TransCanada Reports Solid Third Quarter Results, Advances Large Growth Program

CALGARY, ALBERTA--(Marketwire - Nov. 3, 2010) - TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today announced net income applicable to common shares for third quarter 2010 of $377 million and comparable earnings of $374 million or $0.54 per share.

"Our solid third quarter financial results demonstrate TransCanada continues to move in the right direction. Over the coming months, the company is on track to bring into service a number of large-scale projects that are expected to generate significant earnings and cash flow in the years ahead," says Russ Girling, TransCanada's president and chief executive officer. "At the same time, we recognize our business environment will continue to be challenging in the short term with depressed power and natural gas prices, putting pressure on a portion of our existing operations. TransCanada is well positioned to benefit as the economy recovers and commodity prices improve."

Girling added he is pleased TransCanada continues to advance the remainder of its $21 billion capital plan. The 683 megawatt Halton Hills generating station in Ontario is now officially operational, and Maine's largest wind project - Kibby Wind - is complete. Girling also pointed out construction is well underway on both the Groundbirch pipeline that will connect the Alberta System to the northeast B.C. shale gas play, and on the Bison pipeline that will bring U.S. Rocky Mountain natural gas to market. Both projects should be operational by year's end.

In the first quarter of 2011, the company will also see capacity on its Keystone Pipeline System rise when the Cushing expansion begins operating and the total capacity of the line increases from 435,000 barrels per day (Bbl/d) to 591,000 Bbl/d.

Third Quarter Highlights

(All financial figures are unaudited and in Canadian dollars unless noted otherwise)

--  Net income applicable to common shares of $377 million or $0.54 per
    share 
--  Comparable earnings of $374 million or $0.54 per share 
--  Comparable earnings before interest, taxes, depreciation and
    amortization (EBITDA) of $1.0 billion 
--  Funds generated from operations of $861 million 
--  Common share dividend of $0.40 per share 
--  Invested an additional $1.3 billion to advance $21 billion capital
    program
--  $700 million Halton Hills generating station was completed on time and
    on budget 
--  Began construction on the Groundbirch pipeline that will connect Montney
    shale gas, and on the Bison pipeline that will connect U.S. Rockies gas
--  National Energy Board (NEB) approved a three year settlement with
    stakeholders on the Alberta System that sets the equity return at 9.7
    per cent on deemed common equity of 40 per cent

Net income applicable to common shares for third quarter 2010 was $377 million ($0.54 per share) compared to $345 million ($0.50 per share) in third quarter 2009. Comparable earnings for third quarter 2010 were $374 million ($0.54 per share) compared to $335 million ($0.49 per share) in the same period in 2009.

The year over year increase was due to higher volumes and lower costs associated with higher plant availability at Bruce A for the quarter, higher generation and sales volumes in U.S. Power, higher earnings from the positive impact of recognizing the Alberta System 2010-2012 Revenue Requirement Settlement from its January 1, 2010 effective date, and lower net interest expense from increased capitalization of interest related to the company's large capital growth program. Partially offsetting these increases were lower realized power prices at Bruce B and Western Power.

Notable recent developments in Pipelines, Energy and Corporate include:

Pipelines:

--  Construction of the second phase of the US$12 billion Keystone Pipeline
    System to expand nominal capacity to 591,000 Bbl/d and extend the
    pipeline system to Cushing, Oklahoma is over 90 per cent complete. This
    phase is expected to be operational in first quarter 2011 with
    contracted volumes of 530,000 Bbl/d. 

    TransCanada's 500,000 Bbl/d Gulf Coast Expansion continues to move
    forward. The pipeline has binding, long-term commitments of 380,000
    Bbl/d. TransCanada has received regulatory approval for the Canadian
    portion of the project and anticipates receiving regulatory approval for
    the U.S. portion of the project in the first half of 2011.

    The Gulf Coast Expansion project will increase commercial capacity of 
    the Keystone Pipeline System to 1.1 million Bbl/d. Keystone will play an
    important role in linking a secure and growing supply of western 
    Canadian and U.S. Williston Basin crude oil with the largest refining
    markets in the United States.

--  On September 7 and September 13, 2010, TransCanada launched binding open
    seasons to obtain firm commitments from shippers to transport crude oil
    on the Cushing and Bakken Marketlink projects. The Cushing project would
    deliver crude from Cushing, Oklahoma to the U.S. Gulf Coast, while the
    Bakken initiative would transport oil from the Williston Basin to
    Cushing, Oklahoma or the U.S. Gulf Coast. The open seasons are expected
    to conclude in November 2010. 

--  On September 24, 2010, the NEB approved the Alberta System 2010-2012
    Revenue Requirement Settlement Application. The Settlement has a three
    year term and incorporates an equity return of 9.7 per cent on deemed
    common equity of 40 per cent which is an increase from the return of
    8.75 per cent on 35 per cent deemed common equity previously reflected
    in 2010 results.

--  In August 2010, the company received final regulatory approvals and
    began construction of the Groundbirch pipeline. The pipeline is expected
    to be operational during November 2010. When complete, the approximate
    $155 million project will consist of 77 kilometres (km) (48 miles) of
    36-inch diameter natural gas pipeline that will extend the Alberta
    System into northeast B.C. by connecting to natural gas supplies in the
    Montney shale gas formation. The Groundbirch pipeline has firm
    transportation contracts for 1.1 billion cubic feet per day by 2014.

    The Horn River Pipeline Project NEB hearing is expected to conclude on
    November 9, 2010 and an NEB decision is expected during the first
    quarter of 2011. The approximate $310 million project is scheduled to be
    operational in the second quarter of 2012 with commitments for
    contracted natural gas rising to approximately 540 million cubic feet
    per day (mmcf/d) by 2014.

    TransCanada continues to advance pipeline development in B.C. and
    Alberta to tie in unconventional shale gas supply. The company has
    received requests for further natural gas transmission service
    throughout the northwest portion of the Western Canadian Sedimentary
    Basin, including the Horn River and Montney areas of B.C. These new
    requests are expected to result in the need for further extensions and
    expansions of the Alberta System.

--  Construction on the US$600 million Bison natural gas pipeline project
    began in July 2010. The 487-km (303-mile) pipeline is expected to be
    operational in the fourth quarter of 2010. The project has long-term
    contracts for 407 mmcf/d. 

--  Work continues on the US$320 million Guadalajara pipeline project in
    Mexico. The 305-km (190-mile), 24 and 30-inch diameter natural gas
    pipeline has a contractual in-service date of first quarter 2011. The
    pipeline will move natural gas from Manzanillo to Guadalajara, Mexico's
    second largest city. Construction was approximately 40 per cent complete
    at the end of September 2010. 

--  The open season for the Alaska Pipeline Project concluded on July 30,
    2010 having received multiple conditional bids from major industry
    players and others for significant volumes. The Alaska Pipeline Project
    will work to resolve the shipper and pipeline conditions placed on some
    of the bids by shippers through the next several months. 


Energy:

--  TransCanada's $700 million Halton Hills generating station went into
    service on September 1, 2010, on time and on budget. The 683 megawatt
    (MW) power plant is now operating under a 20-year Clean Energy Supply
    Contract with the Ontario Power Authority (OPA) that will generate
    stable earnings and cash flow over the next two decades. Halton Hills
    will generate enough power to meet the needs of approximately 700,000
    homes. 

--  The second phase of the Kibby Wind power project went into service on
    October 26, 2010. This phase included 22 additional turbines. The two
    phases of the US$350 million project will produce a total of 132 MW of
    clean, renewable energy for the state of Maine - enough for
    approximately 50,000 homes. The first 22-turbine phase of the project
    began producing power in the fall of 2009. 

--  Construction of the 575 MW Coolidge generating station is approximately
    90 per cent complete. The US$500 million generating station is
    anticipated to be in service by second quarter 2011. 

--  Refurbishment work on Bruce A Units 1 and 2 has progressed with the
    completion of a major milestone in October 2010 following the successful
    installation of the last of the 960 calandria tubes. Atomic Energy of
    Canada Limited (AECL) has begun de-staffing and will be substantially
    demobilized from Unit 2 by the end of 2010 and from Unit 1 by second
    quarter 2011.  

    Subject to regulatory approval, Bruce Power expects to load fuel in Unit
    2 in second quarter 2011 and achieve a first synchronization of the
    generator to the electrical grid by the end of 2011, with commercial
    operation expected to occur in first quarter 2012. Bruce Power expects
    to load fuel in Unit 1 in third quarter 2011 with a first
    synchronization of the generator in first quarter 2012 and commercial
    operation is expected to occur during third quarter 2012.

    Plant commissioning and testing is underway and will accelerate at the
    end of second quarter 2011 when construction activities will be
    essentially complete. TransCanada's share of the total capital cost is
    expected to be approximately $2.4 billion. 

--  On October 7, 2010, the Government of Ontario announced that it would
    not proceed with the Oakville generating station. TransCanada has
    commenced negotiations with the OPA on a settlement which would
    terminate the contract and compensate TransCanada for the economic
    consequences associated with the contract's termination. 


Corporate:

--  The Board of Directors of TransCanada declared a quarterly dividend of
    $0.40 per share for the quarter ending December 31, 2010, on
    TransCanada's outstanding common shares. 

--  On September 23, 2010, TransCanada's wholly-owned subsidiary,
    TransCanada PipeLines Limited, successfully completed an offering of
    US$1.0 billion of 3.80 per cent Senior Notes due October 1, 2020. 

    The net proceeds of this offering will be used to partially fund capital
    projects of TransCanada, for general corporate purposes and to reduce
    short term debt. 

--  TransCanada is well positioned to fund its existing capital program
    through its growing internally-generated cash flow, its dividend
    reinvestment and share purchase plan and its continued access to capital
    markets. TransCanada will also continue to examine opportunities for
    portfolio management, including a role for TC PipeLines, LP in financing
    its capital program. 

Teleconference - Audio and Slide Presentation:

TransCanada will hold a teleconference and webcast to discuss its 2010 third quarter financial results. Russ Girling, TransCanada president and chief executive officer and Don Marchand, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and company developments, including its $21 billion capital program, before opening the call to questions from analysts and members of the media.

Event:

TransCanada 2010 third quarter financial results teleconference and webcast

Date:

Wednesday, November 3, 2010

Time:

9:00 a.m. mountain daylight time (MDT) /11:00 a.m. eastern daylight time (EDT)

How:

Analysts, members of the media and other interested parties are invited to participate by calling 866.223.7781 or 416.340.8018 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EDT) November 10, 2010. Please call 800.408.3053 or 416.695.5800 (Toronto area) and enter pass code 5430321#.

With more than 50 years' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada's network of wholly owned natural gas pipelines extends more than 60,000 kilometres (37,000 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with approximately 380 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in over 10,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: www.transcanada.com

Forward-Looking Information

This news release may contain certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada securityholders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operations plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, and strategies and goals for growth and expansion. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of TransCanada's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned to not place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release or otherwise, and to not use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP Measures

TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT and Funds Generated from Operations in this news release.

These measures do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP). They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.

EBITDA is an approximate measure of the Company's pre-tax operating cash flow. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations. EBIT comprises earnings before deducting interest and other financial charges, income taxes, non-controlling interests and preferred share dividends.

Management uses the measures of Comparable Earnings, Comparable EBITDA and Comparable EBIT to better evaluate trends in the Company's underlying operations. Comparable Earnings, Comparable EBITDA and Comparable EBIT comprise Net Income Applicable to Common Shares, EBITDA and EBIT, respectively, adjusted for specific items that are significant, but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating Comparable Earnings, Comparable EBITDA and Comparable EBIT, some of which may recur. Specific items may include but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and certain fair value adjustments. The table in the Consolidated Results of Operations section in the Management's Discussion and Analysis presents a reconciliation of Comparable Earnings, Comparable EBITDA, Comparable EBIT and EBIT to Net Income and Net Income Applicable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.

Funds Generated from Operations comprises Net Cash Provided by Operations before changes in operating working capital. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Third Quarter 2010 Financial Highlights table in this news release.

Third Quarter 2010 Financial Highlights

Operating Results

                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Revenues                                2,129     2,049     6,007     6,195 
                                                                            
Comparable EBITDA(1)                    1,007       994     2,936     3,142 
                                                                            
Net Income                                391       345       989       993 
                                                                            
Net Income Applicable to Common                                             
 Shares                                   377       345       958       993 
                                                                            
Comparable Earnings(1)                    374       335       977       997 
                                                                            
Cash Flows                                                                  
 Funds generated from operations(1)       861       772     2,519     2,230 
 (Increase)/decrease in operating                                           
  working capital                         (70)     (201)     (271)      127 
                                    ---------- --------- --------- ---------
 Net cash provided by operations          791       571     2,248     2,357 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            
Capital Expenditures                    1,297     1,557     3,565     3,943 
Acquisitions, Net of Cash Acquired          -       653         -       902 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------


Common Share Statistics

                                     Three months ended   Nine months ended 
                                           September 30        September 30
(unaudited)                              2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Net Income Per Share - Basic        $    0.54  $   0.50  $   1.39  $   1.55 
                                                                            
Comparable Earnings Per Share(1)    $    0.54  $   0.49  $   1.42  $   1.56 
                                                                            
Dividends Declared Per Share        $    0.40  $   0.38  $   1.20  $   1.14 
                                                                            
Basic Common Shares Outstanding                                             
 (millions)                                                                 
 Average for the period                   692       681       689       641 
 End of period                            693       681       693       681 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            

(1) Refer to the Non-GAAP Measures section in this news release for further
    discussion of comparable EBITDA, comparable earnings, funds generated
    from operations and comparable earnings per share. 

Management's Discussion and Analysis

Management's Discussion and Analysis (MD&A) dated November 2, 2010 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and nine months ended September 30, 2010. It should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2009 Annual Report for the year ended December 31, 2009. Additional information relating to TransCanada, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation. Unless otherwise indicated, "TransCanada" or "the Company" includes TransCanada Corporation and its subsidiaries. Amounts are stated in Canadian dollars unless otherwise indicated. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the Glossary of Terms contained in TransCanada's 2009 Annual Report.

Forward-Looking Information

This MD&A may contain certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results, and expected impact of future commitments and contingent liabilities. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP Measures

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

EBITDA is an approximate measure of the Company's pre-tax operating cash flow. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations. EBIT comprises earnings before deducting interest and other financial charges, income taxes, non-controlling interests and preferred share dividends.

