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

For the fiscal year ended December 31, 2012            Commission File Number 1-8887

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:

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

At December 31, 2012, 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.
738,507,894 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 Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). Yes o    No o

   

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

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, 2012. 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 2012 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 95 through 151 of the TCPL 2012 Management's Discussion and Analysis and Audited Consolidated Financial Statements included herein.

B.    Management's Discussion and Analysis

For management's discussion and analysis, see pages 1 through 94 of the TCPL 2012 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 95 of the TCPL 2012 Management's Discussion and Analysis and Audited Consolidated Financial Statements included herein.

2

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UNDERTAKING

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

DISCLOSURE CONTROLS AND PROCEDURES

For information on disclosure controls and procedures, see "Other Information — Controls and Procedures" in Management's Discussion and Analysis on pages 76 and 77 of the TCPL 2012 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 a code of business ethics for its directors, officers, employees and contractors. The Registrant's code is available on its website at www.transcanada.com. No waivers have been granted from any provision of the code during the 2012 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Pre-Approval Policies and Procedures

TransCanada's Audit Committee has adopted a pre-approval policy with respect to permitted non-audit services. Under the policy, the Audit Committee has granted pre-approval for specified non-audit services. For engagements of up to $250,000, approval of the Audit Committee Chair is required, and the Audit Committee is to be informed of the engagement at the next scheduled Audit Committee meeting. For all engagements of $250,000 or more, pre-approval of the Audit Committee is required. In all cases, regardless of the dollar amount involved, where there is a potential for conflict of interest involving the external auditor to arise on an engagement, the Audit Committee must pre-approve the assignment.

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

3

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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 2012 and 2011 fiscal years.

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 66 of the TCPL 2012 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:

4

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FORWARD-LOOKING INFORMATION

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

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

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

•

anticipated business prospects



•

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



•

expectations or projections about strategies and goals for growth and expansion



•

expected cash flows



•

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



•

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



•

expected regulatory processes and outcomes



•

expected outcomes with respect to legal proceedings, including arbitration



•

expected capital expenditures and contractual obligations



•

expected operating and financial results



•

the expected impact of future commitments and contingent liabilities



•

expected industry, market and economic conditions.

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

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

Assumptions

•

inflation rates, commodity prices and capacity prices



•

timing of debt issuances and hedging



•

regulatory decisions and outcomes



•

foreign exchange rates



•

interest rates



•

tax rates



•

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



•

integrity and reliability of our assets



•

access to capital markets



•

anticipated construction costs, schedules and completion dates



•

acquisitions and divestitures.

5

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Risks and uncertainties

•

our ability to successfully implement our strategic initiatives



•

whether our strategic initiatives will yield the expected benefits



•

the operating performance of our pipeline and energy assets



•

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



•

the availability and price of energy commodities



•

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



•

regulatory decisions and outcomes



•

outcomes of legal proceedings, including arbitration



•

performance of our counterparties



•

changes in the political environment



•

changes in environmental and other laws and regulations



•

competitive factors in the pipeline and energy sectors



•

construction and completion of capital projects



•

labour, equipment and material costs



•

access to capital markets



•

cybersecurity



•

interest and foreign exchange rates



•

weather



•

technological developments



•

economic conditions in North America as well as globally.

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

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

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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.

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DOCUMENTS FILED AS PART OF THIS REPORT

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Management's discussion and analysis

February 11, 2013

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

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

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Contents

ABOUT THIS DOCUMENT			2
ABOUT OUR BUSINESS			4
	•  Three Core Businesses		4
	•  A long-term strategy		5
	•  2012 financial highlights		6
	•  Outlook		11
	•  Non-GAAP measures		12
NATURAL GAS PIPELINES			15
OIL PIPELINES			31
ENERGY			41
CORPORATE			62
FINANCIAL CONDITION			63
OTHER INFORMATION			70
	•  Risks and risk management		70
	•  Controls and procedures		76
	•  CEO and CFO certifications		77
	•  Critical accounting policies and estimates		77
	•  Financial instruments		81
	•  Accounting changes		87
	•  Quarterly results		88
GLOSSARY			94

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2012 Management's discussion and analysis -- 1

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About this document

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

Abbreviations and acronyms that are not defined in the document are defined in the glossary on page 94.

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

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

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

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

•

anticipated business prospects

•

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

•

expectations or projections about strategies and goals for growth and expansion

•

expected cash flows

•

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

•

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

•

expected regulatory processes and outcomes

•

expected outcomes with respect to legal proceedings, including arbitration

•

expected capital expenditures and contractual obligations

•

expected operating and financial results

•

the expected impact of future commitments and contingent liabilities

•

expected industry, market and economic conditions.

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

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

Assumptions

•

inflation rates, commodity prices and capacity prices

•

timing of debt issuances and hedging

•

regulatory decisions and outcomes

•

foreign exchange rates

•

interest rates

•

tax rates

•

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

•

integrity and reliability of our assets

•

access to capital markets

•

anticipated construction costs, schedules and completion dates

•

acquisitions and divestitures.

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2 -- TransCanada Pipelines Limited

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Risks and uncertainties

•

our ability to successfully implement our strategic initiatives

•

whether our strategic initiatives will yield the expected benefits

•

the operating performance of our pipeline and energy assets

•

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

•

the availability and price of energy commodities

•

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

•

regulatory decisions and outcomes

•

outcomes of legal proceedings, including arbitration

•

performance of our counterparties

•

changes in the political environment

•

changes in environmental and other laws and regulations

•

competitive factors in the pipeline and energy sectors

•

construction and completion of capital projects

•

labour, equipment and material costs

•

access to capital markets

•

cybersecurity

•

interest and foreign exchange rates

•

weather

•

technological developments

•

economic conditions in North America as well as globally.

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

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

FOR MORE INFORMATION
See Supplementary information beginning on page 152 for other consolidated financial information on TCPL for the last three years.

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

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2012 Management's discussion and analysis -- 3

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About our business

With over 60 years of 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. We are a wholly owned subsidiary of TransCanada Corporation (TransCanada).

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

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

at December 31 (millions of $)	2012	2011	% change
Total assets
Natural Gas Pipelines	23,210	23,161	-
Oil Pipelines	10,485	9,440	11%
Energy	13,157	13,269	(1%	)
Corporate	2,483	2,196	13%
Total	49,335	48,066	3%

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

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

1

Comparable EBIT is a non-GAAP measure – see page 12 for details.

Common shares outstanding – average

(millions)
2012		738
2011		678
2010		662

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

Preferred shares	Issued and outstanding
Series U	4 million
Series Y	4 million

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4 -- TransCanada Pipelines Limited

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

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

Key components of our strategy

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

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

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

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

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

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

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

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2012 Management's discussion and analysis -- 5

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

See page 12 for more information about the non-GAAP measures we use and a reconciliation to their GAAP equivalents.

Highlights
Comparable EBITDA (earnings before interest, taxes, depreciation and amortization), comparable EBIT (earnings before interest and taxes), comparable earnings and funds generated from operations are all non-GAAP measures. See page 12 for more information.

year ended December 31 (millions of $, except per share amounts)			2012		2011		2010
Income
Revenue			8,007		7,839		6,852
Comparable EBITDA			4,245		4,544		3,686
Net income attributable to common shares			1,338		1,503		1,240
	per common share – basic and diluted		$1.81		$2.22		$1.87
Comparable earnings			1,369		1,536		1,364
Operating cash flow
Funds generated from operations			3,259		3,360		3,109
Decrease/(increase) in working capital			287		207		(292)
Net cash provided by operations			3,546		3,567		2,817
Investing activities
Capital expenditures			2,595		2,513		4,376
Equity investments			652		633		597
Acquisitions, net of cash acquired			214		-		-
Balance sheet
Total assets			49,335		48,066		46,595
Long-term debt			18,913		18,659		18,016
Junior subordinated notes			994		1,016		993
Preferred shares			389		389		389
Common shareholders' equity			17,915		17,543		14,988

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6 -- TransCanada Pipelines Limited

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Comparable earnings and net income

Comparable earnings
Comparable earnings in 2012 were $167 million lower than 2011.

The decrease in comparable earnings was the result of:

•

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

•

lower equity income from Bruce Power because of increased outage days

•

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

•

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

•

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

•

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

These decreases were partially offset by:

•

a full year of revenue from Guadalajara pipeline

•

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

•

incremental earnings from Cartier Wind and Coolidge

•

lower comparable interest expense mainly because of lower interest expense on amounts due to TransCanada, partially offset by new debt issuances in November 2011, March 2012 and August 2012

•

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

•

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

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2012 Management's discussion and analysis -- 7

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2011 comparable earnings were $172 million higher than 2010 and comparable EBIT was $690 million higher than 2010 resulting from:

•

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

•

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

•

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

•

higher comparable interest expense, mainly because:

•

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

•

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

•

partly offset by the realization of gains on derivatives used to manage our exposure to rising interest rates and a weaker U.S. dollar reduced our U.S. dollar-denominated interest expense

•

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

•

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

Net income attributable to common shares
Net income attributable to common shares in 2012 was $1,338 million (2011 – $1,503 million; 2010 – $1,240 million).

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

•

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

•

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

•

the impact of certain risk management activities each year. See page 12 for explanation of specific items in Non-GAAP measures.

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8 -- TransCanada Pipelines Limited

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Cash flow

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

Funds used in investing

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

Capital expenditures

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

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

Balance sheet
We maintained a strong balance sheet while growing our total assets by over $3 billion since 2010. At December 31, 2012, common equity represented 45 per cent of our capital structure.

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2012 Management's discussion and analysis -- 9

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Dividends

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

Before April 28, 2011, common shares purchased with reinvested cash dividends were satisfied with shares issued from treasury at a discount to the average market price in the five days before dividend payment. Beginning with the dividends declared in April 2011, common shares purchased with reinvested cash dividends are satisfied with shares acquired on the open market without discount. The increase in dividends paid on common shares (see below) is, in part, the result of this change combined with the impact of an annual five per cent increase in the dividend rate between 2010 and 2012.

Quarterly dividends on our common shares
The dividend declared for the quarter ending March 31, 2013 is equal to the quarterly dividend to be paid on TransCanada's issued and outstanding common shares at the close of business on March 29, 2013.

Quarterly dividends on our preferred shares
Series U $0.70 (for the period ending April 30, 2013)

Series Y $0.70 (for the period ending May 1, 2013)

Cash dividends year ended December 31 (millions of $)		2012		2011		2010
Common shares		1,226		1,163		1,088
Preferred shares		22		22		22

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

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10 -- TransCanada Pipelines Limited

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OUTLOOK

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

•

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

•

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

•

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

•

return to service of Sundance A in fall 2013

•

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

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

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

EBIT

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

Until we receive the NEB's decision with respect to the Canadian Restructuring Proposal, earnings from the Canadian Mainline will continue to reflect the last approved rate of return on common equity (ROE) of 8.08 per cent on deemed common equity of 40 per cent, and will exclude incentive earnings that have enhanced Canadian Mainline's earnings in recent years. If the 2012 and 2013 tolls are approved as filed, earnings in 2013 will reflect a higher ROE equivalent to an ROE of 12 per cent on deemed common equity of 40 per cent for 2012 and 2013. We also expect higher earnings from the Alberta System because of continued growth in the investment base.

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

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

•

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

•

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

•

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

•

the return to service of Sundance A in fall 2013

•

the acquisition of several Ontario Solar assets in 2013

•

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

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

Although a significant portion of Energy's output is sold under long-term contracts, output that is sold under shorter-term forward arrangements or at spot prices will continue to be affected by fluctuations in commodity prices.

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

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2012 Management's discussion and analysis -- 11

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

•

EBITDA

•

EBIT

•

comparable earnings

•

comparable EBITDA

•

comparable EBIT

•

comparable interest expense

•

comparable interest income and other

•

comparable income taxes

•

funds generated from operations.

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

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

Funds generated from operations
Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a better measure of our consolidated operating cashflow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period. See page 6 for a reconciliation to net cash provided by operations.

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

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

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

•

certain fair value adjustments relating to risk management activities

•

income tax refunds and adjustments

•

gains or losses on sales of assets

•

legal and bankruptcy settlements, and

•

write-downs of assets and investments.

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

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12 -- TransCanada Pipelines Limited

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Reconciliation of non-GAAP measures

year ended December 31 (millions of $, except per share amounts)			2012		2011		2010
Comparable EBITDA			4,245		4,544		3,686
Depreciation and amortization			(1,375)		(1,328)		(1,160)
Comparable EBIT			2,870		3,216		2,526
Other income statement items
Comparable interest expense			(997)		(1,046)		(754)
Comparable interest income and other			86		60		94
Comparable income taxes			(472)		(565)		(387)
Net income attributable to non-controlling interests			(96)		(107)		(93)
Preferred share dividends			(22)		(22)		(22)
Comparable earnings			1,369		1,536		1,364
Specific items (net of tax)
	Sundance A PPA arbitration decision		(15)		-		-
	Risk management activities1		(16)		(33)		3
	Valuation provision for MGP		-		-		(127)
Net income attributable to common shares			1,338		1,503		1,240
Comparable interest expense			(997)		(1,046)		(754)
Specific item:
	Risk management activities1		-		2		-
Interest expense			(997)		(1,044)		(754)
Comparable interest income and other			86		60		94
Specific item:
	Risk management activities1		(1)		(5)		-
Interest income and other			85		55		94
Comparable income taxes			(472)		(565)		(387)
Specific item:
	Sundance A PPA arbitration decision		5		-		-
	Risk management activities1		6		19		(4)
	Valuation provision for MGP		-		-		19
Income taxes expense			(461)		(546)		(372)

1

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

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2012 Management's discussion and analysis -- 13

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EBITDA and EBIT by business segment

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

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

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

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14 -- TransCanada Pipelines Limited

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Natural Gas Pipelines

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

•

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

•

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

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

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

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2012 Management's discussion and analysis -- 15

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16 -- TransCanada Pipelines Limited

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

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

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2012 Management's discussion and analysis -- 17

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

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18 -- TransCanada Pipelines Limited

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RESULTS

Natural Gas Pipelines results
Comparable EBITDA, comparable EBIT and EBIT are all non-GAAP measures. See page 12 for more information.

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

1

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

2

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

3

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

4

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

5

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

6

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

7

Represents our 61.7 per cent ownership interest.

8

Included as of June 2011.

9

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

10

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

11

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

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2012 Management's discussion and analysis -- 19

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

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

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

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

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

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

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

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

•

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

•

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

•

higher OM&A and other costs at ANR

•

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

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

•

Bison starting operations in January 2011

•

Guadalajara starting operations in June 2011

•

lower general, administrative support costs in 2011

•

lower revenues at Great Lakes and GTN in 2011.

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20 -- TransCanada Pipelines Limited

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

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

OUTLOOK

Canadian Pipelines

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

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

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

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

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

U.S. Pipelines

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

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

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

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2012 Management's discussion and analysis -- 21

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Capital expenditures
We spent a total of $1.4 billion in 2012 for our natural gas pipelines in Canada, the U.S. and Mexico, and expect to spend $1.9 billion in 2013 primarily on Alberta System expansion projects, the Tamazunchale Pipeline Extension, the Topolobampo and Mazatlan pipelines in Mexico, and maintenance projects on our natural gas pipelines. We fund capital expenditures through existing cash flows and access to capital markets. See page 63 for further discussion on liquidity risk.

