On December 15, 2011, TCPL agreed to purchase nine Ontario solar projects from Canadian Solar Solutions Inc., with a combined capacity of 86 MW, for approximately $470 million. Under the terms of the agreement, each of the nine solar projects will be developed and constructed by Canadian Solar Solutions Inc. using photovoltaic panels. TCPL will purchase each project once construction and acceptance testing have been completed and operations have begun under 20-year PPAs with the Ontario Power Authority (OPA) under the Feed-in Tariff program in Ontario. TCPL anticipates the projects will be placed in service between late 2012 and mid-2013, subject to regulatory approvals.

142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Contingencies

TCPL and its subsidiaries are subject to various legal proceedings, arbitrations, and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.

Sundance A PPA

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

Guarantees

TCPL and its joint venture partners on Bruce Power, Cameco Corporation and BPC Generation Infrastructure Trust (BPC), have severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, a lease agreement and contractor services. The guarantees have terms ranging from 2018 to perpetuity. In addition, TCPL and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the OPA to refurbish and restart Bruce A power generation units. The guarantees have terms ending in 2018 and 2019. TCPL's share of the potential exposure under these Bruce A and Bruce B guarantees was estimated to be $863 million at December 31, 2011. The fair value of these Bruce Power guarantees at December 31, 2011 is estimated to be $29 million. The Company's exposure under certain of these guarantees is unlimited.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 143

NOTE 25 UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING

As previously discussed in Note 3, TCPL will be adopting U.S. GAAP effective January 1, 2012. The consolidated financial statements have been prepared in accordance with CGAAP which in some respects, differ from U.S. GAAP. The effects of significant differences between CGAAP and U.S. GAAP are described in this note.

Reconciliation of Net Income and Comprehensive Income to U.S. GAAP

Year ended December 31 (millions of dollars)		2011		2010		2009

Net Income – CGAAP		1,633		1,349		1,453
U.S. GAAP adjustments:
	Unrealized loss/(gain) on natural gas inventory held in storage⁽¹⁾	4		15		(3	)
	Tax impact of unrealized loss/(gain) on natural gas inventory held in storage	(1	)	(5	)	1
	Dilution gain⁽²⁾	–		–		(29	)
	Tax impact of dilution gain	–		–		11
	Tax recovery due to a change in tax legislation substantively enacted in Canada⁽⁴⁾	(4	)	(4	)	–

Net Income – U.S. GAAP		1,632		1,355		1,433
	Less: Net Income Attributable to Non-Controlling Interests	(107	)	(93	)	(74	)

Net Income Attributable to Controlling Interests – U.S. GAAP		1,525		1,262		1,359
	Less: Preferred Share Dividends	(22	)	(22	)	(22	)

Net Income Attributable to Common Shareholders – U.S. GAAP		1,503		1,240		1,337

Other Comprehensive Loss – CGAAP		(36	)	(239	)	(153	)
U.S. GAAP adjustments:
	Change in funded status of post-retirement plan liability⁽³⁾	(106	)	(11	)	7
	Tax impact of change in funded status of post-retirement plan liability	27		4		(2	)
	Change in funded status of post-retirement plan liability of equity investment	(80	)	(119	)	(48	)

Other Comprehensive Loss – U.S. GAAP		(195	)	(365	)	(196	)
	Less: Other Comprehensive Income Attributable to Non-Controlling Interests	(11	)	(6	)	(7	)

Other Comprehensive Loss Attributable to Controlling Interests – U.S. GAAP		(206	)	(371	)	(203	)

Comprehensive Income Attributable to Common Shares – U.S. GAAP		1,297		869		1,134

Information Prepared in Accordance with U.S. GAAP

The differences between CGAAP and the following information prepared in accordance with U.S. GAAP relates principally to the accounting for joint venture investments. Under CGAAP, the Company accounts for joint venture investments using the proportionate consolidation basis of accounting whereby the Company's proportionate share of assets, liabilities, revenues, expenses and cash flows are included in the Company's financial statements. U.S. GAAP requires that these joint venture investments be recorded on an equity basis of accounting. Information on the balances that have been proportionately consolidated under CGAAP is included in Note 8 to these financial statements. The effects of any additional differences between CGAAP and U.S. GAAP are described in the footnotes below.