Management uses the measures of Comparable Earnings, Comparable EBITDA and Comparable EBIT to better evaluate trends in the Company's underlying operations. Comparable Earnings, Comparable EBITDA and Comparable EBIT comprise Net Income Applicable to Common Shares, EBITDA and EBIT, respectively, adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating Comparable Earnings, Comparable EBITDA and Comparable EBIT, some of which may recur. Specific items may include but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and certain fair value adjustments. The table in the Consolidated Results of Operations section of this MD&A presents a reconciliation of Comparable Earnings, Comparable EBITDA, Comparable EBIT and EBIT to Net Income and Net Income Applicable to Common Shares. Comparable Earnings Per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.

Funds Generated from Operations comprises Net Cash Provided by Operations before changes in operating working capital. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Funds Generated from Operations table in the Liquidity and Capital Resources section of this MD&A.

Consolidated Results of Operations

Reconciliation of Comparable Earnings, Comparable EBITDA, Comparable EBIT
and EBIT to Net Income

For the three months ended September 30                                     
(unaudited)(millions of                                                     
 dollars except per        Pipelines    Energy   Corporate        Total     
 share amounts)           2010  2009  2010 2009  2010 2009     2010    2009 
------------------------------------- ---------- ---------- ----------------
------------------------------------- ---------- ---------- ----------------
                                                                            
Comparable EBITDA(1)       714   730   311  292   (18) (28)   1,007     994 
Depreciation and                                                            
 amortization             (232) (255)  (94) (88)    -    -     (326)   (343)
                          ----------- ---------- ---------- ----------------
Comparable EBIT(1)         482   475   217  204   (18) (28)     681     651 
Specific items:                                                             
 Fair value adjustments                                                     
  of U.S. Power                                                             
  derivative contracts       -     -   (3)    -     -    -      (3)       - 
 Fair value adjustments                                                     
  of natural gas                                                            
  inventory in storage                                                      
  and forward contracts      -     -     7   14     -    -        7      14 
                          ----------- ---------- ---------- ----------------
EBIT(1)                    482   475   221  218   (18) (28)     685     665 
                          ----------- ---------- ----------                 
                          ----------- ---------- ----------                 
Interest expense                                               (159)   (216)
Interest expense of                                                         
 joint ventures                                                 (13)    (17)
Interest income and                                                         
 other                                                           27      43 
Income taxes                                                   (120)   (107)
Non-controlling                                                             
 interests                                                      (29)    (23)
                                                            ----------------
Net Income                                                      391     345 
Preferred share                                                             
 dividends                                                      (14)      - 
                                                            ----------------
Net Income Applicable to                                                    
 Common Shares                                                  377     345 
                                                                            
Specific items (net of tax):                                                
 Fair value adjustments of U.S. Power derivative contracts        2       - 
 Fair value adjustments of natural gas inventory in                         
  storage and forward contracts                                  (5)    (10)
                                                            ----------------
Comparable Earnings(1)                                          374     335 
                                                            ----------------
                                                            ----------------
                                                                            
Net Income Per Share - Basic and                                            
 Diluted (2)                                                  $0.54   $0.50 
                                                            ----------------
                                                            ----------------

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

(2) For the three months ended September 30                                 
    (unaudited)                                         2010           2009 
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
                                                                            
    Net Income Per Share                            $   0.54       $   0.50 
    Specific items (net of tax):                                            
     Fair value adjustments of natural gas                                  
      inventory in storage and forward                                      
      contracts                                            -          (0.01)
                                               -----------------------------
    Comparable Earnings Per Share(1)                $   0.54       $   0.49 
                                               -----------------------------
                                               -----------------------------

For the nine months ended September 30                                      
(unaudited)                                                                 
 (millions of                                                               
 dollars except        Pipelines     Energy      Corporate        Total     
 per share amounts)  2010   2009   2010  2009   2010  2009     2010    2009 
--------------------------------- ------------ ------------ ----------------
--------------------------------- ------------ ------------ ----------------
                                                                            
Comparable                                                                  
 EBITDA(1)          2,178  2,348    824   883    (66)  (89)   2,936   3,142 
Depreciation and                                                            
 amortization        (736)  (773)  (274) (261)     -     -   (1,010) (1,034)
                   -------------- ------------ ------------ ----------------
Comparable EBIT(1)  1,442  1,575    550   622    (66)  (89)   1,926   2,108 
Specific items:                                                             
 Fair value                                                                 
  adjustments of                                                            
  U.S. Power                                                                
  derivative                                                                
  contracts             -      -    (22)    -      -     -      (22)      - 
 Fair value                                                                 
  adjustments of                                                            
  natural gas                                                               
  inventory in                                                              
  storage and                                                               
  forward                                                                   
  contracts             -      -     (8)   (6)     -     -       (8)     (6)
                   -------------- ------------ ------------ ----------------
EBIT(1)             1,442  1,575    520   616    (66)  (89)   1,896   2,102 
                   -------------- ------------ ------------                 
                   -------------- ------------ ------------                 
Interest expense                                               (528)   (770)
Interest expense                                                            
 of joint ventures                                              (44)    (47)
Interest income                                                             
 and other                                                       33      99 
Income taxes                                                   (286)   (320)
Non-controlling                                                             
 interests                                                      (82)    (71)
                                                            ----------------
Net Income                                                      989     993 
Preferred share                                                             
 dividends                                                      (31)      - 
                                                            ----------------
Net Income Applicable to                                                    
 Common Shares                                                  958     993 
                                                                            
Specific items (net of tax):                                                
 Fair value adjustments of U.S. Power derivative contracts      133       - 
 Fair value adjustments of natural gas inventory in                         
  storage and forward contracts                                   6       4 
                                                            ----------------
Comparable                                                                  
 Earnings(1)                                                    977     997 
                                                            ----------------
                                                            ----------------
                                                                            
Net Income Per Share - Basic and                                            
 Diluted(2)                                                   $1.39   $1.55 
                                                            ----------------
                                                            ----------------

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

(2) For the nine months ended September 30                                  
    (unaudited)                                         2010           2009 
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
                                                                            
    Net Income Per Share                            $   1.39       $   1.55 
    Specific items (net of tax):                                            
     Fair value adjustments of U.S. Power               0.02              - 
      derivative contracts                                                  
     Fair value adjustments of natural gas              0.01           0.01 
      inventory in storage and forward                                      
      contracts                                                             
                                              ------------------------------
    Comparable Earnings Per Share(1)                $   1.42       $   1.56 
                                              ------------------------------
                                              ------------------------------
                                                                            

TransCanada's Net Income in third quarter 2010 was $391 million and Net Income Applicable to Common Shares was $377 million or $0.54 per share compared to $345 million or $0.50 per share in third quarter 2009. The $32 million increase in Net Income Applicable to Common Shares reflected:

--  increased EBIT from Pipelines primarily due to the positive impact of
    recognizing the 2010 - 2012 Alberta System Revenue Requirement
    Settlement (Alberta System Settlement) from its effective date of
    January 1, 2010, lower depreciation and reduced operating, maintenance
    and administration (OM&A) costs, partially offset by the negative impact
    of a weaker U.S. dollar; 
--  increased EBIT from Energy primarily due to higher realized prices,
    volumes and capacity revenues for U.S. Power, and higher sales volumes
    at Bruce A, partially offset by lower realized power prices for Western
    Power and Bruce B, and decreased proprietary and third party storage
    revenues for Natural Gas Storage; 
--  decreased EBIT losses from Corporate primarily due to lower support and
    other corporate costs; 
--  decreased Interest Expense primarily due to increased capitalized
    interest and the positive impact of a weaker U.S. dollar on U.S. dollar-
    denominated interest expense, partially offset by incremental interest
    on new debt issues in 2010; 
--  a negative impact on Interest Income and Other from lower gains in 2010
    compared to 2009 on the translation of U.S. dollar-denominated working
    capital balances; 
--  increased Income Taxes due to higher pre-tax earnings; and 
--  dividends recorded for preferred shares issued in 2010 and third quarter
    2009. 

Comparable Earnings in third quarter 2010 were $374 million or $0.54 per share compared to $335 million or $0.49 per share for the same period in 2009. Comparable Earnings in third quarter 2010 excluded $2 million after tax ($3 million pre-tax) of net unrealized losses resulting from changes in the fair value of U.S. Power derivative contracts. Effective January 1, 2010, these unrealized gains and losses have been removed from Comparable Earnings as they are not expected to be representative of amounts that will be realized on settlement of the contracts. Comparative amounts in 2009 were not excluded from the computation of Comparable Earnings. Comparable Earnings in third quarter 2010 and 2009 also excluded net unrealized gains of $5 million after tax ($7 million pre-tax) and $10 million after tax ($14 million pre-tax), respectively, resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts.

On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. Pipelines and U.S. Energy EBIT is partially offset by the impact on U.S. dollar-denominated interest expense. The resultant net exposure is managed using derivatives, effectively further reducing the Company's exposure to changes in foreign exchange rates. The average U.S. dollar exchange rate was 1.04 for each of the three and nine month periods ended September 30, 2010 (2009 - 1.10 and 1.17, respectively).

TransCanada's Net Income in the first nine months of 2010 was $989 million and Net Income Applicable to Common Shares was $958 million or $1.39 per share compared to $993 million or $1.55 per share for the same period in 2009. The $35 million decrease in Net Income Applicable to Common Shares reflected:

--  decreased EBIT from Pipelines primarily due to the negative impact of a
    weaker U.S. dollar, higher business development costs relating to the
    Alaska pipeline project and reduced revenues from certain U.S.
    pipelines, partially offset by the positive impact of recognizing the
    Alberta System Settlement, lower depreciation and reduced OM&A costs; 
--  decreased EBIT from Energy primarily due to lower overall realized power
    prices at Western Power, reduced volumes and higher operating costs at
    Bruce A, lower realized prices partially offset by higher volumes at
    Bruce B, reduced earnings at Becancour and decreased proprietary and
    third party storage revenues for Natural Gas Storage, partially offset
    by increased volumes and capacity revenue from U.S. Power, and
    incremental earnings from Portlands Energy and Halton Hills, which went
    into service in April 2009 and September 2010, respectively; 
--  decreased EBIT losses from Corporate primarily due to lower support and
    other corporate costs; 
--  decreased Interest Expense primarily due to increased capitalized
    interest and the positive effect of a weaker U.S. dollar on U.S. dollar-
    denominated interest expense, partially offset by incremental interest
    expense on new debt issues in 2010 and by higher losses in 2010 compared
    to 2009 from changes in the fair value of derivatives used to manage the
    Company's exposure to rising interest rates; 
--  the negative impact on Interest Income and Other due to lower gains in
    2010 compared to 2009 from derivatives used to manage the Company's
    exposure to foreign exchange rate fluctuations on U.S. dollar-
    denominated income and the negative impact from the translation of U.S.
    dollar-denominated working capital balances; 
--  decreased Income Taxes due to the net positive impact from income tax
    rate differentials, other income tax adjustments and lower pre-tax
    earnings; and 
--  dividends recorded for preferred shares issued in 2010 and third quarter
    2009. 

Net Income Per Share in the first nine months of 2010 was also reduced by $0.10 per share due to a seven per cent increase in the average number of common shares outstanding, compared to the same period in 2009, including the Company's issuance of 58.4 million common shares in second quarter 2009.

Comparable Earnings in the first nine months of 2010 were $977 million or $1.42 per share compared to $997 million or $1.56 per share for the same period in 2009. Comparable Earnings for the first nine months of 2010 excluded $13 million of after tax ($22 million pre-tax) net unrealized losses resulting from changes in the fair value of U.S. Power derivative contracts. Comparative amounts in 2009 were not excluded from the computation of Comparable Earnings. Comparable Earnings in the first nine months of 2010 and 2009 also excluded net unrealized losses of $6 million after tax ($8 million pre-tax) and $4 million after tax ($6 million pre-tax), respectively, resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts.

Results from each of the segments for the first three and nine months in 2010 are discussed further in the Pipelines and Energy sections of this MD&A.

Pipelines

Pipelines' Comparable EBIT and EBIT were $482 million and $1.4 billion in the three and nine month periods ended September 30, 2010, respectively, compared to $475 million and $1.6 billion for the same periods in 2009.

Pipelines Results

(unaudited)                          Three months ended   Nine months ended 
                                           September 30        September 30 
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Canadian Pipelines                                                          
Canadian Mainline                         257       279       785       851 
Alberta System                            197       190       548       535 
Foothills                                  34        32       102       100 
Other (TQM, Ventures LP)                   12        13        39        44 
                                    ---------- --------- --------- ---------
Canadian Pipelines Comparable                                               
 EBITDA(1)                                500       514     1,474     1,530 
                                    ---------- --------- --------- ---------
                                                                            
U.S. Pipelines                                                              
ANR                                        67        57       248       263 
GTN(2)                                     44        42       130       152 
Great Lakes                                27        31        86       108 
PipeLines LP(2)(3)                         28        29        76        79 
Iroquois                                   16        18        53        62 
Portland(4)                                 1         2        12        18 
International (Tamazunchale,                                                
 TransGas, Gas Pacifico/INNERGY)           10        18        35        46 
General, administrative and support                                         
 costs(5)                                 (16)      (11)      (25)      (18)
Non-controlling interests(6)               45        40       130       134 
                                    ---------- --------- --------- ---------
U.S. Pipelines Comparable EBITDA(1)       222       226       745       844 
                                    ---------- --------- --------- ---------
                                                                            
Business Development Comparable                                             
 EBITDA(1)                                 (8)      (10)      (41)      (26)
                                    ---------- --------- --------- ---------
                                                                            
Pipelines Comparable EBITDA(1)            714       730     2,178     2,348 
Depreciation and amortization            (232)     (255)     (736)     (773)
                                    ---------- --------- --------- ---------
Pipelines Comparable EBIT and                                               
 EBIT(1)                                  482       475     1,442     1,575 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------

(1) Refer to the Non-GAAP Measures section in this MD&A for further
    discussion of Comparable EBITDA, Comparable EBIT and EBIT. 
(2) GTN's results include North Baja until July 1, 2009 when it was sold to
    PipeLines LP. 
(3) PipeLines LP's results reflect TransCanada's ownership interest in
    PipeLines LP of 38.2 per cent in the three and nine months ended
    September 30, 2010 (first six months of 2009 - 32.1 per cent; three
    months ended September 30, 2009 - 42.6 per cent). 
(4) Portland's results reflect TransCanada's 61.7 per cent ownership
    interest. 
(5) Represents general and administrative costs associated with certain of
    the Company's pipelines. 
(6) Non-controlling interests reflects Comparable EBITDA for the portions of
    PipeLines LP and Portland not owned by TransCanada. 