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

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

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

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

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

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

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

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22 -- TransCanada Pipelines Limited

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

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

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

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

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

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2012 Management's discussion and analysis -- 23

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

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

•

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

•

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

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

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

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

•

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

•

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

•

industrial growth in both Canada and the U.S.

•

increased exports to Mexico to fuel new power generation facilities

•

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

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

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

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

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

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

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

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

ANR has demonstrated its adaptability to changing market dynamics by identifying opportunities and investing in its system to accommodate the market's demands for services that are counter to traditional flow patterns. This has resulted in increased bi-directional flows and shorter haul services in some of its supply and market areas.

Although the unseasonably warm winter weather and lack of storage demand negatively impacted ANR in 2012, we expect an increased demand for pipeline transportation broadly in the U.S. resulting in a positive impact to ANR because of the following factors:

•

a return to average weather conditions

•

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

•

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

GTN is supplied with natural gas from the WCSB and the Rockies. It competes with other interstate pipelines providing natural gas transportation services to markets in the U.S. Pacific Northwest, California and Nevada. These markets also have access to supplies from natural gas basins in the Rocky Mountains and the U.S. Southwest. GTN has significant long term contracts and is currently operating under a rate settlement which started in January 2012 and expires at the end of December 2015. As a result, GTN's revenues are subject to variation primarily as a result of capacity sold above its current contracted amount.

Great Lakes competes for natural gas transportation customers with pipelines that transport gas from the WCSB and natural gas sourced in the U.S. Great Lakes has experienced significant non-renewals of its long haul capacity in the past few years and its contracts are for shorter terms than in the past. Great Lakes revenues were also negatively impacted in 2012 by a warm winter and historically high storage levels that decreased its throughput. Demand for Great Lakes capacity changes with seasonal market conditions and we

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2012 Management's discussion and analysis -- 25

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expect a return to average winter weather will increase throughput due to storage demand. Great Lakes is required to file a rate case no later than November 1, 2013, and this provides the opportunity for rate and tariff changes in response to current market conditions.

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

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

•

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

•

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

•

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

•

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

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

SIGNIFICANT EVENTS

Canadian Pipelines

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

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

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

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

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

Projects

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

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

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

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

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

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

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2012 Management's discussion and analysis -- 27

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

Regulatory filings

Canadian Pipelines
We filed a comprehensive restructuring proposal with the NEB in September 2011 for the Canadian Mainline. The proposal is intended to enhance the competitiveness of the Canadian Mainline and transportation from the WCSB, and includes a request for 2012 and 2013 tolls that align with the proposed changes to our business structure and the terms and conditions of service on the Canadian Mainline. The NEB established interim tolls for 2012 based on the approved 2011 final tolls. We do not expect a decision on the Canadian Restructuring Proposal until late first quarter or early second quarter 2013.

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

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

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

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

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

BUSINESS RISKS
The following are risks specific to our natural gas pipelines business. See page 70 for information about general risks that affect the company as a whole.

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

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competition, downstream pipeline tolls, demand within Alberta and the overall value of the reserves, including liquids content.

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

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

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

Several factors influence demand for pipeline capacity:

•

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

•

large producers often diversify their portfolios by developing several basins, but this is influenced by actual costs to develop the resource as well as economic access to markets and cost of the necessary pipeline infrastructure. Basin-on-basin competition impacts the extent and timing of a resource play's development, which in turn drives changes in demand for pipeline capacity.

•

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

•

growing pipeline infrastructure, changes in supply sources, and unutilized capacity on many pipelines have led to a contraction of regional basis differentials (the differences in market prices paid for natural gas between different gas receipt and delivery points), which has led to changes in the way many pipeline systems are being used. As a result, many pipeline companies are moving to restructure their business models, rate designs and services to adapt to the changing flow dynamics.

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2012 Management's discussion and analysis -- 29

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

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

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Oil Pipelines

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

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

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

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

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

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2012 Management's discussion and analysis -- 31

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

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

*

Not shown on map

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2012 Management's discussion and analysis -- 33

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RESULTS
Comparable EBITDA, comparable EBIT and EBIT are all non-GAAP measures. See page 12 for more information.

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

1

Results in 2011 are for 11 months.

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

•

higher contracted volumes

•

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

•

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

•

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

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

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

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

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

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OUTLOOK

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

Capital expenditures
We spent a total of $1.1 billion in 2012, and expect to spend $4.1 billion in 2013, mainly related to Keystone XL and the Gulf Coast Project. We fund capital expenditures through existing cash flows and access to capital markets. See page 63 for further discussion on liquidity risk.

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

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

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

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2012 Management's discussion and analysis -- 35

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

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

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

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

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

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

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

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

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

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

According to BENTEK Energy, the Permian Basin, located mainly in western Texas, currently produces 1.3 million Bbl/d and will reach 1.8 million Bbl/d by the end of 2016. The Permian Basin is the primary source of crude oil for the Cushing Marketlink project. Growing U.S. production has contributed to increased crude oil supply at the Cushing, Oklahoma market hub and resulted in increased demand for additional pipeline capacity between Cushing and the U.S. Gulf Coast refining market. Our Gulf Coast Project will provide needed pipeline capacity to transport growing crude oil supply at Cushing to the U.S. Gulf Coast.

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

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

SIGNIFICANT EVENTS

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

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

The 36-inch pipeline will extend from Cushing, Oklahoma to the U.S. Gulf Coast. We expect it to have an initial capacity of up to 700,000 Bbl/d, and an ultimate capacity of 830,000 Bbl/d. We estimate the total cost

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2012 Management's discussion and analysis -- 37

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of the project to be US$2.3 billion, and as of December 31, 2012, construction was approximately 35 per cent complete. US$300 million of the total cost is expected to be spent on the Houston Lateral pipeline, a 76 km (47 mile) pipeline that will transport crude oil to Houston refineries.

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

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

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

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

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

The pipeline will extend from Hardisty, Alberta to Steele City, Nebraska. We estimate the total cost of the project to be US$5.3 billion and, as of December 31, 2012, had invested US$1.8 billion. We expect the pipeline to be in service in late 2014 or early 2015, subject to regulatory approvals.

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

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

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

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

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

The 90 km (54 mile) pipeline system will transport bitumen and diluent between the Fort Hills mine site and the Voyageur Upgrader, north of Fort McMurray, Alberta. We estimate total capital costs to be $660 million. The pipeline is fully subscribed under long-term contract to service the Fort Hills mine, which is jointly owned by Suncor Energy Inc, Total E&P Canada Ltd. and Teck Resources Limited.

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38 -- TransCanada Pipelines Limited

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

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

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

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

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

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

BUSINESS RISKS
The following are risks specific to our oil pipelines business. See page 70 for information about general risks that affect the company as a whole, including other operational risks, health, safety and environment (HSE) risks, and financial risks.

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

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

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

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2012 Management's discussion and analysis -- 39

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projects are also subject to permitting risk which may result in construction delays and potentially reduced investment returns.

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

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

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40 -- TransCanada Pipelines Limited

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Energy

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

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

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

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

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

1    Includes facilities under development.

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2012 Management's discussion and analysis -- 41

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42 -- TransCanada Pipelines Limited

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

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

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2012 Management's discussion and analysis -- 43

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

1

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

2

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

3

Our share of power generation capacity.

4

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

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44 -- TransCanada Pipelines Limited

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RESULTS
Comparable EBITDA, and comparable EBIT are non-GAAP measures. See page 12 for more information.

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

1

Includes Coolidge starting in May 2011.

2

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

3

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

4

Does not include depreciation and amortization of equity investments.

5

Includes phase two of Kibby Wind starting in October 2010.

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

•

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

•

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

•

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

•

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

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2012 Management's discussion and analysis -- 45

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OUTLOOK

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

•

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

•

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

•

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

•

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

•

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

•

the return to service of Sundance A in fall 2013

•

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

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

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

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

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

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

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46 -- TransCanada Pipelines Limited

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

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

Capital expenditures
We spent a total of $24 million in 2012, and expect to spend $130 million on capital expenditures in Energy in 2013. We fund capital expenditures through existing cash flows and access to capital markets. See page 63 for further discussion on liquidity risk.

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

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

•

Canadian Power

•

U.S. Power

•

Natural Gas Storage

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

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

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2012 Management's discussion and analysis -- 47

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Canadian Power

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

Power purchased under long-term contracts is as follows:

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

Power sold under long-term contracts is as follows:

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

Earnings in the Western Power business are maximized by maintaining and optimizing the operations of our power plants, and through various marketing activities.

A disciplined operational strategy is critical to maximizing output and revenue at our cogeneration facilities and maximizing Coolidge earnings, where revenue is based on plant availability, and is not a function of market price.

The marketing function is critical for optimizing returns and managing risk through direct sales to medium and large industrial and commercial companies and other market participants. Our marketing group sells power sourced through the PPAs, markets uncommitted volumes from the cogeneration plants, and buys and sells power and natural gas to maximize earnings from our assets. To reduce exposure associated with uncontracted volumes, we sell a portion of our power in forward sales markets when acceptable contract terms are available.

A portion of our power is retained to be sold in the spot market or under shorter-term forward arrangements. This ensures we have adequate power supply to fulfill our sales obligations if we have unexpected plant outages and provides the opportunity to increase earnings in periods of high spot prices.

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

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

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

1

Power generation has been suspended since 2008.

Assets currently in development are as follows:

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

Western and Eastern Power results^1,2
Comparable EBITDA and comparable EBIT are non-GAAP measures. See page 12 for more information.

year ended December 31 (millions of $)			2012		2011		2010
Revenue
	Western power1		640		822		598
	Eastern power2		415		391		243
	Other3		91		69		83
			1,146		1,282		924
Income from equity investments4			68		117		74
Commodity purchases resold
	Western power		(281)		(368)		(363)
	Other5		(5)		(9)		(26)
			(286)		(377)		(389)
Plant operating costs and other			(218)		(242)		(185)
Sundance A PPA arbitration decision6			(30)		-		-
General, administrative and support costs			(48)		(43)		(38)
Comparable EBITDA			632		737		386
Depreciation and amortization7			(152)		(141)		(114)
Comparable EBIT			480		596		272

1

Includes Coolidge starting in May 2011.

2

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

3

Includes sale of excess natural gas purchased for generation and sales of thermal carbon black.

4

Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy.

5

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

6

See Significant events for more information about the Sundance A PPA arbitration decision.

7

Does not include depreciation and amortization of equity investments.

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2012 Management's discussion and analysis -- 49

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Sales volumes and plant availability^1,2
Includes our share of volumes from our equity investments.

year ended December 31				2012		2011		2010
Sales volumes (GWh)
Supply
	Generation
		Western Power1		2,691		2,606		2,373
		Eastern Power2		4,384		3,714		2,359
	Purchased
		Sundance A & B and Sheerness PPAs3		6,906		7,909		10,785
		Other purchases		46		248		314
				14,027		14,477		15,831
Sales
	Contracted
		Western Power1		8,240		8,381		10,096
		Eastern Power2		4,384		3,714		2,375
	Spot
		Western Power		1,403		2,382		3,360
				14,027		14,477		15,831
Plant availability4
Western Power1,5				96%		97%		95%
Eastern Power2,6				90%		93%		94%

1

Includes Coolidge starting in May 2011.

2

Includes Cartier phase two of Gros-Morne starting in November 2012, phase one of Gros-Morne starting in November 2011, and Montagne- Sèche starting in November 2011; Halton Hills starting in September 2010. Also includes volumes related to our 50 per cent ownership interest in Portlands Energy.

3

Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership. No volumes were delivered under the Sundance A PPA in 2012 or 2011.

4

The percentage of time in a period that the plant is available to generate power, regardless of whether it is running.

5

Does not include facilities that provide power to TCPL under PPAs.

6

Does not include Bécancour because power generation has been suspended since 2008.

Western Power's comparable EBITDA was $335 million in 2012, or $148 million lower than 2011. This was primarily due to the net effect of:

•

the Sundance A PPA force majeure

•

lower purchased PPA volumes during periods of lower spot prices

•

lower equity earnings from ASTC Power Partnership because of the Sundance B arbitration decision

•

incremental earnings from Coolidge, which was placed in service in May 2011

•

higher realized power prices and

•

lower fuel costs.

In the first quarter of 2012, we recorded revenues and costs related to the Sundance A PPA as though the outages of Units 1 and 2 were interruptions of supply in accordance with the terms of the PPA. In July 2012, we received the Sundance A PPA arbitration decision, and recorded a charge of $30 million; an amount equivalent to the pre-tax income we had recorded in first quarter. Because the plant is now in force majeure, we will not record further revenues and costs until the units are returned to service. See pages 57 and 58 for more information about the Sundance A and Sundance B PPA arbitration decisions.

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50 -- TransCanada Pipelines Limited

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In 2011, Western Power's comparable EBITDA was $483 million, or $271 million higher than 2010, and revenue was $822 million, or $224 million higher than 2010. These increases were mainly the result of higher overall realized power prices in Alberta, and incremental earnings from Coolidge, which went in service in May 2011.

Purchased volumes in 2012 were lower than 2011 mainly because of lower utilization of the Sundance B and Sheerness PPAs during periods of lower spot market power prices, and higher plant outage days. Average spot market power prices in Alberta were $64 per MWh in 2012, or 16 per cent lower than 2011. Despite the decrease in spot prices, Western Power earned a higher realized price per MWh in 2012 compared to 2011 as a result of contracting activities.

Western Power's revenue was $640 million in 2012, or $182 million lower than 2011. This was the net effect of:

•

the Sundance A PPA force majeure

•

lower purchased PPA volumes during periods of lower spot prices

•

incremental earnings from Coolidge which was placed in service in May 2011 and

•

higher realized power prices resulting from contracting activities.

Western Power's commodity purchases resold were $281 million in 2012, or $87 million lower than 2011 because of the Sundance A PPA force majeure and lower purchased volumes.

Eastern Power's comparable EBITDA was $345 million in 2012, or $48 million higher than 2011. Revenue also increased by $24 million in 2012, to $415 million. The increases were mainly due to:

•

incremental earnings from Cartier (Montangne-Sèche and phase one of Gros-Morne, which were placed in service in November 2011, and phase two of Gros-Morne which was placed in service in November 2012), and

•

higher contractual earnings at Bécancour.

In 2011, Eastern Power's comparable EBITDA was $297 million, or $85 million higher than 2010. Revenue also increased by $148 million in 2011, to $391 million. The increases were mainly because Halton Hills was placed in service in September 2010, giving us incremental earnings in 2011.

Income from equity investments was $68 million in 2012, or $49 million lower than 2011, mainly due to lower earnings from ASTC Power Partnership because of:

•

lower Sundance B PPA volumes

•

lower spot market power prices and

•

the impact of the Sundance B PPA arbitration decision.

In 2011, income from equity investments was $117 million, or $43 million higher than 2010, mainly because higher spot market power prices increased earnings from the ASTC Power Partnership.

Plant operating costs and other, which includes natural gas fuel consumed in power generation, were $218 million in 2012, or $24 million lower than 2011, mainly because natural gas fuel prices were lower in 2012. In 2011, they were $242 million, or $57 million higher than 2010 mainly because of incremental fuel consumed at Halton Hills.