144 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidated Statement of Income – U.S. GAAP

Year ended December 31 (millions of dollars)		2011		2010		2009

Revenues⁽¹⁾		7,694		6,634		6,778
Income from Equity Investments		415		453		478
Operating and Other Expenses
	Plant operating costs and other⁽²⁾	2,768		2,434		2,621
	Commodity purchases resold	846		960		772
	Depreciation and amortization	1,328		1,160		1,201
	Valuation provision for MGP	–		146		–

		4,942		4,700		4,594

Financial Charges/(Income)
	Interest expense	1,044		754		986
	Interest income and other	(55	)	(94	)	(116	)

		989		660		870

Income before Income Taxes		2,178		1,727		1,792

Income Taxes Expenses/(Recovery)
	Current⁽²⁾⁽⁴⁾	194		(140	)	15
	Deferred⁽¹⁾	352		512		344

		546		372		359

Net Income – U.S. GAAP		1,632		1,355		1,433
Net Income Attributable to Non-Controlling Interests		107		93		74

Net Income Attributable to Controlling Interests – U.S. GAAP		1,525		1,262		1,359
Preferred Share Dividends		22		22		22

Net Income Attributable to Common Shares – U.S. GAAP		1,503		1,240		1,337

Consolidated Statement of Comprehensive Income – U.S. GAAP

Year ended December 31 (millions of dollars)	2011		2010		2009

Net Income – U.S. GAAP	1,632		1,355		1,433

Other Comprehensive Income/(Loss), Net of Income Taxes
Change in foreign currency translation gains and losses on investments in foreign operations⁽⁸⁾	113		(180	)	(471	)
Change in fair value of derivative instruments to hedge the net investments in foreign operations⁽⁹⁾	(73	)	89		258
Change in fair value of derivative instruments designated as cash flow hedges⁽¹⁰⁾	(212	)	(169	)	(29	)
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges⁽¹¹⁾	147		53		71
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans^(3)(12)	(89	)	(12	)	(1	)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans^(3)(13)	10		5		6
Other Comprehensive Loss on equity investments⁽¹⁴⁾	(91	)	(151	)	(30	)

Other Comprehensive Loss – U.S. GAAP	(195	)	(365	)	(196	)

Comprehensive Income – U.S. GAAP	1,437		990		1,237
Comprehensive Income Attributable to Non-Controlling Interests	118		99		81

Comprehensive Income Attributable to Controlling Interests – U.S. GAAP	1,319		891		1,156
Preferred Share Dividends	22		22		22

Comprehensive Income Attributable to Common Shares – U.S. GAAP	1,297		869		1,134

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 145

Condensed Consolidated Balance Sheet – U.S. GAAP

As at December 31 (millions of dollars)		2011		2010

Assets
Current Assets⁽¹⁾		3,844		4,146
Plant, Property and Equipment⁽⁷⁾		32,467		30,987
Equity Investments^(3)(5)(6)		5,077		4,683
Goodwill		3,534		3,457
Regulatory Assets⁽³⁾		1,684		1,699
Intangibles and Other Assets⁽³⁾⁽⁶⁾		1,460		1,609

		48,066		46,581

Liabilities
Current Liabilities⁽⁴⁾⁽⁷⁾		5,501		5,350
Due to TransCanada Corporation		–		2,703
Regulatory Liabilities		297		308
Deferred Amounts⁽³⁾⁽⁵⁾		929		728
Deferred Income Tax Liabilities^(1)(3)(6)		3,591		3,241
Long-Term Debt⁽⁶⁾		17,724		17,122
Junior Subordinated Notes⁽⁶⁾		1,016		993

		29,058		30,445

Equity
Common shares, no par value		14,037		11,636
	Issued and outstanding: 2011 – 732 million shares
	Issued and outstanding: 2010 – 676 million shares
Preferred shares		389		389
Additional paid-in capital⁽²⁾		394		359
Retained earnings^(1)(2)(4)		4,561		4,227
Accumulated other comprehensive (loss)/income⁽³⁾		(1,449	)	(1,243	)

Equity Attributable to Controlling Interests		17,932		15,368
Equity Attributable to Non-Controlling Interests		1,076		768

		19,008		16,136

		48,066		46,581

Consolidated Statement of Accumulated Other Comprehensive (Loss)/Income – U.S. GAAP