Net Income for Wholly Owned Canadian Pipelines

                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Canadian Mainline                          66        68       196       201 
Alberta System                             70        44       145       123 
Foothills                                   7         6        20        18 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------

Canadian Pipelines

Canadian Mainline's net income for the three and nine months ended September 30, 2010 decreased $2 million and $5 million, respectively, compared to the same periods in 2009 primarily due to lower incentive earnings and a lower rate of return on common equity (ROE), as determined by the National Energy Board (NEB), of 8.52 per cent in 2010 compared to 8.57 per cent in 2009.

Canadian Mainline's Comparable EBITDA for the three and nine months ended September 30, 2010 of $257 million and $785 million, respectively, decreased $22 million and $66 million, respectively, compared to the same periods in 2009 primarily due to lower revenues as a result of lower income taxes and financial charges in the 2010 tolls, which are recovered on a flow-through basis and do not impact net income. The decrease in financial charges was primarily due to higher cost debt that matured in 2009 and early 2010.

The Alberta System's net income was $70 million in third quarter 2010 and $145 million for the first nine months of 2010 compared to $44 million and $123 million for the same periods in 2009. Net income in third quarter 2010 increased $26 million compared to 2009 and reflects the regulatory approval and recognition of the Alberta System Settlement with stakeholders, which includes a 9.70 per cent ROE on deemed common equity of 40 per cent, effective January 1, 2010. The positive impact of the higher ROE and investment base was partially offset by lower incentive earnings compared to 2009.

The Alberta System's Comparable EBITDA was $197 million in third quarter 2010 and $548 million for the first nine months of 2010 compared to $190 million and $535 million for the same periods in 2009. These increases were due to higher revenues associated with the equity return included in the Alberta System Settlement and an increased average investment base, partially offset by lower depreciation and financial charges recovered on a flow-through basis under the Alberta System Settlement and lower incentive earnings compared to 2009.

Comparable EBITDA from Other Canadian Pipelines was $12 million in third quarter 2010 and $39 million for the first nine months of 2010, respectively, compared to $13 million and $44 million for the same periods in 2009. The decrease in the nine months ended September 30, 2010 was primarily due to an adjustment recorded in first quarter 2009 for an NEB decision to increase TQM's allowed rate of return on capital for 2008 and 2007.

U.S. Pipelines

ANR's Comparable EBITDA in the three and nine months ended September 30, 2010 was $67 million and $248 million, respectively, compared to $57 million and $263 million for the same periods in 2009. The increase in third quarter 2010 compared to third quarter 2009 was primarily due to lower OM&A costs, partially offset by the impact of a weaker U.S. dollar. For the nine months ended September 30, 2010, the decrease was primarily due to the negative impact of a weaker U.S. dollar, partially offset by lower OM&A costs.

GTN's Comparable EBITDA for the nine months ended September 30, 2010 decreased $22 million from the same period in 2009 primarily due to the sale of North Baja to PipeLines LP in July 2009 and the negative impact of a weaker U.S. dollar, partially offset by lower OM&A costs in 2010.

Comparable EBITDA for the remainder of the U.S. Pipelines was $111 million and $367 million for the three and nine months ended September 30, 2010, respectively, compared to $127 million and $429 million for the same periods in 2009. The decreases were primarily due to the negative impact of a weaker U.S. dollar, lower revenues from Great Lakes and higher general, administrative and support costs primarily related to the startup of Keystone. These decreases were partially offset by the positive impact on PipeLines LP's earnings as a result of its acquisition of North Baja in July 2009 and higher revenue from Northern Border.

Business Development

Pipelines' Business Development Comparable EBITDA decreased $15 million in the nine months ended September 30, 2010 compared to the same period in 2009. EBITDA for the nine months ended September 30, 2010 reflects increased expenses due to higher business development costs related to the continued advancement of the Alaska pipeline project, net of recoveries. The State of Alaska has agreed to reimburse certain of TransCanada's eligible pre-construction costs, as they are incurred and approved by the State, to a maximum of US$500 million. The State of Alaska is reimbursing up to 50 per cent of the eligible costs incurred prior to the close of the first binding open season on July 30, 2010. Commencing July 31, 2010, the State began reimbursing up to 90 per cent of the eligible costs. Together with applicable expenses, such reimbursements are shared proportionately with ExxonMobil, TransCanada's joint venture partner in developing the Alaska pipeline project.

Depreciation

Pipelines' depreciation decreased $23 million and $37 million for the three and nine months ended September 30, 2010, respectively, primarily due to reduced depreciation resulting from Great Lakes' rate settlement in 2010 and the impact of a weaker U.S. dollar. The decrease in third quarter 2010 was also due to the Alberta System Settlement.

Operating Statistics


Nine months                                                                 
 ended           Canadian      Alberta                                      
 September 30   Mainline(1)   System(2)   Foothills      ANR(3)     GTN(3) 
(unaudited)     2010  2009   2010  2009   2010 2009   2010  2009  2010 2009 
--------------------------- ------------ ----------- ------------ ----------
--------------------------- ------------ ----------- ------------ ----------
                                                                            
Average                                                                     
 investment                                                                 
 base                                                                       
 ($millions)   6,518 6,549  4,986 4,724    661  711    n/a   n/a   n/a  n/a 
Delivery                                                                    
 volumes (Bcf)                                                              
 Total         1,191 1,561  2,535 2,652  1,054  901  1,171 1,199   598  578 
 Average per                                                                
  day            4.4   5.7    9.3   9.7    3.9  3.3    4.3   4.4   2.2  2.1 
              ------------- ------------ ----------- ------------ ----------
              ------------- ------------ ----------- ------------ ----------

(1) Canadian Mainline's throughput volumes in the above table reflect
    physical deliveries to domestic and export markets. Canadian Mainline's
    physical receipts originating at the Alberta border and in Saskatchewan
    for the nine months ended September 30, 2010 were 927 billion cubic feet
    (Bcf) (2009 - 1,234 Bcf); average per day was 3.4 Bcf (2009 - 4.5 Bcf). 
(2) Field receipt volumes for the Alberta System for the nine months ended
    September 30, 2010 were 2,619 Bcf (2009 - 2,734 Bcf); average per day
    was 9.6 Bcf (2009 - 10.0 Bcf). 
(3) ANR's and GTN's results are not impacted by average investment base as
    these systems operate under fixed rate models approved by the U.S.
    Federal Energy Regulatory Commission. 

Mackenzie Gas Pipeline Project

As at September 30, 2010, TransCanada had advanced $145 million to the Aboriginal Pipeline Group (APG) with respect to the Mackenzie Gas Pipeline Project (MGP). TransCanada and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on obtaining regulatory approval and the Canadian government's support of an acceptable fiscal framework. The NEB is expected to release its decision on the project's application for a certificate of public convenience and necessity by December 2010. Project timing thereafter continues to be uncertain. In the event the co-venture group is unable to reach an agreement with the government on an acceptable fiscal framework, the parties will need to determine the appropriate next steps for the project. For TransCanada, this may result in a reassessment of the carrying amount of the APG advances.

Energy

Energy's Comparable EBIT was $217 million in third quarter 2010 compared to $204 million in third quarter 2009. Comparable EBIT in third quarter 2010 excluded net unrealized losses of $3 million resulting from changes in the fair value of U.S. Power derivative contracts. Comparable EBIT in third quarter 2010 and 2009 also excluded net unrealized gains of $7 million and $14 million, respectively, from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts.

Energy's Comparable EBIT was $550 million in the first nine months of 2010 compared to $622 million in the same nine months of 2009. Comparable EBIT excluded net unrealized losses of $22 million resulting from changes in the fair value of U.S. Power derivative contracts. Comparable EBIT in the first nine months of 2010 and 2009 also excluded net unrealized losses of $8 million and $6 million, respectively, from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. Items excluded from Comparable Earnings are discussed further under the headings U.S. Power and Natural Gas Storage in this section.

Energy Results

                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Canadian Power                                                              
Western Power                              45        66       172       218 
Eastern Power(1)                           56        52       154       164 
Bruce Power                                89        81       199       282 
General, administrative and support                                         
 costs                                    (14)       (9)      (29)      (28)
                                    ---------- --------- --------- ---------
Canadian Power Comparable EBITDA(2)       176       190       496       636 
                                    ---------- --------- --------- ---------
                                                                            
U.S. Power                                                                  
Northeast Power(3)                        123        80       279       198 
General, administrative and support                                         
 costs                                     (7)      (12)      (25)      (35)
                                    ---------- --------- --------- ---------
U.S. Power Comparable EBITDA(2)           116        68       254       163 
                                    ---------- --------- --------- ---------
                                                                            
Natural Gas Storage                                                         
Alberta Storage                            28        47       101       122 
General, administrative and support                                         
 costs                                     (2)       (2)       (6)       (7)
                                    ---------- --------- --------- ---------
Natural Gas Storage Comparable                                              
 EBITDA(2)                                 26        45        95       115 
                                    ---------- --------- --------- ---------
                                                                            
Business Development Comparable                                             
 EBITDA(2)                                 (7)      (11)      (21)      (31)
                                    ---------- --------- --------- ---------
                                                                            
Energy Comparable EBITDA(2)               311       292       824       883 
Depreciation and amortization             (94)      (88)     (274)     (261)
                                    ---------- --------- --------- ---------
Energy Comparable EBIT(2)                 217       204       550       622 
Specific items:                                                             
 Fair value adjustments of U.S.                                             
  Power derivative contracts               (3)        -       (22)        - 
 Fair value adjustments of natural                                          
  gas inventory in storage and                                              
  forward contracts                         7        14        (8)       (6)
                                    ---------- --------- --------- ---------
Energy EBIT(2)                            221       218       520       616 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            

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


Canadian Power

Western and Eastern Canadian Power Comparable EBITDA(1)(2)

                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Revenues                                                                    
 Western power                            168       196       534       585 
 Eastern power                             85        69       217       209 
 Other(3)                                  27        19        64        61 
                                    ---------- --------- --------- ---------
                                          280       284       815       855 
                                    ---------- --------- --------- ---------
Commodity Purchases Resold                                                  
 Western power                           (109)     (120)     (314)     (327)
 Other(3)(4)                              (12)       (4)      (24)      (19)
                                    ---------- --------- --------- ---------
                                         (121)     (124)     (338)     (346)
                                    ---------- --------- --------- ---------
                                                                            
Plant operating costs and other           (58)      (42)     (151)     (129)
General, administrative and support                                         
 costs                                    (14)       (9)      (29)      (28)
Other income                                -         -         -         2 
                                    ---------- --------- --------- ---------
Comparable EBITDA(1)                       87       109       297       354 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            

(1) Refer to the Non-GAAP Measures section in this MD&A for further
    discussion of Comparable EBITDA. 
(2) Includes Halton Hills and Portlands Energy effective September 2010 and
    April 2009, respectively. 
(3) Includes sales of excess natural gas purchased for generation and
    thermal carbon black. Effective January 1, 2010, the net impact of
    derivatives used to purchase and sell natural gas to manage Western and
    Eastern Power's assets is presented on a net basis in Other Revenues.
    Comparative results for 2009 reflect amounts reclassified from Other
    Commodity Purchases Resold to Other Revenues. 
(4) Includes the cost of excess natural gas not used in operations. 


Western and Eastern Canadian Power Operating Statistics(1)

                                     Three months ended   Nine months ended 
                                           September 30        September 30
(unaudited)                              2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Sales Volumes (GWh)                                                         
Supply                                                                      
 Generation                                                                 
  Western Power                           572       541     1,751     1,718 
  Eastern Power                           661       305     1,485     1,081 
 Purchased                                                                  
  Sundance A & B and Sheerness PPAs     2,641     2,560     7,755     7,725 
  Other purchases                          89       113       311       420 
                                    ---------- --------- --------- ---------
                                        3,963     3,519    11,302    10,944 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
Sales                                                                       
 Contracted                                                                 
  Western Power                         2,526     2,514     7,368     7,164 
  Eastern Power                           660       307     1,500     1,117 
 Spot                                                                       
  Western Power                           777       698     2,434     2,663 
                                    ---------- --------- --------- ---------
                                        3,963     3,519    11,302    10,944 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
Plant Availability                                                          
Western Power(2)                           94%       90%       94%       92%
Eastern Power                              98%       97%       97%       97%
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            

(1) Includes Halton Hills and Portlands Energy effective September 2010 and
    April 2009, respectively. 
(2) Excludes facilities that provide power to TransCanada under PPAs. 

/T/

Western Power's Comparable EBITDA of $45 million and Power Revenues of $168 million in third quarter 2010 decreased $21 million and $28 million, respectively, compared to the same period in 2009, primarily due to lower overall realized power prices. Average spot market power prices in Alberta decreased 28 per cent to $36 per megawatt hour (MWh) in third quarter 2010 compared to $50 per MWh in third quarter 2009. Spot market sales represented 24 per cent of Western Power's total sales in third quarter 2010.

Western Power's Comparable EBITDA of $172 million and Power Revenues of $534 million in the first nine months of 2010 decreased $46 million and $51 million, respectively, compared to the same period in 2009, primarily due to lower overall realized power prices. 

Eastern Power's Comparable EBITDA of $56 million and Power Revenues of $85 million in third quarter 2010 increased $4 million and $16 million, respectively, compared to the same period in 2009. These increases were primarily due to incremental earnings from Halton Hills, which went into service under a 20 year power purchase arrangement (PPA) in September 2010, partially offset by lower contracted earnings from Becancour. Results from Becancour are consistent with the expected contracted earnings according to the original electricity supply contract with Hydro-Quebec.

Eastern Power's Comparable EBITDA of $154 million in the first nine months of 2010 decreased $10 million, compared to the same period in 2009, primarily due to lower contracted earnings from Becancour and unfavourable wind conditions at Cartier Wind, partially offset by incremental earnings from Portlands Energy and Halton Hills, which went into service in April 2009 and September 2010, respectively. 