Depreciation and amortization was $152 million in 2012, or $11 million higher than 2011, mainly because of incremental depreciation from Cartier and Coolidge. In 2011, depreciation and amortization was $141 million, or $27 million higher than 2010 mainly because of incremental depreciation from Halton Hills and Coolidge being placed in service.

Approximately 85 per cent of Western Power sales volumes were sold under contract in 2012 compared to 78 per cent in 2011 and 75 per cent in 2010. To reduce its exposure to spot market prices in Alberta, Western Power has entered into fixed-price power sales contracts to sell approximately 6,700 GWh for 2013 and approximately 4,300 GWh for 2014.

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2012 Management's discussion and analysis -- 51

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Bruce Power
Bruce Power is a nuclear power generation facility located near Tiverton, Ontario and comprises Bruce A and Bruce B. Bruce A Units 1 to 4 have a combined capacity of approximately 3,000 MW and Bruce B Units 5 to 8 have a combined capacity of approximately 3,200 MW. Bruce B leases the eight nuclear reactors from Ontario Power Generation and subleases Units 1 to 4 to Bruce A.

Bruce Power's generating capacity is fully contracted with the OPA. Results from Bruce Power fluctuate primarily due to the frequency, scope and duration of planned and unplanned outages.

Under the 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. Bruce A also recovers fuel costs from the OPA.

Bruce A fixed price		Per MWh
April 1, 2012 – March 31, 2013		$68.23
April 1, 2011 – March 31, 2012		$66.33
April 1, 2010 – March 31, 2011		$64.71

Under the same contract, all output from Bruce B Units 5 to 8 is subject to a floor price adjusted for inflation once a year on April 1.

Bruce B floor price		Per MWh
April 1, 2012 – March 31, 2013		$51.62
April 1, 2011 – March 31, 2012		$50.18
April 1, 2010 – March 31, 2011		$48.96

Bruce B is required to repay payments it receives under the floor price mechanism within a calendar year when the monthly average spot price exceeds the floor price. It has not had to repay any amounts recorded in revenues in the past three years.

Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.

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52 -- TransCanada Pipelines Limited

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Bruce Power results
Our proportionate share

year ended December 31 (millions of $, unless otherwise indicated)			2012		2011		2010
Income/(loss) from equity investments1
Bruce A			(149)		33		35
Bruce B			163		77		138
			14		110		173
Comprised of:
	Revenues		763		817		862
	Operating expenses		(567)		(565)		(564)
	Depreciation and other		(182)		(142)		(125)
			14		110		173
Bruce Power – other information
Plant availability2
	Bruce A3		54%		90%		81%
	Bruce B		95%		88%		91%
	Combined Bruce Power		81%		89%		88%
Planned outage days
	Bruce A		336		60		60
	Bruce B		46		135		70
Unplanned outage days
	Bruce A		18		16		64
	Bruce B		25		24		34
Sales volumes (GWh)1
	Bruce A3		4,194		5,475		5,026
	Bruce B		8,475		7,859		8,184
			12,669		13,334		13,210
Realized sales price per MWh
	Bruce A		$68		$66		$65
	Bruce B4		$55		$54		$58
	Combined Bruce Power		$57		$57		$60

1

Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B.

2

The percentage of time in a year the plant is available to generate power, regardless of whether it is running.

3

Plant availability and sales volumes for 2012 include the incremental impact of Unit 1 which was returned to service on October 22 and Unit 2, which was returned to service on October 31.

4

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

Equity income from Bruce A decreased by $182 million in 2012, to a loss of $149 million, compared to income of $33 million in 2011. The decrease was mainly due to:

•

lower volumes and higher operating costs resulting from the ongoing Unit 4 planned outage, which began on August 2, 2012 and

•

the Unit 3 West Shift Plus planned outage, which began in November 2011 and was completed in June 2012.

These were partially offset by incremental earnings from Units 1 and 2, which were returned to service on October 22 and October 31, 2012, respectively.

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2012 Management's discussion and analysis -- 53

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Units 1 and 2 have operated at reduced output levels following their return to service and, in late November 2012, Bruce Power took Unit 1 offline for an approximate one month maintenance outage. Bruce Power expects the availability percentages for Units 1 and 2 to increase over time; however, these units have not operated for an extended period of time and may experience slightly higher forced outage rates and reduced availability percentages in 2013. Overall plant availability for Bruce A is expected to be approximately 90 per cent in 2013.

Equity income from Bruce B was $163 million in 2012, or $86 million higher than 2011. The increase was mainly due to higher volumes and lower operating costs resulting from fewer planned outage days, lower lease expense and higher realized prices.

In 2011, equity income from Bruce Power was $110 million, or $63 million lower than 2010. The decrease was mainly from lower equity income at Bruce B, due to lower realized prices resulting from expiration of fixed-price contracts at higher prices and higher operating costs and lower volumes due to increased outage days. Equity income from Bruce Power in 2010 also included the net positive impact of a payment Bruce B made to Bruce A in 2010, related to amendments made to the agreements with the OPA in 2009. The net impact was positive because we have a higher percentage ownership in Bruce A.

The overall plant availability percentage in 2013 is expected to be approximately 90 per cent for Bruce A and high 80s for Bruce B. The Unit 4 outage, which began on August 2, 2012, is expected to be completed in late first quarter 2013. Planned maintenance on Bruce B units is scheduled to occur during the first half of 2013.

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

We earn revenues in both New York and New England in two ways – by providing capacity and by selling energy. Capacity markets compensate power suppliers for being available to provide power, and are intended to promote investment in new and existing power resources needed to meet customer demand and maintain a reliable power system. The energy markets compensate power providers for the actual energy they supply.

Providing capacity
Capacity revenues in New York and New England are a function of two factors – capacity prices and plant availability. It is important for us to keep our plant availability high to maximize the amount of capacity we get paid for.

Capacity prices paid to capacity suppliers in New York are determined by a series of voluntary forward auctions and a mandatory spot auction. The forward auctions are bid based while the mandatory spot auction is affected by a demand curve price setting process that is driven by a number of established parameters that are subject to periodic review by the New York ISO and FERC. The parameters are determined for each zone and include the forecasted cost of a new unit entering the market, available existing operable supply and fluctuations in the forecasted demand. Since 2011, we have been engaged in an ongoing regulatory process related to a number of capacity pricing issues in the New York Zone J market where our Ravenswood facility operates. See page 59 for more information.

The price paid for capacity in the New England Power Pool is determined by annual competitive auctions which are held three years in advance of the applicable capacity year. Auction results are impacted by actual and projected power demand, power supply, and other factors.

Selling energy
We focus on selling power under short- and long-term contracts to wholesale, commercial and industrial customers. In some cases, power sales are bundled with other energy services that we earn additional revenues for providing in the following power markets:

•

New York, operated by the New York ISO

•

New England, operated by the New England ISO

•

PJM Interconnection area (PJM), a regional transmission organization that coordinates the movement in wholesale electricity in all or parts of 13 states and the District of Columbia.

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54 -- TransCanada Pipelines Limited

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We meet our power sales commitments using power we generate ourselves or with power we buy at fixed prices, reducing our exposure to changes in commodity prices.

U.S. Power results
Comparable EBITDA and comparable EBIT are non-GAAP measures. See page 12 for more information for more details.

year ended December 31 (millions of US$)			2012		2011		2010
Revenue
	Power1,2		1,189		1,139		1,319
	Capacity		234		227		231
	Other3		51		80		78
			1,474		1,446		1,628
Commodity purchases resold			(765)		(618)		(772)
Plant operating costs and other2			(452)		(514)		(521)
General, administrative and support costs			(48)		(41)		(32)
Comparable EBITDA1			209		273		303
Depreciation and amortization1			(121)		(109)		(116)
Comparable EBIT1			88		164		187

1

Includes phase two of Kibby Wind starting in October 2010.

2

The realized gains and losses from financial derivatives used to buy and sell power, natural gas and fuel oil to manage U.S. Power's assets are presented on a net basis in power revenues.

3

Includes revenues and costs related to a third party service agreement at Ravenswood, the activity level of which decreased in 2012.

Sales volumes and plant availability

year ended December 31			2012		2011		2010
Physical sales volumes (GWh)
Supply
	Generation		7,567		6,880		6,755
	Purchased		9,408		6,018		8,899
			16,975		12,898		15,654
Plant availability1			85%		87%		86%

1

The percentage of time in a year the plant is available to generate power, regardless of whether it is running.

U.S. Power's comparable EBITDA was US$209 million in 2012, or US$64 million lower than 2011. This reflected the net effect of:

•

lower realized power prices

•

higher load serving costs

•

reduced water flows at the TC Hydro facilities

•

increased generation at the Ravenswood facility and

•

higher sales to wholesale, commercial and industrial customers.

In 2011, comparable EBITDA was US$273 million, or US$30 million lower than 2010. This was mainly the result of 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.

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2012 Management's discussion and analysis -- 55

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Physical sales volumes in 2012 have increased compared to the same period in 2011, partly due to higher purchased volumes to serve increased sales to wholesale, commercial and industrial customers in the PJM and New England markets. Generation volumes were also higher, mainly because of higher volumes at Ravenswood in the last quarter of 2012 resulting from Superstorm Sandy. Ravenswood ran at higher than normal generation levels both during and following the storm when damage at several other power and transmission facilities reduced power supply in the area. This increase in generation volumes was partly offset by lower hydro volumes.

Power revenue was US$1,189 million in 2012, or US$50 million higher than 2011. This was mainly due to higher sales volumes, partly offset by the effect of lower realized power prices on revenues.

Capacity revenue was US$234 million in 2012, or US$7 million higher than 2011 because realized capacity prices in New York were higher, partially offset by lower capacity prices in New England.

Commodity purchases resold were US$765 million in 2012, or US$147 million higher than 2011 because volumes of physical power purchased for resale under power sales commitments to wholesale, commercial and industrial customers were higher, and load serving costs were higher. The impact of higher volumes was partially offset by lower realized prices on purchased power.

In 2011, power revenue was $1,139 million, or $180 million lower than 2010, and commodity purchases resold were $618 million, or $154 million lower than 2010, mainly because volumes of physical power purchased for resale under power sales commitments to wholesale, commercial and industrial customers were lower.

Plant operating costs and other, which includes fuel gas consumed in generation, was US$452 million in 2012, or US$62 million lower than 2011 mainly because natural gas fuel prices were lower, partly offset by higher gas consumption at Ravenswood resulting from increased generation.

As at December 31, 2012, approximately 2,600 GWh or 34 per cent of US Power's planned generation is contracted for 2013, and 1,000 GWh or 13 per cent for 2014. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.

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

Storage capacity

year ended December 31		Working gas storage capacity (Bcf)		Maximum injection/ withdrawal capacity (MMcf/d)
Edson		50		725
CrossAlta1		68		550
Third-party storage		38		630
		156		1,905

1

Reflects the acquisition of the 40 per cent interest held by BP resulting in an additional 27 Bcf of working gas storage capacity in December 2012.

Our natural gas storage business 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. Market volatility creates arbitrage opportunities and our natural gas storage facilities also give customers the ability to capture value from short-term price movements.

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56 -- TransCanada Pipelines Limited

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The natural gas storage business is affected by the change in seasonal natural gas price spreads, which are generally determined by the differential in natural gas prices between the traditional summer injection and winter withdrawal seasons. We manage this exposure by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. We sell a portfolio of short, medium and long-term storage products to participants in the Alberta and interconnected gas markets.

Proprietary natural gas storage transactions include 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, we lock in future positive margins, effectively eliminating our exposure to seasonal natural gas 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 through net income based on the forward market prices for the contracted month of delivery. We record changes in the fair value of these contracts in revenues. We do not include changes in the fair value of natural gas forward purchase and sales contracts when we calculate comparable earnings, because they do not represent the amounts that will be realized on settlement.

Natural Gas Storage results
Comparable EBITDA and comparable EBIT are non-GAAP measures. See page 12 for more information.

year ended December 31 (millions of $)		2012		2011		2010
Alberta Storage1		77		84		136
General, administrative and support costs		(10)		(6)		(8)
Natural Gas Storage – comparable EBITDA		67		78		128
Depreciation and amortization		(10)		(12)		(13)
Natural Gas Storage – comparable EBIT		57		66		115

1

Includes our share of equity income from our investment in CrossAlta up to December 18, 2012. On December 18, 2012, we acquired the remaining 40 per cent interest in CrossAlta, bringing our ownership interest to 100 per cent. See significant events on page 59.

Comparable EBITDA was $67 million in 2012, or $11 million lower than 2011, mainly due to the impact of lower realized natural gas storage price spreads, partially offset by lower operating costs throughout the year.

In 2011, comparable EBITDA was $78 million, or $50 million lower than 2010, mainly due to lower realized natural gas storage price spreads.

SIGNIFICANT EVENTS

Canadian Power

Western Power

Sundance A PPA
In December 2010, Sundance A Units 1 and 2 were withdrawn from service and, in January 2011, were subject to a force majeure claim by TransAlta. In February 2011, TransAlta informed us that it was not economic to replace or repair Units 1 and 2, and that the Sundance A PPA should be terminated.

We disputed both the force majeure and the economic destruction claims under the binding dispute resolution process provided in the PPA. In July 2012, an arbitration panel decided that the PPA should not be terminated and ordered TransAlta to rebuild Units 1 and 2. The panel also limited TransAlta's force majeure claim, from November 20, 2011 until the units can reasonably be returned to service. TransAlta announced that it expects the units to be returned to service in the fall of 2013.

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2012 Management's discussion and analysis -- 57

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Since we considered the outages to be an interruption of supply, we accrued $188 million in pre-tax income between December 2010 and March 2012. The outcome of the decision was that we received approximately $138 million of this amount. We recorded the $50 million difference as a charge to second quarter 2012 earnings, of which $20 million related to amounts accrued in 2011.

We will not record further revenue or costs from the PPA until the units are returned to service. The net book value of the Sundance A PPA recorded in Intangibles and Other Assets remains fully recoverable.

Sundance B PPA
In second quarter 2010, Sundance B Unit 3 experienced an unplanned outage related to mechanical failure of certain generator components and was subject to a force majeure claim by TransAlta. The ASTC Power Partnership, which holds the Sundance B PPA, disputed the claim under the binding dispute resolution process provided in the PPA because we did not believe TransAlta's claim met the test of force majeure. We therefore recorded equity earnings from our 50 per cent ownership interest in ASTC Power Partnership as though this event were a normal plant outage.

In November 2012, an arbitration decision was reached with the arbitration panel granting partial force majeure relief to TransAlta, and we reduced our equity earnings by $11 million from the ASTC Power Partnership to reflect the amount that will not be recovered as result of the decision.

Eastern Power

Napanee Generating Station
In December 2012, we signed a contract with the OPA, to develop, own and operate a new 900 MW natural gas-fired power plant at Ontario Power Generation's Lennox site in Eastern Ontario in the town of Greater Napanee. The plant will replace the facility that was planned and subsequently cancelled in the community of Oakville and will operate under a 20-year Clean Energy Supply contract with the OPA. We were reimbursed for $250 million of costs, mainly related to natural gas turbines that were purchased for the Oakville project, which will now be used at Napanee. We plan to invest approximately $1.0 billion in the Napanee facility.