Year ended December 31 (millions of dollars)	2011		2010		2009

Balance at beginning of year	(1,243	)	(872	)	(669	)
Change in foreign currency translation gains and losses on investments in foreign operations⁽⁸⁾	113		(180	)	(471	)
Change in fair value of derivative instruments to hedge the net investments in foreign operations⁽⁹⁾	(73	)	89		258
Change in fair value of derivative instruments designated as cash flow hedges⁽¹⁰⁾	(213	)	(165	)	(27	)
Reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges⁽¹¹⁾	137		43		62
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans^(3)(12)	(89	)	(12	)	(1	)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans^(3)(13)	10		5		6
Other Comprehensive Loss on equity investments⁽¹⁴⁾	(91	)	(151	)	(30	)

Balance at end of year	(1,449	)	(1,243	)	(872	)

146 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidated Statement of Cash Flows – U.S. GAAP

Year ended December 31 (millions of dollars)	2011		2010		2009

Net cash provided by operations	3,640		2,817		2,974
Net cash used in investing activities	(3,127	)	(5,296	)	(7,324	)
Net cash (used in)/provided by financing activities	(536	)	2,253		4,205
Effect of foreign exchange rate changes on cash and cash equivalents	4		(7	)	(93	)

Decrease in cash and cash equivalents	(19	)	(233	)	(238	)
Cash and cash equivalents beginning of year	648		881		1,119

Cash and cash equivalents end of year	629		648		881

⁽¹⁾: Under U.S. GAAP, inventory is recorded at lower of cost or market. Under CGAAP, natural gas inventory held in storage is recorded at its fair value.
⁽²⁾: Under U.S. GAAP, the dilution gain resulting from TC PipeLines, LP's 2009 equity issuance was accounted for as an equity transaction. Under CGAAP, the dilution gain was included in Net Income.
⁽³⁾: Under U.S. GAAP, an employer is required to recognize the overfunded or underfunded status of a defined benefit post-retirement plan as an asset or liability in its Consolidated Balance Sheet and to recognize changes in that funded status, through OCI, in the year in which the changes occur. The amounts recognized in the Company's U.S. GAAP Consolidated Balance Sheet for its DB Plans and other post-retirement benefits are as follows:

December 31 (millions of dollars)	2011		2010

Intangibles and other assets	–		40
Deferred amounts	(321	)	(156	)

	(321	)	(116	)

Pre-tax amounts recognized in U.S. GAAP AOCI are as follows:

	2011		2010		2009

December 31 (millions of dollars)	Pension Benefits	Other Benefits	Pension Benefits	Other Benefits	Pension Benefits	Other Benefits

Net loss	283	29	179	24	170	21
Prior service cost	7	2	9	2	10	2

	290	31	188	26	180	23

Pre-tax amounts recognized in U.S. GAAP OCI were as follows:

	2011				2010				2009

December 31 (millions of dollars)	Pension Benefits		Other Benefits		Pension Benefits		Other Benefits		Pension Benefits		Other Benefits

Amortization of net loss from AOCI to OCI	(10	)	(1	)	(5	)	(1	)	(5	)	(1	)
Amortization of prior service (credit) from AOCI to OCI	(2	)	–		(2	)	–		(2	)	–
Funded status adjustment	113		6		15		4		2		(1	)

	101		5		8		3		(5	)	(2	)

The funded status based on the accumulated benefit obligation for all DB Plans is as follows:

December 31 (millions of dollars)	2011		2010

Accumulated benefit obligation	1,691		1,463
Fair value of plan assets	1,656		1,636

Funded status – (deficit)/surplus	(35	)	173

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 147

Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded.

December 31 (millions of dollars)	2011		2010

Accumulated benefit obligation	446		182
Fair value of plan assets	391		178

Funded status – (deficit)	(55	)	(4	)

The estimated net loss and prior service cost for the DB Plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $10 million and $1 million, respectively. The estimated net loss and prior service cost for the other post-retirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year is $1 million and $1 million, respectively.

⁽⁴⁾: In accordance with CGAAP, the Company recorded current income tax benefits resulting from substantively enacted Canadian federal income tax legislation. Under U.S. GAAP, the legislation must be fully enacted for income tax adjustments to be recorded.