Western Power manages the sale of its supply volumes on a portfolio basis. A portion of its supply is sold into the spot market to assure supply in the event of an unexpected plant outage. The overall amount of spot market volumes is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management helps to minimize costs in situations where Western Power would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 76 per cent of Western Power sales volumes were sold under contract in third quarter 2010, compared to 78 per cent in third quarter 2009. To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2010, Western Power had entered into fixed-price power sales contracts to sell approximately 2,400 gigawatt hours (GWh) for the remainder of 2010 and 7,300 GWh for 2011.

Eastern Power is focused on selling power under long-term contracts. In third quarter 2010 and 2009, all of Eastern Power's sales volumes were sold under contract and are expected to continue to be 100 per cent sold under contract for the remainder of 2010 and 2011.

/T/

Bruce Power Results

(TransCanada's proportionate share)   Three months ended  Nine months ended 
(unaudited)                                September 30        September 30
(millions of dollars unless                                                 
 otherwise indicated)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Revenues(1)                               212       224       634       685 
Operating Expenses                       (123)     (143)     (435)     (403)
                                    ---------- --------- --------- ---------
Comparable EBITDA(2)                       89        81       199       282 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            
Bruce A Comparable EBITDA(2)               35       (11)       58        77 
Bruce B Comparable EBITDA(2)               54        92       141       205 
                                    ---------- --------- --------- ---------
Comparable EBITDA(2)                       89        81       199       282 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            
Bruce Power - Other Information                                             
Plant availability                                                          
 Bruce A                                   92%       71%       77%       89%
 Bruce B                                   88%       97%       90%       90%
 Combined Bruce Power                      89%       89%       86%       90%
Planned outage days                                                         
 Bruce A                                    -        46        60        46 
 Bruce B                                    7         -        54        45 
Unplanned outage days                                                       
 Bruce A                                    7         3        55         8 
 Bruce B                                   28         3        34        44 
Sales volumes (GWh)                                                         
 Bruce A                                1,446     1,099     3,556     4,157 
 Bruce B                                2,003     1,950     6,102     5,751 
                                    ---------- --------- --------- ---------
                                        3,449     3,049     9,658     9,908 
                                    ---------- --------- --------- ---------
Results per MWh                                                             
 Bruce A power revenues                   $65       $64       $65       $64 
 Bruce B power revenues(3)                $57       $66       $58       $64 
 Combined Bruce Power revenues            $60       $66       $60       $64 
Percentage of Bruce B output sold to                                        
 spot market(4)                            82%       49%       78%       42%
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            

(1) Revenues include Bruce A's fuel cost recoveries of $7 million and $21
    million for the three and nine months ended September 30, 2010,
    respectively (2009 - $7 million and $28 million, respectively). Revenues
    also include Bruce B unrealized losses of $4 million and $5 million as a
    result of changes in the fair value of power derivatives for the three
    and nine months ended September 30, 2010, respectively (2009 - gains of
    $2 million and $4 million, respectively). 
(2) Refer to the Non-GAAP Measures section in this MD&A for further
    discussion of Comparable EBITDA. 
(3) Includes revenues received under the floor price mechanism and contract
    settlements. 
(4) All of Bruce B's output is covered by the floor price mechanism,
    including volumes sold to the spot market. 

/T/

TransCanada's proportionate share of Bruce Power's Comparable EBITDA increased $8 million to $89 million in third quarter 2010 compared to $81 million in third quarter 2009. 

TransCanada's proportionate share of Bruce A's Comparable EBITDA increased $46 million to $35 million in third quarter 2010 compared to losses of $11 million in third quarter 2009 as a result of increased volumes and lower operating costs due to decreased outage days. Bruce A's plant availability in third quarter 2010 was 92 per cent with seven outage days compared to an availability of 71 per cent and 49 outage days in the same period in 2009.

TransCanada's proportionate share of Bruce B's Comparable EBITDA decreased $38 million to $54 million in third quarter 2010 compared to $92 million in third quarter 2009 primarily due to lower realized prices resulting from the expiration of fixed-price contracts at higher prices. Bruce B's volumes increased in third quarter 2010 compared to the same period in 2009 as a result of fewer surplus baseload generation (SBG) derates in 2010 as required by the Independent Electricity System Operator, partially offset by lower plant availability. Bruce B's plant availability in third quarter 2010 was 88 per cent with 35 outage days compared to an availability of 97 per cent and three outage days in the same period in 2009. 

In second quarter 2009, Bruce B's contract with the Ontario Power Authority (OPA) was amended such that, beginning in 2009, annual net payments received under the floor price mechanism will not be subject to repayment in future years. Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. No amounts recorded in revenues in the first nine months of 2010 are expected to be repaid.

TransCanada's proportionate share of Bruce Power's Comparable EBITDA decreased $83 million to $199 million in the nine months ended September 30, 2010 compared to the same period in 2009 as a result of lower volumes and higher operating costs due to higher planned and unplanned outage days at Bruce A, and lower realized prices at Bruce B, partially offset by higher volumes at Bruce B resulting from fewer SBG derates in 2010. The decrease in EBITDA for the nine months ended September 30, 2010 was partially offset by the impact of a payment made in first quarter 2010 from Bruce B to Bruce A regarding 2009 amendments to the agreement with the OPA. The net positive impact to TransCanada in 2010 reflected TransCanada's higher percentage ownership in Bruce A. Under a contract with the OPA, all output from Bruce A in third quarter 2010 was sold at a fixed price of $64.71 per MWh (before recovery of fuel costs from the OPA) compared to $64.45 per MWh in third quarter 2009. All output from the Bruce B units was subject to a floor price of $48.96 per MWh in third quarter 2010 and $48.76 per MWh in third quarter 2009. Both the Bruce A and Bruce B contract prices are adjusted annually for inflation on April 1. Bruce B also enters into fixed-price contracts whereby Bruce B receives or pays the difference between the contract price and the spot price. Bruce B's realized price of $57 per MWh in third quarter 2010 reflected revenues recognized from both the floor price mechanism and contract sales, and decreased from the $66 per MWh in third quarter 2009 due to contracts expiring since that time. A significant portion of the remaining contracts will expire by the end of 2010, which is expected to result in a further reduction in realized prices at Bruce B for future periods. At September 30, 2010, Bruce B had sold forward approximately 200 GWh and 300 GWh, representing TransCanada's proportionate share, for the remainder of 2010 and 2011, respectively.

The overall plant availability percentage in 2010 is expected to be in the low 80's for the two operating Bruce A units and in the low 90's for the four Bruce B units. A planned outage of Bruce A Unit 3 began in late February 2010 and ended in late April 2010. A planned outage on Bruce B Unit 6 commenced in mid-May 2010 with the unit returning to service in late July 2010. A three week planned maintenance outage commenced on October 22, 2010 for Bruce B Unit 5.

As at September 30, 2010, Bruce A had incurred approximately $3.8 billion in costs for the refurbishment and restart of Units 1 and 2, and approximately $0.3 billion for the refurbishment of Units 3 and 4.

U.S. Power

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


(unaudited)                          Three months ended   Nine months ended 
                                           September 30        September 30
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Revenues                                                                    
 Power(3)                                 399       222       884       679 
 Capacity                                  77        66       187       150 
 Other(3)(4)                               15         9        57        66 
                                    ---------- --------- --------- ---------
                                          491       297     1,128       895 
Commodity purchases resold(3)            (178)      (78)     (435)     (267)
Plant operating costs and other(4)       (190)     (139)     (414)     (430)
General, administrative and support                                         
 costs                                     (7)      (12)      (25)      (35)
                                    ---------- --------- --------- ---------
Comparable EBITDA(1)                      116        68       254       163 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            

(1) Refer to the Non-GAAP Measures section of this MD&A for further
    discussion of Comparable EBITDA. 
(2) Includes phase one of Kibby Wind effective October 2009. 
(3) Effective January 1, 2010, the net impact of derivatives used to
    purchase and sell power, natural gas and fuel oil to manage U.S. Power's
    assets is presented on a net basis in Power Revenues. Comparative
    results for 2009 reflect amounts reclassified from Commodity Purchases
    Resold and Other Revenues to Power Revenues. 
(4) Includes revenues and costs related to a third-party service agreement
    at Ravenswood. 


U.S. Power Operating Statistics(1)

                                     Three months ended   Nine months ended 
                                           September 30        September 30
(unaudited)                              2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Sales Volumes (GWh)                                                         
Supply                                                                      
 Generation                             2,403     2,021     5,083     4,593 
 Purchased                              2,514     1,259     7,061     3,653 
                                    ---------- --------- --------- ---------
                                        4,917     3,280    12,144     8,246 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
Sales                                                                       
 Contracted                             4,129     2,800    11,013     7,206 
 Spot                                     788       480     1,131     1,040 
                                    ---------- --------- --------- ---------
                                        4,917     3,280    12,144     8,246 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            
Plant Availability                         96%       97%       91%       78%
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------

(1) Includes phase one of Kibby Wind effective October 2009. 

U.S. Power's Comparable EBITDA for the three months ended September 30, 2010 was $116 million, an increase of $48 million compared to the same period in 2009. The increase was primarily due to higher realized prices, higher volumes of power sold and increased capacity revenues. For the nine months ended September 30, 2010, U.S. Power's Comparable EBITDA of $254 million increased $91 million from the same period in 2009 primarily due to higher capacity revenues, increased sales volumes and a first quarter 2010 adjustment of Ravenswood's 2009 operating costs, partially offset by the negative impact of a weaker U.S. dollar.

U.S. Power's Power Revenues for the three and nine months ended September 30, 2010 of $399 million and $884 million, respectively, increased from $222 million and $679 million in the same periods in 2009 primarily due to higher volumes of power sold in addition to higher realized power prices in third quarter 2010, partially offset by the negative impact of a weaker U.S. dollar. Capacity Revenues increased for the three and nine months ended September 30, 2010 to $77 million and $187 million, respectively, primarily due to higher capacity prices as a result of the long-planned retirement of a power generating facility owned by the New York Power Authority, which occurred at the end of January 2010. The increases in Capacity Revenues were partially offset by the impact of the Unit 30 outage from September 2008 to May 2009, which has a greater impact on 2010 capacity revenues due to the nature of the calculations.

Commodity Purchases Resold of $178 million and $435 million for the three and nine months ended September 30, 2010, respectively, increased from $78 million and $267 million in the same periods in 2009 primarily due to an increase in the quantity of power purchased for resale under power sales commitments in New England and New York, as well as higher power prices per MWh purchased in third quarter 2010, partially offset by the positive impact of a weaker U.S. dollar.

Plant Operating Costs and Other in the three months ended September 30, 2010 were $190 million, an increase of $51 million over the same period in 2009 primarily due to increased generation volumes, partially offset by the positive impact of a weaker U.S. dollar. In the nine months ended September 30, 2010, Plant Operating Costs and Other were $414 million, a decrease of $16 million compared to the same period in 2009, primarily due to the positive impact of a weaker U.S. dollar and the impact of the Ravenswood prior year adjustment, partially offset by higher fuel costs resulting from increased generation.

U.S. Power achieved plant availability of 91 per cent in the nine months ended September 30, 2010 compared to 78 per cent for the same period in 2009 primarily due to the return to service of Ravenswood Unit 30 in May 2009 following an unplanned outage.

In the three and nine months ended September 30, 2010, 84 per cent and 91 per cent, respectively, of power sales volumes were sold under contract, compared to 85 per cent and 87 per cent for the same periods in 2009. U.S. Power is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers, while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases. To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2010, U.S. Power had entered into fixed-price power sales contracts to sell approximately 3,400 GWh for the remainder of 2010 and 10,000 GWh for 2011, including financial contracts to effectively lock in a margin on forecasted generation. Certain contracted volumes are dependent on customer usage levels and actual amounts contracted in future periods will depend on market liquidity and other factors.

Comparable EBITDA excluded net unrealized losses of $3 million and $22 million in the three and nine months ended September 30, 2010, respectively, resulting from changes in the fair value of U.S. Power derivative contracts. Power is purchased under forward contracts to satisfy a significant portion of U.S. Power's wholesale, commercial and industrial power sales commitments, mitigating its exposure to fluctuations in spot market prices and effectively locking in a positive margin. In addition, power generation is managed by entering into contracts to sell a portion of power forecasted to be generated, while simultaneously entering into contracts to purchase the fuel required to generate the power, thereby reducing exposure to market price volatility and effectively locking in positive margins. Each of these contracts provide economic hedges which, in some cases, do not meet the specific criteria required for hedge accounting treatment and, therefore, are recorded at their fair value based on forward market prices. Effective January 1, 2010, the unrealized gains and losses from these contracts have been removed from Comparable EBITDA as they are not representative of amounts that will be realized on settlement of the contracts. Comparative amounts in 2009 were not excluded from the computation of Comparable EBITDA.

Natural Gas Storage

Natural Gas Storage's Comparable EBITDA for the three and nine month periods ended September 30, 2010, was $26 million and $95 million, respectively, compared to $45 million and $115 million for the same periods in 2009. The decrease in Comparable EBITDA in third quarter 2010 was primarily due to decreased proprietary and third party storage revenues as a result of lower realized natural gas price spreads.

Comparable EBITDA excluded net unrealized gains of $7 million and net unrealized losses of $8 million in the three and nine months ended September 30, 2010, respectively (2009 - gains of $14 million and losses of $6 million, respectively), resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. TransCanada manages its proprietary natural gas storage earnings by simultaneously entering into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to price movements of natural gas. Fair value adjustments recorded in each period on proprietary natural gas inventory in storage and these forward contracts are not representative of the amounts that will be realized on settlement. The fair value of proprietary natural gas inventory in storage has been measured using a weighted average of forward prices for the following four months less selling costs.

Other Income Statement Items

Interest Expense

                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Interest on long-term debt(1)             310       317       903       981 
Other interest and amortization             9        12        62        19 
Capitalized interest                     (160)     (113)     (437)     (230)
                                    ---------- --------- --------- ---------
                                          159       216       528       770 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------

(1) Includes interest for Junior Subordinated Notes. 