Cartier Wind
We placed the second phase of the Gros-Morne wind farm project (111 MW) in service in November 2012, completing the 590 MW, five-phase Cartier Wind Project in Québec. All of the power produced by Cartier Wind is sold to Hydro-Québec under 20-year PPAs.

Ontario Solar
In late 2011, we agreed to buy nine Ontario solar projects (combined capacity of 86 MW) from Canadian Solar Solutions Inc., for approximately $476 million. Under the terms of the agreement, Canadian Solar Solutions Inc. will develop and build each of the nine solar projects using photovoltaic panels. We will buy each project once construction and acceptance testing are complete and commercial operation begins. All power produced will be sold under 20-year PPAs with the OPA under the FIT program in Ontario.

We expect to close the acquisition of the first two projects (combined capacity of 20 MW) in the first half of 2013 for a total cost of approximately $125 million. We expect to acquire the other seven projects in 2013 to late 2014, subject to regulatory approvals.

Bécancour
In June 2012, Hydro-Québec notified us that it would exercise its option to extend the agreement to suspend all electricity generation from the Bécancour power plant through 2013. Under the suspension agreement, Hydro-Québec has the option (subject to certain conditions) to extend the suspension every year until regional electricity demand levels recover. We continue to receive capacity payments while generation is suspended.

Bruce Power
This year, Bruce Power completed the refurbishment of Units 1 and 2. Unit 1 was returned to service on October 22, 2012, and Unit 2 on October 31, 2012. An incident in May 2012 within the Unit 2 electrical generator on the non-nuclear side of the plant had delayed returning the units to service. Bruce Power's force

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58 -- TransCanada Pipelines Limited

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majeure claim to the OPA was accepted in August, and it continued to receive the contracted price for power generated during the force majeure period.

Units 1 and 2 have operated at reduced output levels following their return to service and, in late November 2012, Bruce Power took Unit 1 offline for an approximate one month maintenance outage. Bruce Power expects the availability percentages for Units 1 and 2 to increase over time; however, these units have not operated for an extended period of time and may experience slightly higher forced outage rates and reduced availability percentages in 2013. Overall plant availability for Bruce A is expected to be approximately 90 per cent in 2013.

Bruce Power also continued its strategy to maximize the operating life of its reactors. It returned Unit 3 to service in June after completing the $300 million West Shift Plus life extension outage, which began in 2011. Unit 4 is expected to return to service in late first quarter 2013 after the completion of an expanded outage investment program that began in August 2012. These investments should allow Units 3 and 4 to produce low cost electricity until at least 2021.

U.S. Power

Ravenswood
In 2011, we jointly filed two formal complaints with the FERC challenging how the New York ISO applied its buy-side mitigation rules affecting bidding criteria associated with two new power plants that began service in the New York Zone J markets during the summer of 2011.

In June 2012, the FERC addressed the first complaint, indicating it would take steps to increase transparency and accountability for future mitigation exemption tests (MET) and decisions. In September, 2012, the FERC granted an order on the second complaint, directing the New York ISO to retest the two new power plants as well as a transmission project currently under construction using an amended set of assumptions to more accurately perform the MET calculations, in accordance with existing rules and tariff provisions. The recalculation was completed in November 2012 and it was determined that one of the plants had been granted an exemption in error. That exemption was revoked and the plant is now required to offer its capacity at a floor price which has put upward pressure on capacity auction prices since December. The order was prospective only and has no impact on capacity prices for prior periods.

Natural Gas Storage

CrossAlta
In December 2012, we acquired the remaining 40 per cent interests in the Crossfield Gas Storage facility and CrossAlta Gas Storage & Services Ltd. marketing company from BP for approximately $220 million. We now own and operate 100 per cent of CrossAlta. The acquisition added an additional 27 Bcf of working gas storage capacity to our existing portfolio in Alberta.

BUSINESS RISKS
The following are risks specific to our energy business. See page 70 for information about general risks that affect the company as a whole.

Fluctuating power and natural gas market prices
Power and natural gas prices are affected by fluctuations in supply and demand, weather, and by general economic conditions. The power generation facilities in our Western Power operations in Alberta, and in our U.S. Power operations in New England and New York, are exposed to commodity price volatility. Earnings from these businesses are generally correlated to the prevailing power supply and demand conditions and the price of natural gas, as power prices are usually set by gas-fired power supplies. Extended periods of low gas prices will generally exert downward pressure on earnings from these facilities. Our Coolidge Generating Station and our portfolio of assets in Eastern Canada are fully contracted, and are therefore not subject to fluctuating commodity prices. Bruce Power's exposure to fluctuating power prices is discussed further below.

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2012 Management's discussion and analysis -- 59

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To mitigate the impact of power price volatility in Alberta and the U.S. northeast, we sell a portion of our supply under medium to long-term sales contracts where contract terms are acceptable. A portion of our power is retained to be sold in the spot market or under shorter-term forward arrangements to ensure we have adequate power supply to fulfill sales obligations if we have unexpected plant outages. This unsold supply is exposed to fluctuating power and natural gas market prices. As power sales contracts expire, new forward contracts are entered into at prevailing market prices.

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

Our natural gas storage business is subject to fluctuating seasonal natural gas price spreads which are generally determined by the differential in natural gas prices between the traditional summer injection and winter withdrawal seasons.

U.S. Power capacity payments
A portion of revenues earned by our power facilities in New England and a significant portion of revenues earned by Ravenswood are driven by capacity payments. Fluctuations in capacity prices can have a material impact on these businesses, particularly in New York. New York capacity prices are determined by a series of voluntary forward auctions and a mandatory spot auction. The forward auctions are bid based while the mandatory spot auction is affected by a demand curve price setting process that is driven by a number of established parameters that are subject to period review by the New York ISO and FERC. These parameters are determined for each capacity zone and include the forecasted cost of a new unit entering the market, available existing operable supply and fluctuations in forecasted demand. Capacity payments are also a function of plant availability which is discussed below.

Plant availability
Optimizing and maintaining plant availability is essential to the continued success of our Energy business. Unexpected outages or extended planned outages at our power plants can increase maintenance costs, lower plant output and sales revenue and lower capacity payments and margins. We may also have to buy power or natural gas on the spot market to meet our delivery obligations.

We manage this risk by investing in a highly skilled workforce, operating prudently, running comprehensive, risk-based preventive maintenance programs and making effective capital investments.

For facilities we do not operate, our purchase agreements include a financial remedy if a plant owner does not deliver as agreed. The Sundance and Sheerness PPAs, for example, require the producers to pay us market-based penalties if they cannot supply the amount of power we have agreed to buy.

Regulatory
We operate in both regulated and deregulated power markets in both the United States and Canada. These markets are subject to various federal, state and provincial regulations in both countries. As power markets evolve across North America, there is the potential for regulatory bodies to implement new rules that could negatively affect us 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, cost allocations to generators and out-of-market actions taken by others to build excess generation, all of which negatively affect the price of power or capacity, or both. In addition, our development projects rely on an orderly permitting process and any disruption to that process can have negative effects on project schedules and costs. We are an active participant in formal and informal regulatory proceedings and take legal action where required.

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60 -- TransCanada Pipelines Limited

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Weather
Significant changes in temperature and other weather events have many effects on our business, ranging from the impact on demand, availability and commodity prices, to efficiency and output capability.

Extreme temperature and weather can affect market demand for power and natural gas and can lead to significant price volatility. Extreme weather can also restrict the availability of natural gas and power if demand is higher than supply.

Seasonal changes in temperature can reduce the efficiency of our natural gas-fired power plants, and the amount of power they produce. Variable wind speeds affect earnings from our wind assets.

Hydrology
Our hydroelectric power generation facilities in the northeastern U.S. are subject to potential hydrology risks that can impact the volume of water available for generation at these facilities including weather changes and events, local river management and potential dam failures at these plants or upstream facilities.

Execution, capital cost and permitting
Energy's construction programs are subject to execution, capital cost and permitting risks.

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2012 Management's discussion and analysis -- 61

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Corporate

OTHER INCOME STATEMENT ITEMS

year ended December 31 (millions of $)		2012		2011		2010
Comparable interest expense		997		1,046		754
Comparable interest income and other		(86)		(60)		(94)
Comparables income taxes		472		565		387
Net income attributable to non-controlling interests		96		107		93

year ended December 31 (millions of $)		2012		2011		2010
Comparable interest on long-term debt (including interest on junior subordinated notes)
Canadian dollar-denominated		513		490		514
U.S. dollar-denominated		740		734		680
Foreign exchange		–		(7)		20
		1,253		1,217		1,214
Other interest and amortization expense		44		131		127
Capitalized interest		(300)		(302)		(587)
Comparable interest expense		997		1,046		754

Comparable interest expense this year was $49 million lower than 2011 primarily because of lower interest expense on amounts due to TransCanada and the impacts of debt repayments of $980 million and $1,272 million in 2012 and 2011. The decrease was partially offset by incremental interest on debt issues of US$1.0 billion in August 2012, US$500 million in March 2012 and $750 million in November 2011, a TC PipeLines, LP debt issue of US$350 million in June 2011 and the negative impact of a stronger U.S. dollar on U.S. dollar-denominated interest.

In 2011, comparable interest expense increased $292 million compared to 2010 because of a decrease in capitalized interest due to Keystone and Coolidge being placed in service in 2011 and Halton Hills being placed in service in late 2010. Comparable interest expense on U.S. dollar-denominated debt was higher in 2011 than 2010 due to new debt issues of US$1.0 billion in September 2010 and US$1.25 billion in June 2010. This was partially offset by the impact of a weaker U.S. dollar and the decrease in interest expense on Canadian dollar-denominated debt from debt maturities. In 2011, other interest and amortization expense was higher than 2010 because higher interest expense on amounts due to TransCanada, partially offset by gains instead of losses from changes in the fair value of derivatives used to manage our exposure to fluctuating interest rates.

Comparable interest income and other was $26 million higher in 2012 compared to 2011. This increase was mainly because of higher gains in 2012 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income and on translation of foreign denominated working capital balances. In 2011, comparable interest income and other was $34 million lower than 2010 because of lower gains from derivatives used to manage the Company's exposure to foreign exchange rate fluctuations.

Comparable income taxes decreased $93 million in 2012 compared to 2011 mainly because of lower pre-tax earnings. In 2011, comparable income taxes increased $178 million from 2010 because of higher pre-tax earnings in 2011 and higher positive income tax adjustments in 2010 compared to 2011. In 2011 and 2010, we recorded a benefit in current income taxes with an offsetting provision in deferred income taxes due to 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.

Net income attributable to non-controlling interests decreased this year primarily due to lower earnings from Great Lakes.

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62 -- TransCanada Pipelines Limited

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Financial condition

We strive to maintain strong financial capacity and flexibility in all parts of an economic cycle, and rely on our operating cash flows to sustain our business, pay dividends and fund a portion of our growth.

We believe we have the financial capacity to fund our existing capital program through our predictable cash flow from our operations, access to capital markets, cash on hand and substantial committed credit facilities.

We access capital markets to meet our financing needs and manage our capital structure to maintain flexibility and to preserve our credit ratings.

Capital structure

at December 31 (millions of $)		2012		2011
Notes payable		2,275		1,863
Due from TransCanada Corporation		(985)		(750)
Long-term debt		18,913		18,659
Junior subordinated notes		994		1,016
Cash and cash equivalents		(537)		(629)
Debt, net of cash and cash equivalents		20,660		20,159
Equity – controlling interests		18,304		17,932
Equity – non-controlling interests		1,036		1,076
Total equity		19,340		19,008
		40,000		39,167

Consolidated capital structure
at December 31, 2012

1

Net of cash and amounts due from TransCanada Corporation, and excluding junior subordinated notes.

2

Includes non-controlling interests in TC PipeLines, LP and Portland.

The following table shows how we have financed our business activities over the last three years. We continue to fund our extensive capital program through operations and, when needed, through capital markets securities issuances. Dividends paid on our common shares are included in financing activities.

at December 31 (millions of $)		2012		2011		2010
Cash flow from operating activities		3,546		3,567		2,817
Cash flow used in investing activities		(3,256)		(3,054)		(5,296)
Surplus (deficiency)		290		513		(2,479)
Cash flow (used in)/from financing activities		(367)		(536)		2,253
Net cash used		(77)		(23)		(226)

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2012 Management's discussion and analysis -- 63

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Our future liquidity will continue to be comprised of cash flow generated from our operations, committed credit facilities and our ability to access debt and equity markets. Our financial flexibility is further supported by opportunities for portfolio management including potential asset sales to TC PipeLines, LP.

Provisions of various trust indentures and credit arrangements that our subsidiaries are party to restrict those subsidiaries' ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on our ability to declare and pay dividends on our common and preferred shares. In the opinion of management, these provisions do not currently restrict or alter our ability to declare or pay dividends. These trust indentures and credit arrangements also require us to comply with various affirmative and negative covenants and maintain certain financial ratios. As at December 31, 2012, we were in compliance with all of our financial covenants.

Cash from operating activities

year ended December 31 (millions of $)		2012		2011		2010
Funds generated from operations		3,259		3,360		3,109
Decrease/(increase) in operating working capital		287		207		(292)
Net cash from operations		3,546		3,567		2,817

Funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our operations, excluding the timing effects of working capital changes. See page 12 for more information about non-GAAP measures.

At December 31, 2012, our current liabilities were higher than our current assets, leaving us with a working capital deficit of $2.1 billion. This short-term deficiency is considered to be in the normal course of business and is managed through:

•

our ability to generate cash flow from operations

•

our access to approximately $4.7 billion of unutilized, revolving bank lines, and

•

our ongoing access to capital markets.

Cash used in investing activities

year ended December 31 (millions of $)		2012		2011		2010
Capital expenditures		2,595		2,513		4,376
Other investing activities		661		541		920

Our 2012 capital expenditures were primarily focused on expanding our Alberta System and construction of the Gulf Coast Project. Other investing activities in 2012 included our investment in Bruce Power capital projects.

We are developing quality projects under our current $12 billion capital program. These long-life infrastructure assets are supported by long-term commercial arrangements resulting in very predictable future cash flows.

Cash (used in)/from financing activities

year ended December 31 (millions of $)		2012		2011		2010
Long-term debt issued, net of issue costs		1,491		1,622		2,371
Long-term debt repaid		(980)		(1,272)		(494)
Notes payable issued/(repaid), net		449		(224)		472
Dividends and distributions paid		(1,361)		(1,294)		(1,199)
Advance (to)/from parent, net		(235)		(2,090)		116
Equity financing activities		269		2,722		987

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As at December 31, 2012, we had unused capacity of $1.25 billion and US$2.5 billion under our Canadian debt and U.S. debt shelf prospectuses to facilitate future access to the North American debt markets. In January 2013, we issued US$750 million of senior notes, reducing the capacity under our U.S. debt shelf prospectus to US$1.75 billion.

Credit facilities
We use committed, revolving credit facilities to support our commercial paper programs, along with additional demand facilities, for general corporate purposes, including issuing letters of credit and providing additional liquidity.