Below is the reconciliation of the annual changes in the total unrecognized tax benefit:

December 31 (millions of dollars)	2011		2010

Unrecognized tax benefits at beginning of year	58		52
Gross increases – tax positions in prior years	9		7
Gross decreases – tax positions in prior years	(7	)	(1	)
Gross increases – current year positions	11		8
Settlements	–		(7	)
Lapses of statute of limitations	(23	)	(1	)

Unrecognized tax benefits at end of year	48		58

TCPL expects the enactment of certain Canadian federal tax legislation in the next 12 months which is expected to result in a favourable income tax adjustment of approximately $20 million. Otherwise, subject to the results of audit examinations by taxing authorities and other legislative amendments, TCPL does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its financial statements.

TCPL and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2006. Substantially all material U.S. federal income tax matters have been concluded for years through 2007 and U.S. state and local income tax matters through 2006.

TCPL continuing practice is to recognize interest and penalties related to income tax uncertainties in Income Tax Expense. Net tax expense for the year ended December 31, 2011 reflects a reversal of $12 million of interest expense and nil for penalties (2010 – $3 million for interest expense and nil for penalties; 2009 – $8 million reversal of interest expense and nil for penalties). At December 31, 2011, the Company had $7 million accrued for interest expense and nil accrued for penalties (December 31, 2010 – $19 million accrued for interest expense and nil accrued for penalties).

⁽⁵⁾: As a consequence of using equity accounting for certain of these joint ventures under U.S. GAAP, the Company is required to reflect an additional liability of $111 million at December 31, 2011 (December 31, 2010 – $150 million) for certain guarantees related to debt and other performance commitments of the joint venture operations that were not required to be recorded when the underlying liability was reflected on the balance sheet under the proportionate consolidation method of accounting.

U.S. GAAP requires the disclosure of the difference, if any, between the carrying value of the investment and the investor's underlying equity in the net assets of the investee on an ongoing basis, rather than only at the date of purchase as required under CGAAP. At December 31, 2011, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company and Bruce Power is US$120 million (2010 – US$121 million) and $752 million (2010 – $783 million), respectively. This difference is primarily due to goodwill recorded with respect to the acquisition of Northern Border and the fair value assessment of assets at the time of acquisition of Bruce Power.

The distributed earnings from long-term investments for the year ended December 31, 2011 were $494 million (2010 – $250 million; 2009 – $265 million). The undistributed earnings from long-term investments as at December 31, 2011 were $1,283 million (2010 – $1,361 million, 2009 – $1,174 million).

⁽⁶⁾: In accordance with U.S. GAAP, debt issue costs are recorded as a deferred asset rather than being included in Long-Term Debt as required under CGAAP.

148 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

⁽⁷⁾: In 2009, the Company purchased the remaining 20 per cent ownership interest in Keystone, increasing its ownership interest to 100 per cent. Under CGAAP, the transaction was considered to be an asset purchase; however, under U.S. GAAP it is considered to be a business combination. The purchase price was allocated to Plant, Property and Equipment (US$734 million) and Short-term Debt (US$197 million) using fair values of the net assets at the date of acquisition. There is no Income Statement impact under U.S. GAAP as no gain or loss was created.
⁽⁸⁾: Net of income tax recovery of $29 million in 2011 (2010 – $65 million expense; 2009 – $92 million expense).
⁽⁹⁾: Net of income tax recovery of $28 million in 2011 (2010 – $37 million expense; 2009 – $124 million expense).
⁽¹⁰⁾: Net of income tax recovery of $106 million in 2011 (2010 – $82 million recovery; 2009 – $38 million recovery).
⁽¹¹⁾: Net of income tax expense of $77 million in 2011 (2010 – $28 million expense; 2009 – $48 million expense).
⁽¹²⁾: Net of income tax recovery of $30 million in 2011 (2010 – $7 million recovery; 2009 – nil).
⁽¹³⁾: Net of income tax expense of $3 million in 2011 (2010 – $3 million expense; 2009 – $2 million expense).
⁽¹⁴⁾: Primarily related to reclassification to Net Income of actuarial losses on pension and other post-retirement benefit plans, reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges, offset by gains and losses on derivative instruments designated as cash flow hedges. Net of income tax recovery of $3 million in 2011 (2010 – $69 million recovery; 2009 – $17 million recovery).