Interest Expense for third quarter 2010 decreased $57 million to $159 million from $216 million in third quarter 2009 and for the nine months ended September 30, 2010 decreased $242 million to $528 million from $770 million for the nine months ended September 30, 2009. These decreases reflected increased capitalized interest to finance the Company's capital growth program in 2010, primarily due to Keystone construction, and the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest. These decreases were partially offset by incremental interest expense on new debt issues of US$1.25 billion in June 2010 and $700 million in February 2009. The increase in Other Interest and Amortization for the nine months ended September 30, 2010 compared to 2009 was primarily due to higher losses in 2010 compared to 2009 from changes in the fair value of derivatives used to manage the Company's exposure to rising interest rates.

Interest Income and Other for third quarter 2010 decreased $16 million to $27 million from $43 million in third quarter 2009 and for the nine months ended September 30, 2010 decreased $66 million to $33 million from $99 million for the nine months ended September 2009. These decreases reflect the impact of a fluctuating U.S. dollar on the translation of U.S. dollar-denominated working capital balances. The decrease for the nine months ended September 30, 2010 was also due to lower gains in 2010 compared to 2009 from derivatives used to manage the Company's exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Income Taxes for the three and nine months ended September 30, 2010 were $120 million and $286 million, respectively, compared to $107 million and $320 million, respectively, for the same periods in 2009. The increase for third quarter 2010 compared to 2009 was primarily due to higher pre-tax earnings. The decrease for the nine months ended September 30, 2010 compared to 2009 was primarily due to the net positive impact from income tax rate differentials, other income tax adjustments and lower pre-tax earnings.

Liquidity and Capital Resources

TransCanada's financial position remains sound and consistent with recent years as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, and to provide for planned growth. TransCanada's liquidity position remains solid, underpinned by predictable cash flow from operations, significant cash balances on hand from recent preferred share and debt issues, as well as unutilized committed revolving bank lines of US$1.0 billion, $2.0 billion and US$1.0 billion, maturing in November 2011, December 2012 and December 2012, respectively. These facilities also support the Company's two commercial paper programs in Canada. In addition, TransCanada's proportionate share of unutilized capacity on committed bank facilities at TransCanada-operated affiliates was $118 million with maturity dates from 2011 through 2012. As at September 30, 2010, TransCanada had remaining capacity of $1.75 billion, $2.0 billion and US$1.75 billion under its equity, Canadian debt and U.S. debt shelf prospectuses, respectively. In lieu of making cash dividend payments, a portion of declared common and preferred share dividends are expected to be paid in common shares issued under the Company's Dividend Reinvestment and Share Purchase Plan (DRP). TransCanada's liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section of this MD&A.

At September 30, 2010, the Company held Cash and Cash Equivalents of $1.1 billion compared to $1.0 billion at December 31, 2009. The increase in Cash and Cash Equivalents was primarily due to cash generated from operations, proceeds from the issuance of senior notes in second and third quarter 2010 and preferred shares in first and second quarter 2010, partially offset by capital expenditures and dividend payments.

Operating Activities

Funds Generated from Operations(1)

                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Cash Flows                                                                  
 Funds generated from operations(1)       861       772     2,519     2,230 
 (Increase)/decrease in operating                                           
  working capital                         (70)     (201)     (271)      127 
                                     --------- --------- --------- ---------
 Net cash provided by operations          791       571     2,248     2,357 
                                     --------- --------- --------- ---------
                                     --------- --------- --------- ---------
                                                                            

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

Net Cash Provided by Operations increased $220 million and decreased $109 million for the three and nine months ended September 30, 2010, respectively, compared to the same periods in 2009, reflecting increases in Funds Generated from Operations and changes in operating working capital. Funds Generated from Operations for the three and nine months ended September 30, 2010 were $861 million and $2.5 billion, respectively, compared to $772 million and $2.2 billion for the same periods in 2009. The increases for the three and nine months ended September 30, 2010 were primarily due to the income tax benefit generated from bonus depreciation for U.S. tax purposes on Keystone assets placed into service on June 30, 2010 and an increase in cash generated through earnings.

Investing Activities

TransCanada remains committed to executing its $21 billion capital expenditure program. For the three and nine months ended September 30, 2010, capital expenditures totalled $1.3 billion and $3.6 billion, respectively (2009 - $1.6 billion and $3.9 billion, respectively), primarily related to the construction of Keystone, refurbishment and restart of Bruce A Units 1 and 2, expansion of the Alberta System, and construction of the Bison and Guadalajara natural gas pipelines and Coolidge and Halton Hills power plants.

Financing Activities

In September 2010, TCPL issued US$1.0 billion of senior notes maturing October 1, 2020 and bearing interest at 3.80 per cent. These notes were issued under the US$4.0 billion debt shelf prospectus filed in December 2009. The net proceeds of this offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

In June 2010, TransCanada completed a public offering of 14 million Series 5 cumulative redeemable first preferred shares, including the full exercise of an underwriters' option of two million shares, under its September 2009 base shelf prospectus. The preferred shares were issued at a price of $25 per share, resulting in gross proceeds of $350 million including the underwriters' option. The holders of the Series 5 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.10 per share, payable quarterly, yielding 4.4 per cent per annum for the initial five and a half year period ending January 30, 2016. The dividend rate will reset on January 30, 2016 and every five years thereafter to a yield per annum equal to the sum of the then five year Government of Canada bond yield and 1.54 per cent. The Series 5 preferred shares are redeemable by TransCanada on January 30, 2016 and on January 30 of every fifth year thereafter. The net proceeds of this offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

The Series 5 preferred shareholders will have the right to convert their shares into Series 6 cumulative redeemable first preferred shares on January 30, 2016 and on January 30 of every fifth year thereafter. The holders of Series 6 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90 day Government of Canada treasury bill rate and 1.54 per cent.

In June 2010, TCPL issued senior notes of US$500 million and US$750 million maturing on June 1, 2015 and June 1, 2040, respectively, and bearing interest at 3.40 per cent and 6.10 per cent, respectively. These notes were issued under the US$4.0 billion debt shelf prospectus filed in December 2009. The net proceeds of this offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

In March 2010, TransCanada completed a public offering of 14 million Series 3 cumulative redeemable first preferred shares, including the full exercise of an underwriters' option of two million shares, under its September 2009 base shelf prospectus. The preferred shares were issued at a price of $25 per share, resulting in gross proceeds of $350 million including the underwriters' option. The holders of the Series 3 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly, yielding 4.0 per cent per annum for the initial five year period ending June 30, 2015. The dividend rate will reset on June 30, 2015 and every five years thereafter to a yield per annum equal to the sum of the then five year Government of Canada bond yield and 1.28 per cent. The Series 3 preferred shares are redeemable by TransCanada on June 30, 2015 and on June 30 of every fifth year thereafter. The net proceeds of this offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

The Series 3 preferred shareholders will have the right to convert their shares into Series 4 cumulative redeemable first preferred shares on June 30, 2015 and on June 30 of every fifth year thereafter. The holders of Series 4 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90 day Government of Canada treasury bill rate and 1.28 per cent.

The Company is well positioned to fund its existing capital program through its internally-generated cash flow, its DRP and its continued access to capital markets. TransCanada will also continue to examine opportunities for portfolio management, including a role for PipeLines LP, in financing its capital program.

Dividends

On November 2, 2010, TransCanada's Board of Directors declared a quarterly dividend of $0.40 per share for the quarter ending December 31, 2010 on the Company's outstanding common shares. It is payable on January 31, 2011 to shareholders of record at the close of business on December 31, 2010. In addition, quarterly dividends of $0.2875 and $0.25 per preferred share were declared for Series 1 and Series 3 preferred shares, respectively, for the period ending December 31, 2010. The dividends are payable on December 31, 2010 to shareholders of record at the close of business on November 30, 2010. A quarterly dividend of $0.275 per preferred share was declared for Series 5 preferred shares for the period ending January 30, 2011. It is payable on January 31, 2011 to shareholders of record at the close of business on December 31, 2010.

TransCanada's Board of Directors approved the issuance of common shares from treasury at a three per cent discount under TransCanada's DRP for dividends payable on TransCanada's common and preferred shares, and TCPL's preferred shares. The Company reserves the right to alter the discount or return to fulfilling DRP participation by purchasing shares on the open market at any time. In the three and nine months ended September 30, 2010, TransCanada issued 2.9 million and 7.8 million (2009 - 2.5 million and 6.0 million) common shares, respectively, under its DRP, in lieu of making cash dividend payments of $101 million and $271 million, respectively (2009 - $73 million and $182 million, respectively).

Significant Accounting Policies and Critical Accounting Estimates

To prepare financial statements that conform with Canadian GAAP, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions.

TransCanada's significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2009. For further information on the Company's accounting policies and estimates refer to the MD&A in TransCanada's 2009 Annual Report.

Changes in Accounting Policies

The Company's accounting policies have not changed materially from those described in TransCanada's 2009 Annual Report. Future accounting changes that will impact the Company are as follows:

Future Accounting Changes

International Financial Reporting Standards

The Canadian Institute of Chartered Accountants' (CICA) Accounting Standards Board (AcSB) previously announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. As an SEC registrant, TransCanada prepares and files a "Reconciliation to United States GAAP" and also has the option to instead prepare and file its consolidated financial statements using U.S. GAAP. Previously, TransCanada disclosed that effective January 1, 2011, the Company expected to begin reporting under IFRS. Prior to the developments noted below, the Company's IFRS conversion project was proceeding as planned to meet the January 1, 2011 conversion date.

Rate-Regulated Accounting

In accordance with Canadian GAAP, TransCanada currently follows specific accounting policies unique to a rate-regulated business. These rate-regulated accounting (RRA) standards allow the timing of recognition of certain expenses and revenues to differ from that which may otherwise be expected under Canadian GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. These timing differences are recorded as regulatory assets and regulatory liabilities on TransCanada's consolidated balance sheet and represent current rights and obligations regarding cash flows expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities. As at September 30, 2010, TransCanada reported $1.7 billion of regulatory assets and $0.4 billion of regulatory liabilities using RRA in addition to certain other impacts of RRA.

In July 2009, the IASB issued an Exposure Draft "Rate-Regulated Activities" which proposed a form of RRA under IFRS. At its September 2010 meeting, the IASB concluded that the development of RRA under IFRS requires further analysis. The IASB is now considering what form a future project might take, if any, to address RRA. As a result of these developments, TransCanada does not expect a final RRA standard under IFRS to be effective for 2011.

In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises that use RRA in order to permit these entities to defer the adoption of IFRS for one year. Due to the continued uncertainty around the timing, scope and eventual adoption of an RRA standard under IFRS, TransCanada will defer its adoption of IFRS accordingly and continue preparing its consolidated financial statements in 2011 in accordance with Canadian GAAP in order to continue using RRA. During the deferral period, TransCanada will continue to actively monitor IASB developments with respect to RRA and other IFRS, but has also undertaken a project to position the Company to instead adopt U.S. GAAP. During the one year deferral period, if it is determined through absence of a new RRA standard or through application of existing IFRS that TransCanada cannot apply RRA under IFRS, the Company expects to re-evaluate its decision to adopt IFRS and, instead, adopt U.S. GAAP.

As a result of these developments related to RRA under IFRS, TransCanada cannot reasonably quantify the full impact that adopting IFRS would have on its financial position and future results if it proceeded with adopting IFRS. Alternatively, the impact of adopting U.S. GAAP is expected to be consistent with that currently reported in its publicly filed "Reconciliation to United States GAAP".

Contractual Obligations

At September 30, 2010, TransCanada had entered into agreements since December 31, 2009 totalling approximately $395 million to purchase construction materials and services for the Cartier Wind power and Bison natural gas pipeline projects. Other than these commitments and expected increased payments for long-term debt resulting from new debt issuances as discussed in the Liquidity and Capital Resources section of this MD&A, there have been no material changes to TransCanada's contractual obligations from December 31, 2009 to September 30, 2010, including payments due for the next five years and thereafter. TransCanada is currently assessing the impact on its contractual obligations resulting from the Government of Ontario's announcement of the cancellation of the Oakville power project. For further information on the Company's contractual obligations, refer to the MD&A in TransCanada's 2009 Annual Report.

Financial Instruments and Risk Management

TransCanada continues to manage and monitor its exposure to counterparty credit, liquidity and market risk.

Counterparty Credit and Liquidity Risk

TransCanada's maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, the fair value of derivative assets and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table below. Letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At September 30, 2010, there were no significant amounts past due or impaired.

At September 30, 2010, the Company had a credit risk concentration of $308 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.

The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions.

Natural Gas Inventory

At September 30, 2010, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $52 million (December 31, 2009 - $73 million). The change in fair value of proprietary natural gas inventory in storage in the three and nine months ended September 30, 2010 resulted in net pre-tax unrealized losses of $1 million and $20 million, respectively (2009 - gains of $16 million and losses of $13 million, respectively), which were recorded as a decrease in Revenues and Inventories. The change in fair value of natural gas forward purchase and sale contracts in the three and nine months ended September 30, 2010 resulted in net pre-tax unrealized gains of $8 million and $12 million, respectively (2009 - losses of $2 million and gains of $7 million, respectively), which were included in Revenues.

VaR Analysis

TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its liquid open positions. VaR represents the potential change in pre-tax earnings over a given holding period. It is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its open positions will not exceed the reported VaR. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada's consolidated VaR was $6 million at September 30, 2010 (December 31, 2009 - $12 million). The decrease from December 31, 2009 was primarily due to decreased commodity prices, reduced price volatility and fewer open positions in the U.S. Power portfolio.

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations (on an after tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At September 30, 2010, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $10.1 billion (US$9.8 billion) and a fair value of $12.1 billion (US$11.8 billion). At September 30, 2010, $91 million (December 31, 2009 - $96 million) was included in Intangibles and Other Assets for the fair value of forwards and swaps used to hedge the Company's net U.S. dollar investment in foreign operations.

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

Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations

                                   September 30, 2010     December 31, 2009 
                                 --------------------- ---------------------
                                 --------------------- ---------------------
                                             Notional              Notional 
Asset/(Liability)                                  or                    or 
(unaudited)                         Fair    Principal     Fair    Principal 
(millions of dollars)            Value(1)      Amount  Value(1)      Amount 
----------------------------------------- ------------ -------- ------------
----------------------------------------- ------------ -------- ------------
                                                                            
U.S. dollar cross-currency swaps                                            
 (maturing 2010 to 2015)              87   U.S. 2,150       86   U.S. 1,850 
U.S. dollar forward foreign                                                 
 exchange contracts                                                         
 (maturing 2010)                       4     U.S. 400        9     U.S. 765 
U.S. dollar foreign exchange                                                
 options (matured 2010)                -            -        1     U.S. 100 
                                                                            
                                 --------- ----------- --------- -----------
                                                                   
                                      91   U.S. 2,550       96   U.S. 2,715 
                                 --------- ----------- --------- -----------
                                 --------- ----------- --------- -----------

(1) Fair values equal carrying values. 