At December 31, 2012, we had $5.3 billion in unsecured credit facilities, including:

Amount		Unused capacity		Borrower		For		Matures
$2.0 billion		$2.0 billion		TCPL		Committed, revolving, extendible credit facility that supports TCPL's Canadian commercial paper program		October 2017
US$1.0 billion		US$1.0 billion		TransCanada PipeLine USA Ltd. (TCPL USA)		Committed, revolving credit facility that supports a TCPL USA U.S. dollar commercial paper program in the U.S.		October 2013
US$1.0 billion		US$1.0 billion		TransCanada Keystone Pipeline, LP		Committed, revolving, extendible credit facility that supports a U.S. dollar commercial paper program in Canada dedicated to funding a portion of Keystone		November 2013
US$300 million		US$300 million		TCPL USA		Committed, revolving credit facility that matures in first quarter 2013		February 2013
$1.0 billion		$373 million		TCPL		Demand lines for issuing letters of credit and as a source of additional liquidity. At December 31, 2012, we had outstanding $627 million in letters of credit under these lines		Demand

At December 31, 2012, our operated affiliates had $300 million of undrawn capacity on committed credit facilities.

Related Party Debt Financing
Related party debt consists of amounts due from TransCanada.

		Amount		For		Matures
Discount Notes		$2.9 billion		Discount notes issued by TransCanada; used for general corporate purposes.		2013
Credit Facility		$1.2 billion		Demand revolving credit facility arrangement with TransCanada; used for general corporate purposes.		n/a
Credit Facility		$0.7 billion		TransCanada's unsecured credit facility agreement; used to repay indebtedness, make partner contributions to Bruce A, and for working capital and general corporate purposes.		2014

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2012 Management's discussion and analysis -- 65

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Contractual obligations
Payments due (by period)

year ended December 31, 2012 (millions of $)		Total		less than one year		1 - 3 years		3 - 5 years		more than 5 years
Notes payable		2,275		2,275		–		–		–
Long-term debt (includes junior subordinated notes)		19,907		894		2,531		1,769		14,713
Operating leases (future annual payments for various premises, services and equipment, less sub-lease receipts)		747		74		145		155		373
Purchase obligations		8,126		3,012		2,261		1,131		1,722
Other long-term liabilities reflected on the balance sheet		381		9		19		21		332
		31,436		6,264		4,956		3,076		17,140

Our contractual obligations include our long-term debt, operating leases, purchase obligations and other liabilities incurred in our business such as environmental liability funds and employee retirement and post-retirement benefit plans.

Long-term debt
At the end of 2012, we had $18.9 billion of long-term debt and $1.0 billion of junior subordinated notes, compared to $18.7 billion of long-term debt and $1.0 billion of junior subordinated notes at December 31, 2011.

Total notes payable were $2.3 billion, compared to $1.9 billion at the end of 2011.

We attempt to spread out the maturity profile of our debt. The majority of our obligations mature beyond five years with an average term of 12 years.

At December 31, 2012, scheduled principal repayments and interest payments related to long-term debt were as follows:

Principal repayments
Payments due (by period)

year ended December 31, 2012 (millions of $)		Total		less than one year		1 - 3 years		3 - 5 years		more than 5 years
Notes payable		2,275		2,275		–		–		–
Long-term debt		18,913		894		2,531		1,769		13,719
Junior subordinated notes		994		–		–		–		994
		22,182		3,169		2,531		1,769		14,713

Interest payments
Payments due (by period)

year ended December 31, 2012 (millions of $)		Total		less than one year		1 - 3 years		3 - 5 years		more than 5 years
Long-term debt		15,377		1,154		2,125		1,908		10,190
Junior subordinated notes		3,443		63		126		126		3,128
		18,820		1,217		2,251		2,034		13,318

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Operating leases
Our operating leases for premises, services and equipment expire at different times between now and 2052. Some of our operating leases include the option to renew the agreement for one to 10 years.

Our commitments under the Alberta PPAs are considered operating leases. Future payments under these PPAs depend on plant availability, so we do not include them in our summary of future obligations. Our share of power purchased under the PPAs in 2012 was $303 million (2011 – $394 million; 2010 – $363 million).

We have subleased a part of the PPAs to third parties under terms and conditions similar to our own leases.

Purchase obligations
We have purchase obligations that are transacted at market prices and in the normal course of business, including long-term natural gas transportation and purchase arrangements. At December 31, 2012, our operated affiliates had $0.3 billion of undrawn capacity on committed credit facilities.

Payments due (by period)
(not including pension plan contributions)

year ended December 31 (millions of $)		Total		less than one year		1 - 3 years		3 - 5 years		more than 5 years
Natural Gas Pipelines
Transportation by others1		531		112		185		157		77
Capital expenditures2,3		1,322		797		439		86		-
Other		10		2		4		4		-
Oil Pipelines
Capital expenditures2,4		1,732		1,271		461		-		-
Other		40		4		8		8		20
Energy
Commodity purchases5		2,849		388		738		686		1,037
Capital expenditures2,6		62		41		11		10		-
Other7		1,539		377		395		180		587
Corporate
Information technology and other		41		20		20		-		1
		8,126		3,012		2,261		1,131		1,722

1

Rates are primarily based on known 2012 levels. Demand rates may change after 2012. Purchase obligations are based on known or contracted demand volumes only and do not include commodity charges incurred when volumes flow.

2

Amounts are estimates and can vary depending on timing of construction and project enhancements. We expect to fund capital projects with cash from operations, by issuing senior debt and subordinated capital if required, and through portfolio management.

3

Primarily relate to the construction costs of the Alberta System expansion and other natural gas pipeline projects.

4

Primarily relate to Keystone XL and Gulf Coast.

5

Includes fixed and variable components but does not include derivatives. The variable components are estimates and can vary depending on plant production, market prices and regulatory tariffs.

6

Primarily relate to preliminary construction and development costs of Napanee.

7

Includes estimates of certain amounts that may change depending on plant-fired hours, the consumer price index, actual plant maintenance costs, plant salaries and changes in regulated rates for transportation. This also includes the purchase obligation for Ontario Solar.

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2012 Management's discussion and analysis -- 67

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KEY PURCHASE COMMITMENTS

Ontario Solar
In December 2011, we announced an agreement to purchase nine Ontario solar projects with a combined capacity of 86 MW at a cost of approximately $476 million.

We will acquire each project under 20-year purchase plan agreements with the OPA (under Ontario's FIT program) once construction and acceptance testing are complete and operations have begun. We expect the projects to be acquired between first quarter 2013 and late 2014, subject to regulatory approvals.

GUARANTEES

Bruce Power
We and our partners, Cameco Corporation and BPC Generation Infrastructure Trust (BPC), have severally guaranteed one-third of some of Bruce B's contingent financial obligations related to power sales agreements, a lease agreement and contractor services. The Bruce B guarantees have terms to 2018 except for one guarantee with no termination date that has no exposure associated with it.

We and BPC have each severally guaranteed half of certain contingent financial obligations of Bruce A related to a sublease agreement, an agreement with the OPA to restart the Bruce A power generation units, and certain other financial obligations. The Bruce A guarantees have terms to 2019.

At December 31, 2012, our share of the potential exposure under the Bruce A and B guarantees was estimated to be $897 million. The carrying amount of these guarantees was estimated to be $10 million. Our exposure under certain of these guarantees is unlimited.

Other jointly owned entities
We and our partners in certain other jointly owned entities have also guaranteed (jointly, severally, or jointly and severally) the financial performance of these entities relating mainly to redelivery of natural gas, PPA payments and the payment of liabilities. The guarantees have terms ranging from 2013 to 2040.

Our share of the potential exposure under these assurances was estimated at December 31, 2012 to range between $43 million to a maximum of $89 million. The carrying amount of these guarantees was estimated to be $7 million, and is included in other long-term liabilities. In some cases, if we make a payment that exceeds our ownership interest, the additional amount must be reimbursed by our partners.

OBLIGATIONS – PENSION AND OTHER POST-RETIREMENT PLANS
In 2013, we expect to make funding contributions of approximately $71 million to our defined benefit pension plans and other post-retirement benefit plans and approximately $33 million to our savings plan and defined contribution pension plans. We also expect to provide a $59 million letter of credit to a defined benefit plan in lieu of cash funding.

In 2012, we made funding contributions of approximately $90 million to our defined benefit pension plans and other post-retirement benefit plans and approximately $24 million to our savings plan and defined contribution pension plans. We also provided a $48 million letter of credit to a defined benefit plan in lieu of cash funding.

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68 -- TransCanada Pipelines Limited

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Outlook
The next actuarial valuation for our pension and other post-retirement benefit plans will be carried out as at January 1, 2014. Based on current market conditions, we expect funding requirements for these plans to approximate 2012 levels for several years. This will allow us to amortize solvency deficiencies in the plans, in addition to normal funding costs.

Our net benefit cost for our defined benefit and other post-retirement plans increased to $99 million in 2012 from $68 million, mainly due to a lower discount rate used to measure the benefit obligation.

Future net benefit costs and the amount we will need to contribute to fund our plans will depend on a range of factors, including:

•

interest rates

•

actual returns on plan assets

•

changes to actuarial assumptions and plan design

•

actual plan experience versus projections, and

•

amendments to pension plan regulations and legislation.

We do not expect future increases in the level of funding needed to maintain our plans to have a material impact on our liquidity.

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2012 Management's discussion and analysis -- 69

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Other information

RISKS AND RISK MANAGEMENT
The following is a summary of general risks that affect our company. You can find risks specific to each operating business segment in the business segment discussions.

Risk management is integral to the successful operation of our business. Our strategy is to ensure that our risks and related exposures are in line with our business objectives and risk tolerance.

We build risk assessment into our decision-making processes at all levels.

The Board's Governance Committee oversees our risk management activities, including making sure there are appropriate management systems in place to manage our risks, and adequate Board oversight of our risk management policies, programs and practices. Other Board committees oversee specific types of risk: the Audit Committee oversees management's role in monitoring financial risk, the Human Resources Committee oversees executive resourcing and compensation, organizational capabilities and compensation risk, and the Health, Safety and Environment Committee oversees operational, safety and environmental risk through regular reporting from management.

Our executive leadership team is accountable for developing and implementing risk management plans and actions, and effective risk management is reflected in their compensation.

Operational risks

Business interruption
Operational risks, including labour disputes, equipment malfunctions or breakdowns, acts of terror, or natural disasters and other catastrophic events, could decrease revenues, increase costs or result in legal or other expenses, all of which could reduce our earnings. We have incident, emergency and crisis management systems to ensure an effective response to minimize further loss or injuries and to enhance our ability to resume operations. We have comprehensive insurance to mitigate certain of these risks, but insurance does not cover all events in all circumstances. Losses that are not covered by insurance may have an adverse effect on our operations, earnings, cash flow and financial position.

Our reputation and relationships
Stakeholders, such as Aboriginal communities, communities, landowners, governments and government agencies, and environmental non-governmental organizations can have a significant impact on our operations, infrastructure developments and overall reputation. Our Stakeholder Engagement Framework – which we have implemented across the company – is our formal commitment to stakeholder engagement. Our four core values – integrity, collaboration, responsibility and innovation – are at the heart of our commitment to stakeholder engagement, and guide us in our interactions with stakeholders.

Execution and capital costs
Investing in large infrastructure projects involves substantial capital commitments, based on the assumption that the new assets will offer an attractive return on investment in the future. Under some contracts, we share the cost of these risks with customers, in exchange for the potential benefit they will realize when the project is finished. While we carefully consider the expected cost of our capital projects, under some contracts we bear capital cost overrun risk which may decrease our return on these projects.

Cybersecurity
Security threats (including cybersecurity threats) and related disruptions can have a negative impact on our business. We rely on our information technology to process, transmit and store electronic information, including information we use to safely operate our assets. A breach in the security of our information

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70 -- TransCanada Pipelines Limited

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technology could expose our business to a risk of loss, misuse or interruption of critical information and functions that affect operations. This could affect our operations, damage our assets, result in safety incidents, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions and potential litigation, which could have a material adverse effect on our operations, financial position and results of operations.

Pipeline abandonment costs
The NEB's Land Matters Consultation Initiative (LMCI) is an initiative that will require all Canadian pipeline companies regulated by the NEB to set aside funds to cover future abandonment costs.

The NEB provided several key guiding principles during the LMCI process, including the position that abandonment costs are a legitimate cost of providing pipeline service and are recoverable, upon NEB approval, from users of the individual pipeline systems. The first hearing addressing the basis and the approach to the determination of specific pipeline abandonment cost estimates was held in October 2012. Additional hearings and the Board's decisions are scheduled to be completed by June 2014, which implies that 2015 would be the earliest that the collection of funds could begin.

Health, safety and environment
Our approach to managing health and safety and protecting the environment is guided by our HSE commitment statement, which outlines guiding principles for a safe and healthy environment for our employees, contractors and the public, and expresses our commitment to protect the environment.

We are committed to continually improving our occupational health and safety performance, and to promoting safety on and off the job, in the belief that all occupational injuries and illnesses are preventable. We try to work with companies and contractors who share our commitment and approach. We also have environmental controls in place, including physical design, programs, procedures and processes, to help manage the environmental risk factors we are exposed to, including spill and release response.

Management monitors HSE performance and is kept informed about operational issues and initiatives through formal incident and issues management processes and regular reporting.

The safety and integrity of our existing and newly-developed infrastructure is also a top priority. All new assets are designed, constructed and commissioned with full consideration given to safety and integrity, and are brought in service only after all necessary requirements have been satisfied. We expect to spend approximately $402 million in 2013 for pipeline integrity on the pipelines we operate, an increase of $90 million over 2012 primarily due to increased levels of in-line pipeline inspection on all systems as well an increased amount of pipe replacement required due to population encroachment on the pipelines. 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 our earnings. Under the Keystone contracts, pipeline integrity expenditures are recovered through the tolling mechanism and, as a result, these expenditures also have no impact on our earnings. Our pipeline safety record in 2012 continued to be better than industry benchmarks. We experienced no pipeline breaks in 2012 on our operated pipelines.

Spending associated with public safety on the Energy assets is focused primarily on our hydro dams and associated equipment.

Our main environmental risks are:

•

air and greenhouse gas (GHG) emissions

•

product releases, including crude oil and natural gas, into the environment (land, water and air)

•

use, storage and disposal of chemicals, hazardous materials, and

•

compliance with corporate and regulatory policies and requirements.

Environmental compliance and liabilities
Our facilities are subject to stringent federal, state, provincial and local environmental statutes and regulations governing environmental protection, including air and GHG emissions, water quality, wastewater discharges

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2012 Management's discussion and analysis -- 71

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and waste management. Our facilities are required to obtain or comply with a wide variety of environmental registrations, licences, permits and other approvals and requirements. Failure to comply could result in administrative, civil or criminal penalties, remedial requirements or orders for future operations.

We continually monitor our facilities to ensure compliance with all environmental requirements. We routinely monitor proposed changes in environmental policy, legislation and regulation, and where the risks are potentially large or uncertain, we comment on proposals independently or through industry associations.

We are not aware of any material outstanding orders, claims or lawsuits related to releasing or discharging any material into the environment or in connection with environmental protection.

Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and penalties resulting from any failure to comply, and potential limitations on operations.

Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated properties, and with damage claims arising from the contamination of properties.

It is not possible to estimate the amount and timing of all our future expenditures related to environmental matters because:

•

environmental laws and regulations (and interpretation and enforcement of them) can change

•

new claims can be brought against our existing or discontinued assets

•

our pollution control and clean up cost estimates may change, especially when our current estimates are based on preliminary site investigation or agreements

•

we may find new contaminated sites, or what we know about existing sites could change

•

where there is potentially more than one responsible party involved in litigation, we cannot estimate our joint and several liability with certainty.