NOTE 26 RELATED PARTY TRANSACTIONS

The following amounts are included in Due from TransCanada Corporation:

2011

2010

(millions of dollars)

Maturity Dates

Outstanding
December 31

Effective
Interest Rate

Outstanding
December 31

Effective
Interest
Rate

Discount Notes⁽¹⁾

2012

2,849

1.4%

2,566

1.4%

Credit Facility⁽²⁾

(1,435

)

3.0%

(1,203

)

3.0%

Credit Facility⁽³⁾

2012

(664

)

3.8%

–

750

1,363

The following amounts are included in Due to TransCanada Corporation:

2011

2010

(millions of dollars)

Maturity Dates

Outstanding
December 31

Effective
Interest Rate

Outstanding
December 31

Effective
Interest
Rate

Credit Facility⁽³⁾

2012

–

2,703

3.8%

⁽¹⁾: Interest on the discount notes is equivalent to current commercial paper rates.
⁽²⁾: TCPL's demand revolving credit facility arrangement with TransCanada is $2.0 billion (or a U.S. dollar equivalent). This facility bears interest at the Royal Bank of Canada prime rate per annum or the U.S. base rate per annum. This facility may be terminated at any time at TransCanada's option.
⁽³⁾: TransCanada's unsecured credit facility agreement with a subsidiary of TCPL was increased on November 15, 2010 to $3.5 billion from $2.5 billion. The amendment also limited the interest options to only allow interest to be charged at Reuters prime rate plus 75 basis points.

In 2011, Interest Expense included $140 million (2010 – $70 million; 2009 – $52 million) of interest charges and $35 million (2010 – $19 million; 2009 – $20 million) of interest income as a result of inter-corporate borrowing. At December 31, 2011, Accounts Payable included $2 million of interest payable to TransCanada (2010 – $6 million).

The Company made interest payments of $144 million to TransCanada in 2011 (2010 – $66 million; 2009 – $52 million).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 149

FIVE YEAR FINANCIAL HIGHLIGHTS

(millions of dollars except where indicated)			2011		2010		2009		2008		2007

Income Statement
Revenues			9,139		8,064		8,181		8,547		8,731
EBITDA
		Natural Gas Pipelines	2,967		2,769		3,122		3,315		3,077
		Oil Pipelines	587		–		–		–		–
		Energy	1,281		1,117		1,132		1,169		970
		Corporate	(86	)	(99	)	(117	)	(104	)	(102	)

			4,749		3,787		4,137		4,380		3,945
Depreciation			(1,528	)	(1,354	)	(1,377	)	(1,247	)	(1,237	)

EBIT			3,221		2,433		2,760		3,133		2,708
Financial charges and other			(1,044	)	(719	)	(931	)	(992	)	(918	)
Income taxes			(544	)	(365	)	(376	)	(591	)	(483	)

Net income			1,633		1,349		1,453		1,550		1,307
Net income attributable to non-controlling interests			(107	)	(93	)	(74	)	(108	)	(75	)

Net income attributable to controlling interests			1,526		1,256		1,379		1,442		1,232
Preferred share dividends			(22	)	(22	)	(22	)	(22	)	(22	)

Net income attributable to common shares			1,504		1,234		1,357		1,420		1,210

Comparable earnings			1,542		1,368		1,308		1,259		1,087
Cash Flow Statement
Funds generated from operations			3,572		3,279		3,044		2,992		2,603
Decrease/(increase) in operating working capital			282		(256	)	(88	)	128		63

Net cash provided by operations			3,854		3,023		2,956		3,120		2,666
Capital expenditures and acquisitions			3,274		5,036		6,319		6,363		5,874
Disposition of assets, net of current income taxes			–		–		–		28		35
Cash dividends paid on common and preferred shares			1,185		1,109		998		817		725
Balance Sheet
Assets
Plant, property and equipment:
	Natural Gas Pipelines		18,385		18,230		18,333		19,339		18,122
	Oil Pipelines		9,254		8,184		5,305		1,361		158
	Energy		10,545		9,745		9,158		8,435		5,127
	Corporate		78		85		83		54		45
Total assets			49,723		48,126		44,670		40,735		31,737
Capitalization
Long-term debt			17,632		17,028		16,186		15,368		12,377
Junior subordinated notes			1,009		985		1,036		1,213		975
Non-controlling interests			1,076		768		785		805		610
Preferred shares			389		389		389		389		389
Common shareholders' equity			18,073		15,358		14,483		12,574		9,664
Per Common Share Data (dollars)
Net income – basic and diluted			$2.22		$1.87		$2.20		$2.59		$2.33