Non-Derivative Financial Instruments Summary

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

                                   September 30, 2010     December 31, 2009 
                                 --------------------- ---------------------
                                 --------------------- ---------------------
(unaudited)                       Carrying       Fair   Carrying       Fair 
(millions of dollars)               Amount      Value     Amount      Value 
------------------------------------------- ---------- ---------- ----------
------------------------------------------- ---------- ---------- ----------
                                                                            
Financial Assets(1)                                                         
Cash and cash equivalents            1,094      1,094        997        997 
Accounts receivable and                                                     
 other(2)(3)                         1,557      1,615      1,432      1,483 
Available-for-sale assets(2)            23         23         23         23 
                                 ---------- ---------- ---------- ----------
                                     2,674      2,732      2,452      2,503 
                                 ---------- ---------- ---------- ----------
                                 ---------- ---------- ---------- ----------
                                                                            
Financial Liabilities(1)(3)                                                 
Notes payable                        1,613      1,613      1,687      1,687 
Accounts payable and deferred                                               
 amounts(4)                          1,298      1,298      1,538      1,538 
Accrued interest                       325        325        377        377 
Long-term debt                      18,383     22,710     16,664     19,377 
Junior subordinated notes            1,020        968      1,036        976 
Long-term debt of joint ventures       889      1,021        965      1,025 
                                 ---------- ---------- ---------- ----------
                                    23,528     27,935     22,267     24,980 
                                 ---------- ---------- ---------- ----------
                                 ---------- ---------- ---------- ----------

(1) Consolidated Net Income in 2010 included gains of $11 million (2009 - $9
    million) for fair value adjustments related to interest rate swap
    agreements on US$150 million (2009 - US$300 million) of long-term debt.
    There were no other unrealized gains or losses from fair value
    adjustments to the financial instruments.
(2) At September 30, 2010, the Consolidated Balance Sheet included financial
    assets of $1,123 million (December 31, 2009 - $966 million) in Accounts
    Receivable, $41 million (December 31, 2009 - nil) in Other Current 
    Assets and $416 million (December 31, 2009 - $489 million) in 
    Intangibles and Other Assets.
(3) Recorded at amortized cost, except for certain long-term debt which is
    recorded at fair value. 
(4) At September 30, 2010, the Consolidated Balance Sheet included financial
    liabilities of $1,261 million (December 31, 2009 - $1,513 million) in
    Accounts Payable and $37 million (December 31, 2009 - $25 million) in
    Deferred Amounts.


Derivative Financial Instruments Summary

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

September 30, 2010                                                          
(unaudited) (all amounts in                                                 
 millions unless otherwise                Natural       Foreign             
 indicated)                      Power        Gas      Exchange    Interest 
--------------------------------------- ---------- ------------- -----------
--------------------------------------- ---------- ------------- -----------
                                                                            
Derivative Financial                                                        
 Instruments Held for                                                       
 Trading(1)                                                                 
 Fair Values(2)                                                             
 Assets                      $     238  $     176             -  $       27 
 Liabilities                 $    (189) $    (179) $         (9) $      (38)
Notional Values                                                             
 Volumes(3)                                                                 
  Purchases                     15,466        114             -           - 
  Sales                         17,965         96             -           - 
Canadian dollars                     -          -             -         759 
U.S. dollars                         -          -    U.S. 1,189    U.S. 350 
Cross-currency                       -          -    47/U.S. 37           - 
                                                                            
Net unrealized                                                              
 (losses)/gains in the                                                      
 period(4)                   $      (1) $       4  $         10  $       50 
 Three months ended                                                         
  September 30, 2010                                                        
 Nine months ended September                                                
  30, 2010                   $     (27) $       9  $         (1) $       33 
                                                                            
Net realized gains/(losses)                                                 
 in the period(4)                                                           
 Three months ended                                                         
  September 30, 2010         $      13  $     (10) $          6  $      (54)
 Nine months ended September                                                
  30, 2010                   $      50  $     (39) $          8  $      (64)
                                                                            
Maturity dates               2010-2015  2010-2015     2010-2012   2010-2016 
                                                                            
Derivative Financial                                                        
 Instruments in Hedging                                                     
 Relationships(5)(6)                                                        
Fair Values(2)                                                              
 Assets                      $     163          -             -  $       11 
 Liabilities                 $    (256) $     (85) $        (44) $      (36)
Notional Values                                                             
 Volumes(3)                                                                 
  Purchases                     15,563         60             -           - 
  Sales                         12,655          -             -           - 
U.S. dollars                         -          -      U.S. 120  U.S. 1,025 
Cross-currency                       -          -  136/U.S. 100           - 
                                                                            
Net realized gains/(losses)                                                 
 in the period(4)                                                           
 Three months ended                                                         
  September 30, 2010         $      37  $     (19)            -  $       (7)
 Nine months ended September                                                
  30, 2010                   $      (6) $     (28)            -  $      (26)
                                                                            
Maturity dates               2010-2015  2010-2013     2010-2014   2011-2013 
                             ---------- ---------- ------------- -----------
                             ---------- ---------- ------------- -----------

(1) All derivative financial instruments in the held-for-trading
    classification have been entered into for risk management purposes and
    are subject to the Company's risk management strategies, policies and
    limits. These include derivatives that have not been designated as
    hedges or do not qualify for hedge accounting treatment but have been
    entered into as economic hedges to manage the Company's exposures to
    market risk.
(2) Fair values equal carrying values. 
(3) Volumes for power and natural gas derivatives are in GWh and Bcf,
    respectively.
(4) Realized and unrealized gains and losses on power and natural gas
    derivative financial instruments held for trading are included 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 unrealized gains and losses on
    derivative financial instruments in hedging relationships are initially
    recognized in Other Comprehensive Income and are 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 $11 million and a notional amount of US$150
    million. Net realized gains on fair value hedges for the three and nine
    months ended September 30, 2010 were $1 million and $3 million,
    respectively, and were included in Interest Expense. In third quarter
    2010, the Company did not record any amounts in Net Income related to
    ineffectiveness for fair value hedges.
(6) Losses included in Net Income for the three and nine months ended
    September 30, 2010 were nil and $1 million, respectively, for changes in
    the fair value of power and natural gas cash flow hedges that were
    ineffective in offsetting the change in fair value of their related
    underlying positions. There were no gains or losses included in Net
    Income for the three and nine months ended September 30, 2010 for
    discontinued cash flow hedges. No amounts have been excluded from the
    assessment of hedge effectiveness. 


2009                                                                        
(unaudited)                                                                 
 (all amounts                                                               
 in millions                                                                
 unless                                                                     
 otherwise                  Natural         Oil        Foreign              
 indicated)       Power         Gas    Products       Exchange     Interest 
------------------------  ---------- -----------  -------------  -----------
------------------------  ---------- -----------  -------------  -----------
                                                                            
Derivative                                                                  
 Financial                                                                  
 Instruments                                                                
 Held for                                                                   
 Trading                                                                    
Fair                                                                        
 Values(1)(2)                                                               
 Assets       $     150   $     107  $        5              -   $       25 
 Liabilities  $     (98)  $    (112) $       (5)  $        (66)  $      (68)
Notional                                                                    
 Values(2)                                                                  
Volumes(3)                                                                  
Purchases        15,275         238         180              -            - 
Sales            13,185         194         180              -            - 
Canadian                                                                    
 dollars              -           -           -              -          574 
U.S. dollars          -           -           -       U.S. 444   U.S. 1,325 
Cross-                                                                      
 currency             -           -           -  227/ U.S. 157            - 
                                                                            
Net                                                                         
 unrealized                                                                 
 (losses)/gains                                                             
 in the                                                                  
 period(4)                                                                  
Three months                                                                
 ended                                                                      
 September                                                                  
 30, 2009     $      (8)  $      21  $       (1)  $          2   $       (7)
Nine months                                                                 
 ended                                                                      
 September                                                                  
 30, 2009     $      11   $      (4) $        1   $          4   $       20 
                                                                            
Net realized                                                                
 gains/(losses)                                                             
 in the                                                                  
 period(4)                                                                  
Three months                                                                
 ended                                                                      
 September                                                                  
 30, 2009     $      23   $     (43) $        1   $         11   $       (5)
Nine months                                                                 
 ended                                                                      
 September                                                                  
 30, 2009     $      53   $     (56)          -   $         28   $      (14)
                                                                            
Maturity                                                                    
 dates(2)     2010-2015   2010-2014        2010      2010-2012    2010-2018 
                                                                            
Derivative                                                                  
 Financial                                                                  
 Instruments                                                                
 in Hedging                                                                 
 Relationships                                                              
 (5)(6)                                                                    
Fair                                                                        
 Values(1)(2)                                                               
 Assets       $     175   $       2           -              -   $       15 
 Liabilities  $    (148)  $     (22)          -   $        (43)  $      (50)
Notional                                                                    
 Values(2)                                                                  
Volumes(3)                                                                  
 Purchases       13,641          33           -              -            - 
 Sales           14,311           -           -              -            - 
U.S. dollars          -           -           -       U.S. 120   U.S. 1,825 
Cross-                                                                      
 currency             -           -           -   136/U.S. 100            - 
                                                                            
Net realized                                                                
 gains/(losses)                                                             
 in the                                                                  
 period(4)                                                                  
Three months                                                                
 ended                                                                      
 September                                                                  
 30, 2009     $      30   $      (8)          -              -   $      (10)
Nine months                                                                 
 ended                                                                      
 September                                                                  
 30, 2009     $     108   $     (28)          -              -   $      (27)
                                                                            
Maturity                                                                    
 dates(2)     2010-2015   2010-2014         n/a      2010-2014    2010-2020 
             ----------- ----------- ----------- -------------- ------------
             ----------- ----------- ----------- -------------- ------------

(1) Fair values equal carrying values. 
(2) As at December 31, 2009. 
(3) Volumes for power, natural gas and oil products derivatives are in GWh,
    Bcf and thousands of barrels, respectively. 
(4) Realized and unrealized gains and losses on power, natural gas and oil
    products derivative financial instruments held for trading are included
    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 unrealized gains and losses on
    derivative financial instruments in hedging relationships are initially
    recognized in Other Comprehensive Income and are 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 $4 million and a notional amount of US$150
    million at December 31, 2009. Net realized gains on fair value hedges
    for the three and nine months ended September 30, 2009 were $1 million
    and $3 million, respectively, and were included in Interest Expense. In
    third quarter 2009, the Company did not record any amounts in Net Income
    related to ineffectiveness for fair value hedges. 
(6) Net Income for the three and nine months ended September 30, 2009
    included gains of $1 million and $2 million, respectively, for changes
    in the fair value of power and natural gas cash flow hedges that were
    ineffective in offsetting the change in fair value of their related
    underlying positions. There were no gains or losses included in Net
    Income for the three and nine months ended September 30, 2009 for
    discontinued cash flow hedges. No amounts have been excluded from the
    assessment of hedge effectiveness. 


Balance Sheet Presentation of Derivative Financial Instruments

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

(unaudited)                                                                 
(millions of dollars)                           September 30,   December 31,
                                                        2010           2009 
------------------------------------------------------------- --------------
------------------------------------------------------------- --------------
                                                                            
Current                                                                     
 Other current assets                                    357            315 
 Accounts payable                                       (442)          (340)
                                                                            
Long-term                                                                   
 Intangibles and other assets                            349            260 
 Deferred amounts                                       (394)          (272)
                                              --------------- --------------
                                              --------------- --------------

Controls and Procedures

As of September 30, 2010, an evaluation was carried out under the supervision of, and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of TransCanada's disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of TransCanada's disclosure controls and procedures were effective as at September 30, 2010.

During the recent fiscal quarter, there have been no changes in TransCanada's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, TransCanada's internal control over financial reporting.

Outlook

Since the disclosure in TransCanada's 2009 Annual Report, the Company's earnings outlook for 2010 has declined due to the continued negative impact of reduced market prices for power on Energy's results. As discussed in the Recent Developments section of this MD&A, the Company has delayed recognition of EBITDA from Keystone, which is to be offset by higher capitalized interest. For further information on outlook, refer to the MD&A in TransCanada's 2009 Annual Report.

Recent Developments

Pipelines

Keystone

The first phase of Keystone extending from Hardisty, Alberta has commenced serving markets in Wood River and Patoka, Illinois. As part of the NEB's approval to begin operations, Keystone will operate at a reduced maximum operating pressure (MOP) on the Canadian conversion segment of the pipeline, which will reduce throughput capacity below the initial nominal capacity of 435,000 barrels per day (Bbl/d). Additional in-line inspections have been completed and approval from the NEB to remove the MOP restriction is anticipated in fourth quarter 2010.

Construction of the second phase of Keystone to expand nominal capacity to 591,000 Bbl/d and extend the pipeline to Cushing, Oklahoma was over 90 per cent complete at September 30, 2010. Commercial in service of this phase is expected in first quarter 2011.

Keystone is planning to construct and operate an expansion and extension of the pipeline system that will provide additional capacity of 500,000 Bbl/d from Western Canada to the U.S. Gulf Coast in first quarter 2013. The Keystone Gulf Coast expansion will extend from Hardisty to a delivery point near Port Arthur, Texas. In March 2010, the NEB approved the Company's application to construct and operate the Canadian portion of the Keystone expansion. In April 2010, the Department of State, the lead agency for U.S. federal regulatory approvals, issued a Draft Environmental Impact Statement which concluded that Keystone's expansion to the Gulf Coast would have limited environmental impact. The regulatory process conducted by the Department of State continues with final regulatory approvals expected in the first half of 2011. Construction is expected to begin shortly thereafter.

On September 7, 2010, to address market demands, TransCanada commenced a binding open season to obtain firm commitments for the Cushing Marketlink Project, which would transport crude oil from Cushing to the U.S. Gulf Coast. If the open season, which is expected to close in November 2010, is successful, commercial in service is anticipated in first quarter 2013.