At December 31, 2012, we had accrued approximately $37 million related to these obligations ($49 million at the end of 2011). This represents the amount that we have estimated that we will need to manage our currently indentified environmental liabilities. We believe that the Company has considered all necessary contingencies and established appropriate reserves for environmental liabilities; however, there is the risk that unforeseen matters may arise requiring us to set aside additional amounts. We adjust this reserve quarterly to account for changes in liabilities.

Emissions regulation risk
We own assets in four regions where there are regulations to address industrial GHG emissions. We have procedures in place to comply with these regulations, including:

•

under the Specified Gas Emitters Regulation in Alberta, industrial facilities with GHG emissions above a certain threshold have to reduce their emissions by 12 per cent below an average intensity baseline. Our Alberta System facilities and Sundance and Sheerness (the coal-fired power facilities we have PPAs with) are subject to this regulation. We recover compliance costs on the Alberta System through the tolls our customers pay. A portion of the compliance costs for Sundance and Sheerness are recovered through market pricing and contract flow through provisions. We recorded $15 million for the Alberta Specified Gas Emitters Regulation in 2012, after contracted cost recovery.

•

B.C. has imposed a tax on carbon dioxide (CO₂) emissions from fossil fuel combustion since 2008. We recover the compliance costs for our compressor and meter stations through the tolls our customers pay. In 2012, we recorded $5 million for the B.C. carbon tax. The cost per tonne of CO₂ increased from $25 to $30 beginning in July 2012

•

Northeastern U.S. states that are members of the Regional Greenhouse Gas Initiative (RGGI) implemented a CO₂ cap-and-trade program for electricity generators beginning January 2009. This program applies to both the Ravenswood and Ocean State Power generation facilities. These costs are generally recovered through the power market, and do not have a significant net impact on our results. We recorded $3 million in 2012 to participate in quarterly auctions of allowances under RGGI

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•

the natural gas distributor in Québec collects a hydrocarbon royalty on behalf of the provincial government through a green fund charge. We recorded less than $1 million for the hydrocarbon royalty related to our Bécancour facility in 2012.

In September 2012, the Government of Canada finalized a GHG regulation for the coal-fired electricity sector. Starting in July 2015, companies will have to meet a new GHG emissions performance standard for new and existing units (equal to approximately the emissions of a combined cycle natural gas-fired electrical generation unit). We do not believe the regulation poses a significant risk or will have a significant financial impact, and it may present opportunities for new power generation investment.

There are also federal, regional, state and provincial initiatives in development. While economic events may significantly affect the scope and timing of new regulations, we anticipate that most of our facilities will be subject to future regulations to manage industrial GHG emissions.

As described in the Business interruption section, above, we have a set of procedures in place to manage our response to natural disasters like forest fires, tornadoes, earthquakes, floods, volcanic eruptions and hurricanes, regardless of how they are caused. The procedures, which are included in the Operating Procedures in our Incident Management System, are designed to help protect the health and safety of our employees, minimize risk to the public and limit the impact any operational issues caused by a natural disaster might have on the environment.

Financial risks
We are exposed to market risk, counterparty credit risk and liquidity risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and ultimately shareholder value.

These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance. We manage market risk and counterparty credit risk within limits that are ultimately established by the Board, implemented by senior management and monitored by our risk management and internal audit groups. Management monitors compliance with market and counterparty risk management policies and procedures, and reviews the adequacy of the risk management framework, overseen by the Audit Committee. Our internal audit group assists the Audit Committee by carrying out regular and ad-hoc reviews of risk management controls and procedures, and reporting up to the Audit Committee.

Market risk
We build and invest in large infrastructure projects, buy and sell energy commodities, issue short-term and long-term debt (including amounts in foreign currencies) and invest in foreign operations. Certain of these activities expose us to market risk from changes in commodity prices and foreign exchange and interest rates which may affect our earnings and the value of the financial instruments we hold.

We use derivative contracts to assist in managing our exposure to market risk, including:

•

forwards and futures contracts – agreements to buy or sell a financial instrument or commodity at a specified price and date in the future. We use foreign exchange and commodity forwards and futures to manage the impact of changes in foreign exchange rates and commodity prices

•

swaps – agreements between two parties to exchange streams of payments over time according to specified terms. We use interest rate, cross-currency and commodity swaps to manage the impact of changes in interest rates, foreign exchange rates and commodity prices

•

options – agreements that give the purchaser the right (but not the obligation) 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. We use option agreements to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

We assess contracts we use to manage market risk to determine whether a contract, or a portion of it, meets the definition of a derivative.

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2012 Management's discussion and analysis -- 73

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Commodity price risk
We are exposed to changes in commodity prices, especially electricity and natural gas, and use several strategies to reduce this exposure, including:

•

committing a portion of expected power supply to fixed price sales contracts of varying terms while reserving a portion of our unsold power supply to mitigate operational and price risk in our asset portfolio

•

purchasing a portion of the natural gas we need to fuel our natural gas-fired power plants in advance or entering into contracts that base the sale price of our electricity on the cost of the natural gas, effectively locking in a margin

•

meeting our power sales commitments using power we generate ourselves or with power we buy at fixed prices, reducing our exposure to changes in commodity prices

•

using derivative instruments to enter into offsetting or back-to-back positions to manage commodity price risk created by certain fixed and variable prices in arrangements for different pricing indices and delivery points.

Foreign exchange and interest rate risk
Certain of our businesses generate income in U.S. dollars, but since we report in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. operations continue to grow, our exposure to changes in currency rates increases. Some of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.

We use foreign exchange derivatives to manage other foreign exchange transactions, including foreign exchange exposures that arise on some of our regulated assets. We defer some of the realized gains and losses on these derivatives as regulatory assets and liabilities until we recover or pay them to shippers according to the terms of the shipping agreements.

We have floating interest rate debt which subjects us to interest rate cash flow risk. We manage this using a combination of interest rate swaps and options.

Average exchange rate – U.S. to Canadian dollars

2012		1.00
2011		0.99
2010		1.03

The impact of changes in the value of the U.S. dollar on our U.S. operations is significantly offset by other U.S. dollar-denominated items, as set out in the table below. Comparable EBIT is a non-GAAP measure. See page 12 for more information.

Significant U.S. dollar-denominated amounts

year ended December 31 (millions of US$)		2012		2011		2010
U.S. and International Natural Gas Pipelines comparable EBIT		660		761		683
U.S. Oil Pipelines comparable EBIT		363		301		-
U.S. Power comparable EBIT		88		164		187
Interest on U.S. dollar-denominated long-term debt		(740)		(734)		(680)
Capitalized interest on U.S. capital expenditures		124		116		290
U.S. non-controlling interests and other		(192)		(192)		(164)
		303		416		316

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

Asset/(liability)

		2012				2011
December 31 (millions of $)		Fair value1		Notional or principal amount		Fair value1		Notional or principal amount
U.S. dollar cross-currency swaps (maturing 2013 to 2019)		82		US$3,800		93		US$3,850
U.S. dollar forward foreign exchange contracts (maturing 2013)		-		US$250		(4)		US$725
		82		US$4,050		89		US$4,575

1

Fair values equal carrying values.

2

Consolidated net income in 2012 included net realized gains of $30 million (2011 – gains of $27 million) related to the interest component of cross-currency swap settlements.

U.S. dollar-denominated debt designated as a net investment hedge

at December 31 (billions of $)		2012		2011
Carrying value		$11.1 (US$11.2)		$10 (US$9.8)
Fair value		$14.3 (US$14.4)		$12.7 (US$12.5)

Fair value of derivatives used to hedge our U.S. dollar investment in foreign operations

at December 31 (millions of $)		2012		2011
Other current assets		71		79
Intangibles and other		47		66
Accounts payable		6		15
Deferred amounts		30		41

Counterparty credit risk
We have exposure to counterparty credit risk in the following areas:

•

accounts receivable

•

portfolio investments

•

the fair value of derivative assets

•

notes receivable.

If a counterparty fails to meet its financial obligations to us according to the terms and conditions of the financial instrument, we could experience a financial loss. We manage our exposure to this potential loss using recognized credit management techniques, including:

•

dealing with creditworthy counterparties – a significant amount of our credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties

•

setting limits on the amount we can transact with any one counterparty – we monitor and manage the concentration of risk exposure with any one counterparty, and reduce our exposure when we feel we need to and when it is allowed under the terms of our contracts

•

using contract netting arrangements and obtaining financial assurances, like guarantees, letters of credit or cash, when it is available and we believe it is necessary.

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2012 Management's discussion and analysis -- 75

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There is no guarantee, however, these techniques will protect us from material losses.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. We had no significant credit losses in 2012 and no significant amounts past due or impaired at year end. We had a credit risk concentration of $259 million with one counterparty ($274 million in 2011). This amount is secured by a guarantee from the counterparty's parent company and we anticipate collecting the full amount.

We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.

Liquidity risk
Liquidity risk is the risk that we will not be able to meet our financial obligations as they come due. We manage our liquidity by continuously forecasting our cash flow for a 12 month period and making sure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.

See page 63 financial condition for more information about our liquidity.

Dealing with legal proceedings
Legal proceedings, arbitrations and actions are part of doing business. The most significant this year were the TransAlta Sundance A claims, which were resolved through a binding arbitration process that resulted in a decision in July 2012. See page 57 for more information.

While we cannot predict the final outcomes of proceedings and actions with certainty, management does not expect any current proceeding or action to have a material impact on our consolidated financial position, results of operations or liquidity. We are not aware of any potential legal proceeding or action that would have a material impact on our consolidated financial position, results of operations or liquidity.

CONTROLS AND PROCEDURES
We meet Canadian and U.S. regulatory requirements for disclosure controls and procedures, internal control over financial reporting and related CEO and CFO certifications.

Disclosure controls and procedures
Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as at December 31, 2012, as required by the Canadian securities regulatory authorities and by the SEC.

They concluded that:

•

our disclosure controls and procedures were effective in providing reasonable assurance that the information we are required to disclose in reports we file with or send to securities regulatory authorities is compiled and communicated to management (including the President and CEO and the CFO as required) so management can make timely decisions about our disclosure and information is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws.

•

our internal control over financial reporting is effective as it is reliable and provides reasonable assurance that our financial reporting and the preparation of our consolidated financial statements for external reporting purposes is in accordance with U.S. GAAP. Management conducted this evaluation based on the framework in Internal control – integrated framework, a publication issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Internal control over financial reporting is a process designed by or supervised by management and involves our Board, Audit Committee, management and other employees.

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There was no change in our internal control over financial reporting in 2012 that had or is likely to have a material impact. Note that no matter how well-designed, internal control over financial reporting has inherent limitations, and management can only provide reasonable assurance about the reliability of the preparation and presentation of financial statements for external reporting.

CEO AND CFO CERTIFICATIONS
Our President and CEO and our CFO have attested to the quality of the public disclosure in our fiscal 2012 reports filed with Canadian securities regulators and the SEC, and have filed certifications with them.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgment. We also regularly assess the assets and liabilities themselves.

You can find a summary of our significant accounting policies in Note 2 to the consolidated financial statements for the year ended December 31, 2012.

The following accounting policies and estimates require us to make the most significant assumptions when preparing our financial statements and changes in these assumptions could have a material impact on the financial statements.

Rate-regulated accounting
Under U.S. GAAP, a company qualifies to use rate-regulated accounting when it meets three criteria:

•

a regulator must establish or approve the rates for the regulated services or activities

•

the regulated rates must be designed to recover the cost of providing the services or products, and

•

it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers because of the demand for services or products and the level of direct and indirect competition.

We believe that the regulated natural gas pipelines we account for using rate-regulated accounting meet these criteria. The most significant impact of using these principles is the timing of when we recognize certain expenses and revenues, which is based on the economic impact of the regulators' decisions about our revenues and tolls, and may be different from what would otherwise be expected under U.S. GAAP. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods. Regulatory liabilities are amounts that are expected to be refunded through customer rates in future periods.

Regulatory assets and liabilities

at December 31 (millions of $)			2012		2011
Regulatory assets
	Regulatory assets		1,629		1,684
	Other current assets		178		178
Regulatory liabilities
	Regulatory liabilities		268		297
	Accounts payable		100		139

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2012 Management's discussion and analysis -- 77

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Depreciation and amortization
Total depreciation and amortization expense in 2012 was $1,375 million (2011 – $1,328 million; 2010 – $1,160 million). Each segment has recorded their portion of this amount.

We depreciate our plant, property and equipment on a straight-line basis over their estimated useful lives once they are ready for their intended use. We estimate their useful lives based on third-party engineering studies, experience and industry practice. When changes to the estimated service lives occur, the change is applied prospectively over the remaining expected useful life, which would result in a change to the depreciation expense in future periods.

We use various rates to calculate the depreciation of different kinds of company assets:

Asset type		Annual rate of depreciation
Natural gas pipeline and compression equipment		1% – 6%
Oil pipeline and pumping equipment		Approximately 2% – 2.5%
Metering and other plant equipment		Various rates
Major power generation and natural gas storage plant, equipment and structures in the energy business		2% – 20%
Other energy equipment		Various rates
Corporate plant, property and equipment		3% – 20%

Natural Gas Pipelines
Regulators for our natural gas pipelines business approve our depreciation rates, which allows us to recover the expense of depreciation from our customers as a cost of providing services. As a result, changes in the estimate of the useful lives of plant, property and equipment have no material impact on net income but have a direct effect on funds generated from operations.

Energy
In addition to the depreciation of our energy assets, we deferred and amortize the initial payment for our PPAs on a straight-line basis over the terms of the contracts, which expire in 2017 and 2020. We included a PPA amortization expense of $52 million in Energy's depreciation and amortization expense for 2010 through 2012.

Impairment of long-lived assets and goodwill
We review long-lived assets (such as plant, property and equipment) and intangible assets for impairment whenever events or changes in circumstances lead us to believe we might not be able to recover an asset's carrying value. If the total of the undiscounted future cash flows we estimate for an asset is less than its carrying value, we consider its fair value to be less than its carrying value, and we calculate an impairment loss to recognize this.

Goodwill
As at December 31, 2012, we reported total goodwill of $3.5 billion (2011 – $3.5 billion).

We test goodwill for impairment annually or more frequently if events or changes in circumstances lead us to believe it might be impaired. We assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired, and if we conclude that it is more likely than not that the fair value of the reporting unit is greater than its carrying value, we use a two-step process to test for impairment:

1.

First, we compare the fair value of the reporting unit, including its goodwill, to its book value. If fair value is less than book value, we consider our goodwill to be impaired.

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2.

Next, we measure the amount of the impairment by calculating the implied fair value of the reporting unit's goodwill. We do this by deducting the fair value of the tangible and intangible net assets of the reporting units from the fair value we calculated in the first step. If the goodwill's carrying value exceeds its implied fair value, we record an impairment charge.

We base these valuations on our projections of future cash flows, which involves making estimates and assumptions about:

•

discount rates

•

commodity and capacity prices

•

market supply and demand assumptions

•

growth opportunities

•

output levels

•

competition from other companies, and

•

regulatory changes.