Per Preferred Share Data (dollars)
Series U cumulative first preferred shares			$2.80		$2.80		$2.80		$2.80		$2.80
Series Y cumulative first preferred shares			$2.80		$2.80		$2.80		$2.80		$2.80
Financial Ratios
Earnings to fixed charges⁽¹⁾			2.3		1.8		2.1		2.7		2.6

⁽¹⁾: The earnings to fixed charges ratio is determined by dividing earnings by fixed charges. Earnings is calculated as the sum of EBIT and interest income and other, less income attributable to non-controlling interests with interest expense and undistributed earnings of investments accounted for by the equity method. Fixed charges is calculated as the sum of interest expense, interest expense of joint ventures and capitalized interest.

150 SUPPLEMENTARY INFORMATION

CONTACT INFORMATION Visit www.transcanada.com for more information on: Our pipelines and energy businesses • Projects and initiatives • Corporate responsibility • Corporate governance • Investor services TransCanada welcomes questions from shareholders and investors. Please contact: David Moneta, Vice-President, Investor Relations 1.800.361.6522 (Canada and U.S. Mainland) TransCanada Corporation TransCanada Tower, 450 First Street SW, Calgary, Alberta T2P 5H1 1.403.920.2000 1.800.661.3805 Alex Pourbaix President, Energy and Oil Pipelines Wendy Hanrahan Executive Vice-President, Corporate Services Sean McMaster Executive Vice-President, Stakeholder Relations and General Counsel Russ Girling President and Chief Executive Officer (From left to right) Don Wishart Executive Vice-President, Operations and Major Projects Don Marchand Executive Vice-President and Chief Financial Officer Dennis McConaghy Executive Vice-President, Corporate Development Greg Lohnes President, Natural Gas Pipelines

OUR VISION TransCanada will be the leading energy infrastructure company in North America, with a strong focus on pipelines and power generation opportunities located in regions where we have or can develop significant competitive advantage. Please recycle Printed in Canada March 2012 TransCanada PipeLines Limited 2011

Independent Auditors' Report of Registered Public Accounting Firm

To the Shareholders of TransCanada PipeLines Limited

We have audited the accompanying consolidated financial statements of TransCanada PipeLines Limited, which comprise the consolidated balance sheets as at December 31, 2011 and 2010, the consolidated statements of income, comprehensive income, accumulated other comprehensive income, equity and cash flows for each of the years in the three-year period ended December 31, 2011, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinions.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of TransCanada PipeLines Limited as at December 31, 2011 and 2010 and the results of its consolidated operations and its consolidated cash flows for each of the years in the three-year period ended December 31, 2011 in accordance with Canadian generally accepted accounting principles.

Other Matters

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), TransCanada PipeLines Limited's internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 13, 2012 expressed an unmodified opinion on the effectiveness of TransCanada PipeLines Limited's internal control over financial reporting.

/s/ KPMG LLP
Chartered Accountants
Calgary, Canada
February 13, 2012

Report of Independent Registered Public Accounting Firm

To the Board of Directors of TransCanada PipeLines Limited

We have audited TransCanada PipeLines Limited's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). TransCanada PipeLines Limited's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, TransCanada PipeLines Limited maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TransCanada PipeLines Limited as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, accumulated other comprehensive income, equity and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated February 13, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP
Chartered Accountants
Calgary, Canada
February 13, 2012

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EXPLANATORY NOTE
AUDITED CONSOLIDATED ANNUAL FINANCIAL STATEMENTS AND MANAGEMENT'S DISCUSSION & ANALYSIS
UNDERTAKING
DISCLOSURE CONTROLS AND PROCEDURES
AUDIT COMMITTEE FINANCIAL EXPERT
CODE OF ETHICS
PRINCIPAL ACCOUNTANT FEES AND SERVICES
OFF-BALANCE SHEET ARRANGEMENTS
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
IDENTIFICATION OF THE AUDIT COMMITTEE
FORWARD-LOOKING INFORMATION
SIGNATURES
TABLE OF CONTENTS