In response to significant market demand, the Company is pursuing opportunities to attract growing Bakken shale crude oil production from the Williston Basin in Montana and North Dakota to Keystone for delivery to major U.S. refining markets. On September 13, 2010, the Company commenced a binding open season to obtain firm commitments from interested parties for the Bakken Marketlink Project, which would transport crude oil from Baker, Montana to Cushing and to the U.S. Gulf Coast. If the open season, which is expected to close in November 2010, is successful, commercial in service is anticipated in first quarter 2013.

The total capital cost of Keystone is expected to be approximately US$12 billion. Approximately US$7 billion has been spent to date, including approximately US$1 billion for the expansion to the Gulf Coast, with the remaining US$5 billion to be invested between now and the end of 2012. Capital costs related to the construction of Keystone are subject to capital cost risk- and reward-sharing mechanisms with its customers.

Although the first phase of Keystone is now in commercial service, cash flow related to Keystone, other than general, administrative and support costs, is being capitalized until the MOP restriction has been removed and the pipeline is capable of operating at pipeline design pressure. Following this, TransCanada expects Keystone to begin recording EBITDA, which is anticipated to increase through 2011, 2012 and 2013 as subsequent phases are placed in service. Based on current long-term commitments of 910,000 Bbl/d, Keystone is expected to generate EBITDA of approximately US$1.2 billion in 2013, its first full year of commercial operation serving both the U.S. Midwest and Gulf Coast markets. If volumes increase to 1.1 million Bbl/d, the full commercial design of the system, Keystone would generate approximately US$1.5 billion of annual EBITDA. In the future, Keystone can be economically expanded from 1.1 million Bbl/d to 1.5 million Bbl/d in response to additional market demand.

Canadian Mainline

In any year, tolls on the Canadian Mainline are partially based on projected throughput volumes for the year. Estimated throughput volumes for 2010 are now expected to be lower than was used in setting the tolls for 2010. As a result, amounts collected through tolls are projected to be approximately 15 per cent less than anticipated in 2010. This shortfall is deferred for accounting purposes as it is expected to be collected in future tolls under the framework regulated by the NEB.

TransCanada continues to work with stakeholders on developing rate and service changes that respond to changing market dynamics, and a related NEB filing is anticipated before the end of the year.

TransCanada's second open season to transport Marcellus volumes on the Canadian Mainline closed on August 25, 2010. This second open season was initiated at the request of prospective shippers and TransCanada received over 1.0 billion cubic feet per day (Bcf/d) of interest. A precedent agreement from the first open season was terminated by a customer who re-bid in the second open season. In October 2010, TransCanada issued precedent agreements to the bidders in the second open season which will form the basis for TransCanada to assess options to meet these service requests and provide support for any related regulatory filings.

Alberta System

In August 2010, the NEB approved the Company's application for the Alberta System's Rate Design Settlement and the Integration of the ATCO Pipelines System with the Alberta System. This approval, which is the product of many months of collaborative work with stakeholders, will permit the provision of streamlined natural gas transmission service to Alberta System customers under a new rate structure that reflects the current business environment.

In September 2010, the NEB approved the Alberta System's 2010 - 2012 Revenue Requirement Settlement Application, which is the result of extensive stakeholder discussions. The settlement has a three year term and:

--  incorporates a return of 9.70 per cent on 40 per cent deemed common
    equity, which is an increase from the return of 8.75 per cent on 35 per
    cent deemed common equity previously reflected in 2010 results; 
--  fixes certain annual OM&A costs at $174 million; and 
--  provides flow-through treatment of other costs. 

On October 19, 2010, the NEB approved final rates for the Alberta System, which reflect the Alberta System Settlement and the Rate Design Settlement.

In August 2010, the Company received final regulatory approvals and commenced construction of the Groundbirch pipeline. When complete, the approximately $155 million natural gas pipeline will extend the Alberta System into northeast B.C. and connect to natural gas supplies in the Montney shale gas formation. Construction and commissioning is expected to be complete in November 2010. Groundbirch has firm transportation contracts for 1.1 Bcf/d by 2014.

The NEB hearing relating to the Horn River pipeline project is expected to conclude on November 9, 2010 and a decision is expected in first quarter 2011. The approximately $310 million project is scheduled to be operational in second quarter 2012 with commitments for contracted natural gas of approximately 540 million cubic feet per day (mmcf/d) by 2014.

TransCanada continues to advance further pipeline development in B.C. and Alberta to transport unconventional shale gas supply. The Company has received requests for additional natural gas transmission service throughout the northwest portion of the Western Canadian Sedimentary Basin, including the Horn River and Montney areas of B.C. These new requests are expected to result in the need for further extensions and expansions of the Alberta System.

TQM

In July 2010, TQM reached a multi-year settlement agreement with interested parties regarding its annual revenue requirement for 2010, 2011 and 2012. The settlement includes an annual revenue requirement which consists of flow-through and fixed components. Variances between actual costs and those included in the fixed component, comprised of certain OM&A costs, return on rate base, depreciation and municipal taxes, accrue to TQM. In August 2010, the Company filed an application with the NEB requesting regulatory approval of the negotiated settlement. A decision from the NEB is expected in fourth quarter 2010.

Bison

In third quarter 2010, TransCanada received final approvals for the Bison natural gas pipeline project. The Company commenced construction in July 2010 on the approximately US$600 million project which is anticipated to be in service in fourth quarter 2010. The project has long-term contracts for 407 mmcf/d.

Alaska

Interested shippers on the proposed Alaska Pipeline Project submitted conditional commercial bids in the open season that closed July 30, 2010. The project is now working with shippers to resolve those conditions within the project's control. Discussions are expected to be completed over the next several months.

Guadalajara

Construction continues on the approximately US$320 million Guadalajara natural gas pipeline project in Mexico, which will transport natural gas from Manzanillo to Guadalajara. The pipeline has a contractual in-service date of first quarter 2011 and was approximately 40 per cent complete at September 30, 2010.

Energy

Bruce

Refurbishment work on Bruce A Units 1 and 2 reached a major milestone in October 2010 with the successful installation of the last of the 960 calandria tubes. Atomic Energy of Canada Limited (AECL) has begun de-staffing and will be substantially demobilized from Unit 2 by the end of 2010 and from Unit 1 by second quarter 2011. As a result of experience gained from Unit 2 activities, the project has seen improvements in the amount of time required to complete similar activities for Unit 1.

Subject to regulatory approval, Bruce expects to load fuel in Unit 2 in second quarter 2011 and achieve a first synchronization of the generator to the electrical grid by the end of 2011, with commercial operation expected to occur in first quarter 2012. Bruce expects to load fuel in Unit 1 in third quarter 2011 with a first synchronization of the generator in first quarter 2012 and commercial operation is expected to occur during third quarter 2012.

Plant commissioning and testing is underway and will accelerate at the end of second quarter 2011 when construction activities are essentially complete. TransCanada's share of the total capital cost is expected to be approximately $2.4 billion.

Halton Hills

The $700 million Halton Hills generating station went into service on September 1, 2010, on time and on budget. Power from the 683 MW natural gas-fired power plant near Halton Hills, Ontario will be sold to the OPA under a 20 year Clean Energy Supply contract.

Kibby Wind

The 66 MW second phase of the Kibby Wind power project went into service on October 26, 2010. This phase included the installation of an additional 22 turbines, which were all erected ahead of schedule. The two phases of the project will produce a combined 132 MW and have a capital cost of US$350 million.

Coolidge

Construction of the 575 MW Coolidge generating station was approximately 90 per cent complete at September 30, 2010. The approximately US$500 million generating station is anticipated to be in service by second quarter 2011.

Oakville

On October 7, 2010, the Government of Ontario announced that it would not proceed with the Oakville generating station. TransCanada has commenced negotiations with the OPA on a settlement which would terminate the Clean Energy Supply contract and compensate TransCanada for the economic consequences associated with the contract's termination.

Share Information

As at October 29, 2010, TransCanada had 696 million issued and outstanding common shares, and nine million outstanding options to purchase common shares, of which seven million were exercisable. As at October 29, 2010, TransCanada had 22 million Series 1, 14 million Series 3 and 14 million Series 5 issued and outstanding preferred shares that are convertible to 22 million Series 2, 14 million Series 4 and 14 million Series 6 preferred shares, respectively.

Selected Quarterly Consolidated Financial Data(1)

(unaudited)                 2010                     2009              2008 
                   --------------------- --------------------------- -------
                   --------------------- --------------------------- -------
(millions of                                                                
 dollars except per                                                         
 share amounts)     Third Second  First  Fourth  Third Second First  Fourth 
---------------------------------------- --------------------------- -------
---------------------------------------- --------------------------- -------
                                                                            
Revenues            2,129  1,923  1,955   1,986  2,049  1,984 2,162   2,234 
Net Income            391    295    303     387    345    314   334     277 
                                                                            
Share Statistics                                                            
Net income per                                                              
 common share -                                                             
 Basic             $ 0.54 $ 0.41 $ 0.43  $ 0.56 $ 0.50 $ 0.50 $ 0.54 $ 0.47 
Net income per                                                              
 common share -                                                             
 Diluted           $ 0.54 $ 0.41 $ 0.43  $ 0.56 $ 0.50 $ 0.50 $ 0.54 $ 0.46 
                                                                            
Dividend declared                                                           
 per common share  $ 0.40 $ 0.40 $ 0.40  $ 0.38 $ 0.38 $ 0.38 $ 0.38 $ 0.36 
                   --------------------- --------------------------- -------
                   --------------------- --------------------------- -------

(1) The selected quarterly consolidated financial data has been prepared in
    accordance with Canadian GAAP. Certain comparative figures have been
    restated to conform with the current year's presentation. 

Factors Impacting Quarterly Financial Information

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

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

Significant developments that impacted the last eight quarters' EBIT and Net Income are as follows:

--  Third quarter 2010, Pipelines' EBIT increased as a result of recording
    nine months of incremental earnings related to the Alberta System 2010 -
    2012 Revenue Requirement Settlement, which resulted in a $33 million
    increase to Net Income. Energy's EBIT included contributions from Halton
    Hills, which was placed in service in September 2010, and net unrealized
    losses of $3 million pre-tax ($2 million after tax) resulting from
    changes in the fair value of certain U.S. Power derivative contracts.
    Energy's EBIT also included net unrealized gains of $7 million pre-tax
    ($5 million after tax) due to changes in the fair value of proprietary
    natural gas inventory in storage and natural gas forward purchase and
    sale contracts.
--  Second quarter 2010, Energy's EBIT included net unrealized gains of $9
    million pre-tax ($6 million after tax) resulting from changes in the
    fair value of certain U.S. Power derivative contracts. Energy's EBIT
    also included net unrealized gains of $6 million pre-tax ($4 million
    after tax) due to changes in the fair value of proprietary natural gas
    inventory in storage and natural gas forward purchase and sale
    contracts. Net Income decreased $58 million after tax due to losses in
    2010 compared to gains in 2009 for interest rate and foreign exchange
    rate derivatives that did not qualify as hedges for accounting purposes
    and the translation of U.S. dollar-denominated working capital balances.
--  First quarter 2010, Energy's EBIT included net unrealized losses of $28
    million pre-tax ($17 million after tax) resulting from changes in the
    fair value of certain U.S. Power derivative contracts. Energy's EBIT
    also included net unrealized losses of $21 million pre-tax ($15 million
    after tax) due to changes in the fair value of proprietary natural gas
    inventory in storage and natural gas forward purchase and sale
    contracts. 
--  Fourth quarter 2009, Pipelines' EBIT included a dilution gain of $29
    million pre-tax ($18 million after tax) resulting from TransCanada's
    reduced ownership interest in PipeLines LP after PipeLines LP issued
    common units to the public. Energy's EBIT included net unrealized gains
    of $7 million pre-tax ($5 million after tax) due to changes in the fair
    value of proprietary natural gas inventory in storage and natural gas
    forward purchase and sale contracts. Net Income included $30 million of
    favourable income tax adjustments resulting from reductions in the
    Province of Ontario's corporate income tax rates. 
--  Third quarter 2009, Energy's EBIT included net unrealized gains of $14
    million pre-tax ($10 million after tax) due to changes in the fair value
    of proprietary natural gas inventory in storage and natural gas forward
    purchase and sale contracts. 
--  Second quarter 2009, Energy's EBIT included net unrealized losses of $7
    million pre-tax ($5 million after tax) due to changes in the fair value
    of proprietary natural gas inventory in storage and natural gas forward
    purchase and sale contracts. Energy's EBIT also included contributions
    from Portlands Energy, which was placed in service in April 2009, and
    the negative impact of Western Power's lower overall realized power
    prices.
--  First quarter 2009, Energy's EBIT included net unrealized losses of $13
    million pre-tax ($9 million after tax) due to changes in the fair value
    of proprietary natural gas inventory in storage and natural gas forward
    purchase and sale contracts. 
--  Fourth quarter 2008, Energy's EBIT included net unrealized gains of $7
    million pre-tax ($6 million after tax) due to changes in the fair value
    of proprietary natural gas inventory in storage and natural gas forward
    purchase and sale contracts. Net Income included net unrealized losses
    of $57 million pre-tax ($39 million after tax) due to changes in the
    fair value of derivatives used to manage the Company's exposure to
    rising interest rates but which did not qualify as hedges for accounting
    purposes.