If our assumptions change significantly, our requirement to record an impairment charge could also change. There is a risk that adverse changes in key assumptions could result in a future impairment of a portion of the goodwill balance relating to Great Lakes. These assumptions could be negatively impacted by factors including weather, levels of natural gas in storage, the outcome of the 2013 Natural Gas Act Section 4 general rate case and the outcome of the Canadian Restructuring Proposal. Our share of the goodwill related to Great Lakes, net of non-controlling interests, was US$266 million at December 31, 2012 (2011 – US$266 million).

Employee post-retirement benefits
We sponsor defined benefit pension plans, defined contribution plans, a savings plan and other post-retirement benefit plans. We expense contributions we make to these plans, except for our defined benefit plans, in the period we make contributions. We estimate the cost of the defined benefit plans and other post-retirement benefits actuarially, based on service and management's best estimate of expected plan investment performance, salary increases, employee retirement age and expected health care costs. Changes in these estimates could result in a change in the expense and liability amounts.

We measure the assets in the defined benefit plans at fair value, and calculate our expected returns using market-related values based on a five-year moving average for all of the defined benefit plans' assets on a plan-by-plan basis. We amortize past service costs over the expected average remaining service life of the employees, and amortize adjustments arising from plan amendments on a straight-line basis over the average remaining service period of employees active at the date of amendment. Future pension expense and funding could be impacted by changes in plan asset returns, assumed discount rates and other factors dependent on the participants of our plans. We recognize the overfunded or underfunded status of the defined benefit plans as an asset or liability on the balance sheet, and recognize changes in this status through other comprehensive income (loss) (OCI) in the year the change occurs. When net actuarial gains or losses are higher than 10 per cent of the benefit obligation (or the market-related value of the plan's assets, whichever is higher), we amortize the difference in accumulated other comprehensive income (loss)/income (AOCI) over the average remaining service period of the active employees.

In some of our regulated operations, we can recover some post-retirement benefit amounts through tolls as benefits are funded.

We record unrecognized gains and losses, or changes in actuarial assumptions related to our post-retirement benefit plans, as either regulatory assets or liabilities, and amortize them on a straight-line basis over the average remaining service life of active employees.

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2012 Management's discussion and analysis -- 79

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Asset retirement obligations
When there is a legal obligation to set aside funds to cover future abandonment costs, and we can reasonably estimate them, we recognize the fair value of the asset retirement obligation in our financial statements.

We cannot determine when we will retire many of our hydro-electric power plants, oil pipelines, natural gas pipelines and transportation facilities and regulated natural gas storage systems because we intend to operate them as long as there is supply and demand, and so we have not recorded obligations for them.

For those we do record, we use the following assumptions:

•

when we expect to retire the asset

•

the scope of abandonment and reclamation activities that are required

•

inflation and discount rates.

The ARO is initially recorded when the obligation exists and is subsequently accreted through charges to operating expenses.

We continue to evaluate our future abandonment obligations and costs and monitor developments that could affect the amounts we record.

Canadian regulated pipelines
The NEB's LMCI is an initiative for all pipeline companies regulated under the National Energy Board Act (Canada) to begin collecting and setting aside funds to cover future abandonment costs.

As part of the guidance provided by the initiative, the NEB has stated that abandonment costs are a legitimate cost of providing pipeline service and should be recoverable (with NEB approval) from system users.

In May 2009, the NEB established several filing deadlines for pipeline companies, including deadlines for

•

estimating their pipeline abandonment costs

•

proposing how they will collect these funds (through tolls or another satisfactory method)

•

proposing how they will set aside the funds they collect.

We filed estimates for our regulated Canadian oil and natural gas pipelines in November 2011 as required. Based on the NEB's direction in 2009, the soonest we could begin collecting funds through cost of service tolls would be 2015. The specific impacts on tolls will be the subject of an NEB filing expected in May 2013.

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FINANCIAL INSTRUMENTS
All financial instruments, including both derivative and non-derivative financial instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchases and normal sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.

We apply hedge accounting to derivative instruments that qualify. We recognize three kinds of hedges including fair value and cash flow hedges, and hedges of foreign currency exposures of net investments in foreign operations. Changes in fair value are recorded according to the accounting rules that apply as outlined in the table below. Hedge accounting is discontinued prospectively if the hedging relationship is no longer effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise.

Type of hedge		How we record derivative instruments in hedging relationships
Fair value hedge		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. To the extent that the hedging relationship is effective, changes in the fair value of the hedged item are offset by changes in the fair value of the hedging derivative, 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. When fair value hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments are amortized to net income over the remaining term of the original hedging relationship.
Cash flow hedge		We recognize the effective portion of the change in the fair value of the hedging derivative initially in OCI, and any ineffective portion is recognized in net income in the same financial statement category as the underlying transaction. When cash flow hedge accounting is discontinued, the amounts previously in AOCI are reclassified to revenues, interest expense and interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or the original hedged item settles. When the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur, we immediately reclassify any gains and losses from AOCI to net income.
Hedge of foreign currency exposure for net investments in foreign operations		We recognize the effective portion of foreign exchange gains and losses on the hedging instruments in OCI and the ineffective portion in interest income and other.

In some cases, derivatives do not meet the specific criteria for hedge accounting treatment, and the changes in fair value are recorded in net income in the period of change. This may expose us to increased variability in reported operating results because the fair value of the derivative instruments can fluctuate significantly from period to period; however, we enter into the arrangements as they are considered to be effective economic hedges.

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 clearly and 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 a derivative or accounted for at fair value. Changes in the fair value of embedded derivatives are included in net income.

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2012 Management's discussion and analysis -- 81

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The recognition of gains and losses on the derivatives for the Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of rate regulated accounting, including those that qualify for hedge accounting treatment, can be recovered through the tolls charged by us. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles.

Fair values

Non-derivative Instruments
Certain financial instruments including cash and cash equivalents, accounts receivable, intangibles and other assets, notes payable, accounts payable, accrued interest and other long-term liabilities 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 our notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt has been estimated based on quoted market prices for the same or similar debt instruments. The fair value of available for sale assets has been calculated using quoted market prices where available.

Derivative Instruments
The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair values of power and natural gas derivatives 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.

Credit risk has been taken into consideration when calculating the fair value of derivatives, notes receivable and long-term debt.

Non-derivative financial instruments summary

		2012				2011
at December 31 (millions of $)		Carrying amount1		Fair value2		Carrying amount1		Fair value2
Financial assets
Cash and cash equivalents		537		537		629		629
Accounts receivable and other3		1,324		1,373		1,378		1,422
Due from TransCanada Corporation		985		985		750		750
Available for sale assets3		44		44		23		23
		2,890		2,939		2,780		2,824
Financial liabilities4
Notes payable		2,275		2,275		1,863		1,863
Accounts payable and deferred amounts5		1,535		1,535		1,330		1,330
Accrued interest		370		370		367		367
Long-term debt		18,913		24,573		18,659		23,757
Junior subordinated notes		994		1,054		1,016		1,027
		24,087		29,807		23,235		28,344

1

Recorded at amortized cost, except for US$350 million (2011 – US$350 million) of long-term debt that is attributed to hedged risk and recorded at fair value. This debt, which is recorded at fair value on a recurring basis, is classified in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers.

2

The fair value measurement of financial assets and liabilities recorded at amortized cost for which fair value is not equal to the carrying value would be included in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers.

3

At December 31, 2012, the consolidated balance sheet included financial assets of $1.1 billion (2011 – $1.1 billion) in accounts receivable, $40 million (2011 – $41 million) in other current assets and $240 million (2011 – $247 million) in intangible and other assets.

4

Consolidated net income in 2012 included losses of $10 million (2011 – losses of $13 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationship on US$350 million of debt at December 31, 2012 (2011 – US$350 million). There were no other unrealized gains or losses from fair value adjustments to non-derivative financial instruments.

5

At December 31, 2012, the consolidated balance sheet included financial liabilities of $1.5 billion (2011 – $1.2 billion) in accounts payable, and $38 million (2011 – $137 million) in other long-term liabilities.

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Contractual repayments of non-derivative financial liabilities – Principal and interest payments due by period

at December 31, 2012 (millions of $)		Total		2013		2014 and 2015		2016 and 2017		2018 and thereafter
Notes payable		2,275		2,275		-		-		-
Long-term debt		18,913		894		2,531		1,769		13,719
Junior subordinated notes		994		-		-		-		994
		22,182		3,169		2,531		1,769		14,713

Interest payments on non-derivative financial liabilities – Principal and interest payments due by period

at December 31, 2012 (millions of $)		Total		2013		2014 and 2015		2016 and 2017		2018 and thereafter
Long-term debt		15,377		1,154		2,125		1,908		10,190
Junior subordinated notes		3,443		63		126		126		3,128
		18,820		1,217		2,251		2,034		13,318

2012 Derivative instruments summary
The following summary does not include hedges of our net investment in foreign operations.

(millions of $, except where noted)				Power		Natural gas		Foreign exchange		Interest
Derivative instruments held for trading1
Fair values2
	Assets			$139		$88		$1		$14
	Liabilities			$(176)		$(104)		$(2)		$(14)
Notional values
	Volumes3
		Purchases		31,135		83		-		-
		Sales		31,066		65		-		-
	Canadian dollars			-		-		-		620
	U.S. dollars			-		-		US1,408		US200
	Cross-currency			-		-		-		-
Net unrealized (losses)/gains in the year4				$(30)		$2		$(1)		$-
Net realized gains/(losses) in the year4				$5		$(10)		$26		$-
Maturity dates				2013 – 2017		2013 – 2016		2013		2013 – 2016
Derivative instruments in hedging relationships5,6
Fair values2
	Assets			$76		$–		$–		$10
	Liabilities			$(97)		$(2)		$(38)		$–
Notional values
	Volumes3
		Purchases		15,184		1		-		-
		Sales		7,200		-		-		-
	U.S. dollars			-		-		US12		US350
	Cross-currency			-		-		136/US100		-
Net realized (losses)/gains in the year4				$(130)		$(23)		$-		$7
Maturity dates				2013 – 2018		2013		2013 – 2014		2013 – 2015

1

All derivative instruments held for trading have been entered into for risk management purposes and are subject to our risk management strategies, policies and limits. This includes 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 our exposure 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 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 $10 million and a notional amount of US$350 million. In 2012, net realized gains on fair value hedges were $7 million and were included in interest expense. In 2012, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

6

In 2012, 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.

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2012 Management's discussion and analysis -- 83

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The anticipated timing of settlement of the derivative instruments assumes constant commodity prices, interest rates and foreign exchange rates at December 31, 2012. Settlements will vary based on the actual value of these factors at the date of settlement.

Anticipated timing of settlement – derivative instruments

at December 31, 2012 (millions of $)			Total		2013		2014 and 2015		2016 and 2017		2018 and thereafter
Anticipated timing of settlement – derivative contracts
Derivative instruments held for trading
	Assets		242		141		99		2		-
	Liabilities		(296)		(175)		(117)		(4)		-
Derivative instruments in hedging relationships
	Assets		204		117		85		2		-
	Liabilities		(173)		(105)		(55)		(11)		(2)
			(23)		(22)		12		(11)		(2)

2011 Derivative instruments summary
The following summary does not include hedges of our net investment in foreign operation.

(millions of $, except where noted)				Power		Natural gas		Foreign exchange		Interest
Derivative instruments held for trading1
Fair values2
	Assets			$185		$176		$3		$22
	Liabilities			$(192)		$(212)		$(14)		$(22)
Notional values
	Volumes3
		Purchases		21,905		103		-		-
		Sales		21,334		82		-		-
	Canadian dollars			-		-		-		684
	U.S. dollars			-		-		US1,269		US250
	Cross-currency			-		-		47/US37		-
Net unrealized (losses)/gains in the year4				$(2)		$(50)		$(4)		$1
Net realized gains/(losses) in the year4				$42		$(74)		$10		$1
Maturity dates				2012 – 2016		2012 – 2016		2012		2012 – 2016
Derivative instruments in hedging relationships5,6
Fair values2
	Assets			$16		$3		$-		$13
	Liabilities			$(277)		$(22)		$(38)		$(1)
Notional values
	Volumes3
		Purchases		17,188		8		-		-
		Sales		8,061		-		-		-
	U.S. dollars			-		-		US73		US600
	Cross-currency			-		-		136/US100		-
Net realized losses in the year4				$(165)		$(17)		$-		$(16)
Maturity dates				2012 – 2017		2012 – 2013		2012 – 2014		2012 – 2015

1

All derivative instruments held for trading have been entered into for risk management purposes and are subject to our 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 our 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 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 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 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, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

6

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.

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84 -- TransCanada Pipelines Limited

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Balance sheet presentation of derivative financial instruments
The fair value of the derivative financial instruments on the balance sheet.

at December 31 (millions of $)		2012		2011
Current
Other current assets		259		361
Accounts payable and other		(283)		(485)
Long term
Intangibles and other assets		187		202
Other long-term liabilities		(186)		(349)

Derivatives in cash flow hedging relationships
The components of OCI related to derivatives in cash flow hedging relationships.

Cash flow hedges¹

year ended December 31 (millions of $,		Power				Natural gas				Foreign exchange				Interest
pre-tax)		2012		2011		2012		2011		2012		2011		2012		2011
Change in fair value of derivative instruments recognized in OCI (effective portion)		83		(263)		(21)		(59)		(1)		5		-		(1)
Reclassification of gains and losses on derivative instruments from AOCI to Net Income (effective portion)		147		81		54		100		-		-		18		43
Gains and losses on derivative instruments recognized in earnings (ineffective portion)		7		-		-		-		-		-		-		-

1

No amounts have been excluded from the assessment of hedge effectiveness.

Credit risk related contingent features
Derivatives often contain financial assurance provisions that may require us to provide collateral if a credit risk-related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade). We may also need to provide collateral if the fair value of our derivative financial instruments exceeds pre-defined exposure limits.

Based on contracts in place and market prices at December 31, 2012, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $37 million (2011 – $110 million), with collateral provided in the normal course of business of nil (2011 – $28 million).

If the credit-risk-related contingent features in these agreements were triggered on December 31, 2012, we would have been required to provide additional collateral of $37 million (2011 – $82 million) to our counterparties. We have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

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2012 Management's discussion and analysis -- 85

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Fair value hierarchy
Financial assets and liabilities that are recorded at fair value are required to be categorized into three levels based on a fair value hierarchy.

Levels	How fair value has been determined
Level I	Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.
Level II	Valuation based on the extrapolation of inputs other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and power and natural gas commodity derivatives where fair value is determined using the market approach.
Level III	Valuation of assets and liabilities measured on a recurring basis using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. This category includes long-dated commodity transactions in certain markets where liquidity is low. Long term electricity prices are estimated using a third-party modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which we operate. Inputs into the model include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices are based on a view of future natural gas supply and demand, as well as exploration and development costs. Significant decreases in fuel prices or demand for electricity or natural gas, or increases in the supply of electricity or natural gas would result in a lower fair value measurement of contracts included in Level III.

Financial assets and liabilities measured on a recurring basis
Current and non-current portions

			Quoted prices in active markets (Level I)1				Significant other observable inputs (Level II)1,2				Significant unobservable inputs (Level III)2				Total
at December 31 (millions of $, pre-tax)			2012		2011		2012		2011		2012		2011		2012		2011
Derivative instrument assets:
	Interest rate contracts		-		-		24		35		-		-		24		35
	Foreign exchange contracts		-		-		119		142		-		-		119		142
	Power commodity contracts		-		-		213		201		2		-		215		201
	Gas commodity contracts		75		124		13		55		-		-		88		179
Derivative instrument liabilities:
	Interest rate contracts		-		-		(14)		(23)		-		-		(14)		(23)
	Foreign exchange contracts		-		-		(76)		(102)		-		-		(76)		(102)
	Power commodity contracts		-		-		(269)		(454)		(4)		(15)		(273)		(469)
	Gas commodity contracts		(95)		(208)		(11)		(26)		-		-		(106)		(234)
Non-derivative financial instruments:
	Available-for-sale assets		44		23		-		-		-		-		44		23
			24		(61)		(1)		(172)		(2)		(15)		21		(248)

1

Transfers between Level I and Level II would occur when there is a change in market circumstances. There were no transfers between Level I and Level II in 2012 and 2011.

2

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. As contracts near maturity and observable market data become available, they are transferred out of Level III and into Level II. There were no transfers out of Level II and into Level III in 2012 and 2011.

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86 -- TransCanada Pipelines Limited

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Net change in the Level III fair value category

(millions of $, pre-tax)		Derivatives1,2
Balance at December 31, 2010		(8)
New contracts		1
Settlements		2
Transfers out of Level III		3
Total gains/(losses) included in OCI		(13)
Balance at December 31, 2011		(15)
Settlements		(1)
Transfers out of Level III		(21)
Total gains included in net income		11
Total gains/(losses) included in OCI		24
Balance at December 31, 2012		(2)

1

The fair value of derivative assets and liabilities is presented on a net basis.

2

At December 31, 2012, there were unrealized gains included in net income attributed to derivatives that were still held at the reporting date of $1 million (2011 – nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $4 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III at December 31, 2012.

ACCOUNTING CHANGES

Changes in accounting policies for 2012

Fair value measurement
We adopted the Financial Accounting Standards Board's (FASB) accounting standards update on fair value measurements, and increased our qualitative and quantitative disclosures about Level III measurements effective January 1, 2012.

Intangibles – goodwill
We adopted the FASB accounting standards update on testing goodwill for impairment, and changed our accounting policy related to testing goodwill for impairment effective January 1, 2012. We now assess qualitative factors affecting the fair value of a reporting unit compared to its carrying amount first, before deciding whether to proceed to the two-step quantitative impairment test. The adoption of this standard and our assessment of goodwill in 2012 did not result in any finding of impairment. For further information see impairment of long-lived assets and goodwill on page 78.

Future accounting changes

Balance sheet offsetting/netting
In December 2011, the FASB issued an amendment requiring companies to provide disclosure that will help readers understand the effect, or potential effect, of netting arrangements on the company's financial position. This guidance, which will be effective for annual periods beginning on or after January 1, 2013, will require us to include additional information about financial instruments and derivative instruments that are either offset in accordance with current U.S. GAAP or subject to an enforceable master netting arrangement, or other similar agreement.

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2012 Management's discussion and analysis -- 87

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QUARTERLY RESULTS

Selected quarterly consolidated financial data
(unaudited, millions of $, except per share amounts)

2012			Fourth		Third		Second		First
Revenues			2,089		2,126		1,847		1,945
Net income attributable to common shares			315		379		282		362
Share statistics
	Net income per share – basic and diluted		$0.43		$0.51		$0.38		$0.49

2011			Fourth		Third		Second		First
Revenues			2,015		2,043		1,851		1,930
Net income attributable to common shares			372		379		348		404
Share statistics
	Net income per share – basic and diluted		$0.54		$0.56		$0.52		$0.60

Factors affecting quarterly financial information by business segment
Quarter-over-quarter revenues and net income fluctuate for reasons that vary across our business segments.

In Natural Gas Pipelines, except for seasonal fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:

•

regulators' decisions

•

negotiated settlements with shippers

•

acquisitions and divestitures

•

developments outside of the normal course of operations

•

newly constructed assets being placed in service.

In Oil Pipelines, 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.

In Energy, quarter-over-quarter revenues and net income are affected by:

•

weather

•

customer demand

•

market prices for natural gas and energy

•

capacity prices and payments

•

planned and unplanned plant outages

•

acquisitions and divestitures

•

certain fair value adjustments

•

developments outside of the normal course of operations

•

newly constructed assets being placed in service.

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88 -- TransCanada Pipelines Limited

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Factors affecting financial information by quarter

Fourth quarter 2012

•

EBIT included net unrealized losses of $17 million pre-tax ($12 million after-tax) from certain risk management activities.

Third quarter 2012

•

EBIT included net unrealized gains of $31 million pre-tax ($20 million after tax) from certain risk management activities.

Second quarter 2012

•

EBIT included a $50 million pre-tax charge ($37 million after tax) from the Sundance A PPA arbitration decision, and net unrealized losses of $14 million pre-tax ($13 million after tax) from certain risk management activities.

First quarter 2012

•

EBIT included net unrealized losses of $22 million pre-tax ($11 million after tax) from certain risk management activities.

Fourth quarter 2011

•

EBIT included net unrealized after-tax gains of $11 million ($13 million pre-tax) resulting from certain risk management activities.

Third quarter 2011

•

EBIT included net unrealized losses of $43 million pre-tax ($30 million after tax) resulting from certain risk management activities.

Second quarter 2011

•

EBIT included net unrealized losses of $3 million pre-tax ($2 million after tax) resulting from certain risk management activities.

First quarter 2011

•

EBIT included net unrealized losses of $19 million pre-tax ($12 million after tax) resulting from certain risk management activities.

•

Natural Gas Pipelines EBIT included incremental earnings from Bison, which we placed in service in January 2011.

•

Oil Pipelines began recording EBIT for the Keystone Pipeline System in February 2011.

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2012 Management's discussion and analysis -- 89

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FOURTH QUARTER 2012 HIGHLIGHTS

Reconciliation of non-GAAP measures

Three months ended December 31 (unaudited) (millions of $)			2012		2011
Comparable EBITDA			1,052		1,120
Depreciation and amortization			(343)		(341)
Comparable EBIT			709		779
Other income statement items
Comparable interest expense			(252)		(276)
Comparable interest income and other			20		8
Comparable income taxes			(122)		(117)
Net income attributable to non-controlling interests			(23)		(28)
Preferred share dividends			(5)		(5)
Comparable earnings			327		361
Specific item (net of tax)
	Risk management activities1		(12)		11
Net income attributable to common shares			315		372
Comparable interest expense			(252)		(276)
Specific item:
	Risk management activities		-		-
Interest expense			(252)		(276)
Comparable interest income and other			20		8
Specific item
	Risk management activities1		(5)		35
Interest income and other			15		43
Comparable income taxes			(122)		(117)
Specific item
	Risk management activities1		5		(2)
Income taxes expense			(117)		(119)

1

Three months ended December 31

(unaudited) (millions of $)		2012		2011
Risk management activities gains/(losses):
Canadian Power		(6)		-
U.S. Power		(5)		(33)
Natural Gas Storage		(1)		11
Interest rate		-		-
Foreign exchange		(5)		35
Income taxes attributable to risk management activities		5		(2)
Risk management activities		(12)		11

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90 -- TransCanada Pipelines Limited

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EBITDA and EBIT by Business Segment

Three months ended December 31, 2012 (unaudited) (millions of $)		Natural Gas Pipelines		Oil Pipelines		Energy		Corporate		Total
Comparable EBITDA		690		172		222		(32)		1,052
Depreciation and amortization		(236)		(36)		(68)		(3)		(343)
Comparable EBIT		454		136		154		(35)		709

Three months ended December 31, 2011 (unaudited) (millions of $)		Natural Gas Pipelines		Oil Pipelines		Energy		Corporate		Total
Comparable EBITDA		716		179		254		(29)		1,120
Depreciation and amortization		(235)		(35)		(67)		(4)		(341)
Comparable EBIT		481		144		187		(33)		779

Highlights by line item

Comparable earnings
Comparable earnings in fourth quarter 2012 were $327 million compared to $361 million for the same period in 2011. Comparable earnings excluded net unrealized after-tax losses of $12 million ($17 million pre-tax) (2011 – $11 million after-tax gains; $13 million pre-tax) resulting from changes in the fair value of certain risk management activities.

Comparable earnings decreased $34 million in fourth quarter 2012 compared to the same period in 2011 and included the following:

•

decreased Canadian Natural Gas Pipelines net income primarily due to lower earnings from the Canadian Mainline which excluded incentive earnings and reflected a lower investment base;

•

decreased U.S. and International Natural Gas Pipelines comparable EBIT primarily due to lower revenues on Great Lakes due to uncontracted capacity and lower rates as well as lower revenues and higher costs on ANR;

•

decreased Oil Pipelines comparable EBIT which reflected increased business development activity and related costs;

•

decreased Energy comparable EBIT as a result of the Sundance A PPA force majeure as well as decreases and lower equity earnings from ASTC Power Partnership resulting from an unfavourable Sundance B PPA arbitration decision. These decreases were partially offset by higher contributions from Eastern Power due to incremental earnings from Cartier Wind as well as from U.S. Power due to higher generation volumes and realized power and capacity prices in New York; and

•

increased comparable interest income and other due to higher realized gains in 2012 compared to losses in 2011 on derivatives used to manage our exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Net income attributable to common shares
Our net income attributable to common shares was $315 million in fourth quarter 2012 compared to $372 million for the same period in 2011.

Highlights by business segment

Natural Gas Pipelines
Natural Gas Pipelines comparable EBIT was $454 million in fourth quarter 2012 compared to $481 million for the same period in 2011. This decrease was primarily due to lower earnings from the Canadian Mainline which excluded incentive earnings and reflected a lower investment base and lower contributions from Great Lakes and ANR partially offset by higher earnings from the Alberta System.

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2012 Management's discussion and analysis -- 91

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Natural Gas Pipelines business development comparable EBITDA was $4 million in fourth quarter 2012 compared to $15 million for the same period in 2011. This decrease was primarily related to reduced activity in 2012 for the Alaska Pipeline Project.

Canadian Pipelines
Canadian Mainline's net income of $47 million in fourth quarter 2012 decreased $13 million compared to the same period in 2011. Canadian Mainline's net income for fourth quarter 2011 included incentive earnings earned under an incentive arrangement in the five-year tolls settlement that expired December 31, 2011. In the absence of a NEB decision with respect to the 2012-2013 tolls application, Canadian Mainline's 2012 quarterly results reflected the last approved ROE of 8.08 per cent on deemed common equity of 40 per cent and exclude incentive earnings. In addition, Canadian Mainline's fourth quarter 2012 net income decreased as a result of a lower average investment base compared to the prior year.

The Alberta System's net income of $55 million in fourth quarter 2012 increased by $4 million compared to the same period in 2011. The increase in 2012 net income was from a higher average investment base and was partially offset by lower incentive earnings.

Canadian Mainline's comparable EBITDA for fourth quarter 2012 of $250 million decreased $12 million compared to $262 million in the same period in 2011. The Alberta System's comparable EBITDA was $195 million for fourth quarter 2012 compared to $185 million in the same period in 2011. EBITDA from the Canadian Mainline and the Alberta System reflect the net income variances discussed above as well as variances in depreciation, financial charges and income taxes which are recovered in revenue on a flow-through basis and, therefore, do not impact net income.

U.S. Pipelines
ANR's comparable EBITDA in fourth quarter 2012 of US$63 million decreased US$10 million compared to the same period in 2011. The decrease was primarily due to lower transportation revenues and higher costs.

Great Lakes' comparable EBITDA for fourth quarter 2012 of US$11 million decreased US$9 million compared to the same period in 2011. The decrease was primarily the result of lower transportation revenue due to uncontracted capacity and lower rates compared to the same period in 2011.

Natural Gas Pipelines' business development comparable EBITDA loss from business development activities decreased $11 million for fourth quarter 2012 compared to the same period in 2011. The decrease in business development costs were primarily related to reduced activity in 2012 for the Alaska Pipeline Project.

Oil Pipelines
Oil Pipelines' comparable EBIT in fourth quarter 2012 was $136 million compared to $144 million for the same period in 2011. This decrease primarily reflected increased business development activity and related costs. The Keystone Pipeline System's comparable EBITDA of $180 million in fourth quarter 2012 is consistent with the same period in 2011.

Energy
Energy's comparable EBIT was $154 million in fourth quarter 2012 compared to $187 million in fourth quarter 2011. This decrease was a result of the Sundance A PPA force majeure as well as lower equity earnings from ASTC Power Partnership resulting from an unfavourable Sundance B PPA arbitration decision. These decreases were partially offset by higher contributions from Eastern Power due to incremental earnings from new assets being placed in service at Cartier Wind as well as from U.S. Power due to higher generation volumes and realized power and capacity prices in New York.

Western Power's comparable EBITDA of $84 million in fourth quarter 2012 decreased $58 million compared to the same period in 2011 primarily due to the Sundance A PPA force majeure and decreased equity earnings from the ASTC Power Partnership as a result of the Sundance B PPA arbitration decision.

Western Power's power revenues of $158 million in fourth quarter 2012 decreased $61 million compared to the same period in 2011 primarily due to the Sundance A PPA force majeure.

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92 -- TransCanada Pipelines Limited

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Eastern Power's comparable EBITDA of $94 million in fourth quarter 2012 increased $12 million compared to the same period in 2011. The increase was primarily due to incremental Cartier Wind earnings from phases one and two of Gros-Morne which were placed in service in November 2011 and November 2012, respectively, and Montagne-Sèche which was placed in service in November 2011, partially offset by lower Bécancour contractual earnings.

Our loss from Bruce A increased $39 million to a loss of $54 million in fourth quarter 2012 compared to the same period in 2011. This increase was primarily due to lower volumes and higher operating costs resulting from higher outage days. These increases were partially offset by incremental volumes and earnings from Units 1 and 2 which were returned to service on October 22 and October 31, respectively.

Our equity income from Bruce B increased $32 million to $46 million in fourth quarter 2012 compared to the same period in 2011. The increase was primarily due to higher volumes and lower operating costs resulting from fewer planned outage days and lower lease expense. Provisions in the Bruce B lease agreement with Ontario Power Generation provide for a reduction in the annual lease expense if the annual average Ontario spot price for electricity is less than $30 per MWh which was the case in 2012.

U.S. Power's comparable EBITDA in fourth quarter 2012 was US$48 million compared to US$32 million in fourth quarter 2011. The increase was primarily due to higher generation volumes and higher realized power and capacity prices in New York, partially offset by lower earnings from the U.S. hydro facilities due to reduced water flows, as well as lower capacity prices and higher load serving costs in New England.

Natural Gas Storage's comparable EBITDA in fourth quarter 2012 was $20 million and was comparable to the same period in 2011.

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2012 Management's discussion and analysis -- 93

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Glossary

Units of measure

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

General terms and terms related to our operations

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

Accounting terms

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

Government and regulatory bodies

CFE		Comisión Federal de Electricidad (Mexico)
CRE		Comisión Reguladora de Energia, or Energy Regulatory Commission (Mexico)
DOS		Department of State (U.S.)
FERC		Federal Energy Regulatory Commission (U.S.)
IEA