Consolidated Income

(unaudited)                          Three months ended   Nine months ended 
(millions of dollars except per            September 30        September 30
 share amounts)                          2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Revenues                                2,129     2,049     6,007     6,195 
                                    ---------- --------- --------- ---------
                                                                            
Operating and Other Expenses                                                
Plant operating costs and other           817       836     2,328     2,443 
Commodity purchases resold                301       205       773       616 
Depreciation and amortization             326       343     1,010     1,034 
                                    ---------- --------- --------- ---------
                                        1,444     1,384     4,111     4,093 
                                    ---------- --------- --------- ---------
                                                                            
Financial Charges/(Income)                                                  
Interest expense                          159       216       528       770 
Interest expense of joint ventures         13        17        44        47 
Interest income and other                 (27)      (43)      (33)      (99)
                                    ---------- --------- --------- ---------
                                          145       190       539       718 
                                    ---------- --------- --------- ---------
                                                                            
Income before Income Taxes and Non-                                         
 Controlling Interests                    540       475     1,357     1,384 
                                    ---------- --------- --------- ---------
                                                                            
Income Taxes                                                                
Current                                   (49)       14      (167)      103 
Future                                    169        93       453       217 
                                    ---------- --------- --------- ---------
                                          120       107       286       320 
                                    ---------- --------- --------- ---------
Non-Controlling Interests                                                   
Non-controlling interest in                                                 
 PipeLines LP                              25        19        64        51 
Preferred share dividends of                                                
 subsidiary                                 6         6        17        17 
Non-controlling interest in Portland       (2)       (2)        1         3 
                                    ---------- --------- --------- ---------
                                           29        23        82        71 
                                    ---------- --------- --------- ---------
Net Income                                391       345       989       993 
Preferred Share Dividends                  14         -        31         - 
                                    ---------- --------- --------- ---------
Net Income Applicable to Common                                             
 Shares                                   377       345       958       993 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            
Net Income Per Share - Basic and                                            
 Diluted                             $   0.54  $   0.50  $   1.39  $   1.55 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            
Average Shares Outstanding - Basic                                          
 (millions)                               692       681       689       641 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
Average Shares Outstanding - Diluted                                        
 (millions)                               693       682       690       642 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------

See accompanying notes to the consolidated financial statements.

Consolidated Cash Flows

                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Cash Generated From Operations                                              
Net income                                391       345       989       993 
Depreciation and amortization             326       343     1,010     1,034 
Future income taxes                       169        93       453       217 
Non-controlling interests                  29        23        82        71 
Employee future benefits funding                                            
 less than/(in excess) of expense           8       (22)      (36)      (79)
Other                                     (62)      (10)       21        (6)
                                    ---------- --------- --------- ---------
                                          861       772     2,519     2,230 
(Increase)/decrease in operating                                            
 working capital                          (70)     (201)     (271)      127 
                                    ---------- --------- --------- ---------
Net cash provided by operations           791       571     2,248     2,357 
                                    ---------- --------- --------- ---------
                                                                            
Investing Activities                                                        
Capital expenditures                   (1,297)   (1,557)   (3,565)   (3,943)
Acquisitions, net of cash acquired          -      (653)        -      (902)
Deferred amounts and other               (221)      (20)     (430)     (294)
                                    ---------- --------- --------- ---------
Net cash used in investing                                                  
 activities                            (1,518)   (2,230)   (3,995)   (5,139)
                                    ---------- --------- --------- ---------
                                                                            
Financing Activities                                                        
Dividends on common and preferred                                           
 shares                                  (184)     (186)     (567)     (535)
Distributions paid to non-                                                  
 controlling interests                    (28)      (25)      (83)      (76)
Notes payable (repaid)/issued, net        (44)       77       (53)     (607)
Long-term debt issued, net of issue                                         
 costs                                  1,021       207     2,337     3,267 
Reduction of long-term debt              (146)       (9)     (429)     (509)
Long-term debt of joint ventures                                            
 issued                                    86        93       164       201 
Reduction of long-term debt of joint                                        
 ventures                                 (93)      (52)     (232)     (108)
Common shares issued, net of issue                                          
 costs                                      6         2        20     1,805 
Preferred shares issued, net of                                             
 issue costs                                -       539       679       539 
                                    ---------- --------- --------- ---------
Net cash provided by financing                                              
 activities                               618       646     1,836     3,977 
                                    ---------- --------- --------- ---------
                                                                            
Effect of Foreign Exchange Rate                                             
 Changes on Cash and Cash                                                   
 Equivalents                               (8)      (63)        8       (97)
                                    ---------- --------- --------- ---------
                                                                            
 (Decrease)/Increase in Cash and                                            
  Cash Equivalents                       (117)   (1,076)       97     1,098 
                                                                            
Cash and Cash Equivalents                                                   
Beginning of period                     1,211     3,482       997     1,308 
                                    ---------- --------- --------- ---------
                                                                            
Cash and Cash Equivalents                                                   
End of period                           1,094     2,406     1,094     2,406 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------
                                                                            
Supplementary Cash Flow Information                                         
Net income taxes (refunded)/paid          (26)      (63)       17        50 
Interest paid, net of capitalized                                           
 interest                                 215       297       573       834 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------

See accompanying notes to the consolidated financial statements. 

Consolidated Balance Sheet

(unaudited)                                     September 30,   December 31,
(millions of dollars)                                   2010           2009 
------------------------------------------------------------- --------------
------------------------------------------------------------- --------------
                                                                            
ASSETS                                                                      
Current Assets                                                              
Cash and cash equivalents                              1,094            997 
Accounts receivable                                    1,123            966 
Inventories                                              452            511 
Other                                                    772            701
                                              --------------- --------------
                                                       3,441          3,175 
Plant, Property and Equipment                         35,555         32,879 
Goodwill                                               3,696          3,763 
Regulatory Assets                                      1,491          1,524 
Intangibles and Other Assets                           2,435          2,500 
                                              --------------- --------------
                                                      46,618         43,841 
                                              --------------- --------------
                                              --------------- --------------
                                                                            
LIABILITIES AND SHAREHOLDERS' EQUITY                                        
Current Liabilities                                                         
Notes payable                                          1,613          1,687 
Accounts payable                                       2,162          2,195 
Accrued interest                                         325            377 
Current portion of long-term debt                        455            478 
Current portion of long-term debt of joint                                  
 ventures                                                 28            212 
                                              --------------- --------------
                                                       4,583          4,949 
Regulatory Liabilities                                   332            385 
Deferred Amounts                                         896            743 
Future Income Taxes                                    3,143          2,856 
Long-Term Debt                                        17,928         16,186 
Long-Term Debt of Joint Ventures                         861            753 
Junior Subordinated Notes                              1,020          1,036 
                                              --------------- --------------
                                                      28,763         26,908 
                                              --------------- --------------
Non-Controlling Interests                                                   
Non-controlling interest in PipeLines LP                 706            705 
Preferred shares of subsidiary                           389            389 
Non-controlling interest in Portland                      81             80 
                                              --------------- --------------
                                                       1,176          1,174 
                                              --------------- --------------
Shareholders' Equity                                  16,679         15,759 
                                              --------------- --------------
                                                      46,618         43,841 
                                              --------------- --------------
                                              --------------- --------------

See accompanying notes to the consolidated financial statements. 


Consolidated Comprehensive Income

(unaudited)                          Three months ended   Nine months ended 
                                           September 30        September 30
(millions of dollars)                    2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Net Income                                391       345       989       993 
                                     --------- --------- --------- ---------
Other Comprehensive (Loss)/Income,                                          
 Net of Income Taxes                                                        
 Change in foreign currency                                                 
  translation gains and losses on                                           
  investments in foreign                                                    
  operations(1)                          (127)     (230)      (47)     (381)
 Change in gains and losses on                                              
  hedges of investments in foreign                                          
  operations(2)                            47       113        27       209 
 Change in gains and losses on                                              
  derivative instruments designated                                         
  as cash flow hedges(3)                  (52)       16      (173)       80 
 Reclassification to Net Income of                                          
  gains and losses on derivative                                            
  instruments designated as cash                                            
  flow hedges pertaining to prior                                           
  periods(4)                                8        (1)        6        (6)
                                     --------- --------- --------- ---------
 Other Comprehensive (Loss)/Income       (124)     (102)     (187)      (98)
                                     --------- --------- --------- ---------
Comprehensive Income                      267       243       802       895 
                                     --------- --------- --------- ---------
                                     --------- --------- --------- ---------

(1) Net of income tax expense of $36 million and $21 million for the three
    and nine months ended September 30, 2010, respectively (2009 - expense
    of $68 million and $68 million, respectively). 
(2) Net of income tax expense of $19 million and $11 million for the three
    and nine months ended September 30, 2010, respectively (2009 - expense
    of $50 million and $102 million, respectively). 
(3) Net of income tax recovery of $33 million and $117 million for the three
    and nine months ended September 30, 2010, respectively (2009 - expense
    of $4 million and $20 million, respectively). 
(4) Net of income tax expense of $4 million and $21 million for the three
    and nine months ended September 30, 2010, respectively (2009 - expense
    of $4 million and $4 million, respectively). 

See accompanying notes to the consolidated financial statements.


Consolidated Accumulated Other Comprehensive (Loss)/Income

                                     Currency                               
(unaudited)                       Translation      Cash Flow                
(millions of dollars)             Adjustments         Hedges          Total 
---------------------------------------------- -------------- --------------
---------------------------------------------- -------------- --------------
                                                                            
Balance at December 31, 2009             (592)           (40)          (632)
Change in foreign currency                                                  
 translation gains and losses                                               
 on investments in foreign                                                  
 operations(1)                            (47)             -            (47)
Change in gains and losses on                                               
 hedges of investments in                                                   
 foreign operations(2)                     27              -             27 
Change in gains and losses on                                               
 derivative instruments                                                     
 designated as cash flow                                                    
 hedges(3)                                  -           (173)          (173)
Reclassification to Net Income                                              
 of gains and losses on                                                     
 derivative instruments                                                     
 designated as cash flow hedges                                             
 pertaining to prior                                                        
 periods(4)(5)                              -              6              6 
                                -------------- -------------- --------------
Balance at September 30, 2010            (612)          (207)          (819)
                                -------------- -------------- --------------
                                -------------- -------------- --------------
                                                                            
                                                                            
---------------------------------------------- -------------- --------------
---------------------------------------------- -------------- --------------
                                                                            
Balance at December 31, 2008             (379)           (93)          (472)
Change in foreign currency                                                  
 translation gains and losses                                               
 on investments in foreign                                                  
 operations(1)                           (381)             -           (381)
Change in gains and losses on                                               
 hedges of investments in                                                   
 foreign operations(2)                    209              -            209 
Changes in gains and losses on                                              
 derivative instruments                                                     
 designated as cash flow                                                    
 hedges(3)                                  -             80             80 
Reclassification to Net Income                                              
 of gains and losses on                                                     
 derivative instruments                                                     
 designated as cash flow hedges                                             
 pertaining to prior periods(4)             -             (6)            (6)
                                -------------- -------------- --------------
Balance at September 30, 2009            (551)           (19)          (570)
                                -------------- -------------- --------------
                                -------------- -------------- --------------

(1) Net of income tax expense of $21 million for the nine months ended
    September 30, 2010 (2009 - $68 million expense). 
(2) Net of income tax expense of $11 million for the nine months ended
    September 30, 2010 (2009 - $102 million expense). 
(3) Net of income tax recovery of $117 million for the nine months ended
    September 30, 2010 (2009 - $20 million expense). 
(4) Net of income tax expense of $21 million for the nine months ended
    September 30, 2010 (2009 - $4 million expense). 
(5) Losses related to cash flow hedges reported in Accumulated Other
    Comprehensive (Loss)/Income and expected to be reclassified to Net
    Income in the next 12 months are estimated to be $95 million ($56
    million, net of tax). These estimates assume constant commodity prices,
    interest rates and foreign exchange rates over time, however, the
    amounts reclassified will vary based on the actual value of these
    factors at the date of settlement. 

See accompanying notes to the consolidated financial statements.


Consolidated Shareholders' Equity

(unaudited)                                             Nine months ended  
                                                           September 30    
(millions of dollars)                                   2010           2009 
------------------------------------------------------------- --------------
------------------------------------------------------------- --------------
                                                                            
Common Shares                                                               
 Balance at beginning of period                       11,338          9,264 
 Shares issued under dividend reinvestment                                  
  plan                                                   271            182 
 Proceeds from shares issued on exercise of                                 
  stock options                                           20             13 
 Proceeds from shares issued under public                                   
  offering, net of issue costs                             -          1,792 
                                               -------------- --------------
 Balance at end of period                             11,629         11,251 
                                               -------------- --------------
                                                                            
Preferred Shares                                                            
 Balance at beginning of period                          539              - 
 Proceeds from shares issued under public                                   
  offering, net of issue costs                           685            539 
                                               -------------- --------------
 Balance at end of period                              1,224            539 
                                               -------------- --------------
                                                                            
Contributed Surplus                                                         
 Balance at beginning of period                          328            279 
 Issuance of stock options                                 2              3 
  Increased ownership in PipeLines LP                      -             49 
                                               -------------- --------------
 Balance at end of period                                330            331 
                                               -------------- --------------
                                                                            
Retained Earnings                                                           
 Balance at beginning of period                        4,186          3,827 
 Net income                                              989            993 
 Common share dividends                                 (829)          (754)
 Preferred share dividends                               (31)             - 
                                               -------------- --------------
 Balance at end of period                              4,315          4,066 
                                               -------------- --------------
                                                                            
Accumulated Other Comprehensive (Loss)/Income                               
 Balance at beginning of period                         (632)          (472)
 Other comprehensive (loss)/income                      (187)           (98)
                                               -------------- --------------
 Balance at end of period                               (819)          (570)
                                               -------------- --------------
                                                       3,496          3,496 
                                               -------------- --------------
                                                                            
Total Shareholders' Equity                            16,679         15,617 
                                               -------------- --------------
                                               -------------- --------------

See accompanying notes to the consolidated financial statements.

Notes to Consolidated Financial Statements

(Unaudited)

1. Significant Accounting Policies

The consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The accounting policies applied are consistent with those outlined in TransCanada's annual audited Consolidated Financial Statements for the year ended December 31, 2009. These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. These Consolidated Financial Statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2009 audited Consolidated Financial Statements included in TransCanada's 2009 Annual Report. Unless otherwise indicated, "TransCanada" or "the Company" includes TransCanada Corporation and its subsidiaries. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the Glossary of Terms contained in TransCanada's Annual Report. Amounts are stated in Canadian dollars unless otherwise indicated. Certain comparative figures have been reclassified to conform with the current year's presentation.

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

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

In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies.

2. Changes in Accounting Policies

The Company's accounting policies have not changed materially from those described in TransCanada's 2009 Annual Report. Future accounting changes that will impact the Company are as follows:

Future Accounting Changes

International Financial Reporting Standards

The Canadian Institute of Chartered Accountants' (CICA) Accounting Standards Board (AcSB) previously announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. As an SEC registrant, TransCanada prepares and files a "Reconciliation to United States GAAP" and also has the option to instead prepare and file its consolidated financial statements using U.S. GAAP. Previously, TransCanada disclosed that effective January 1, 2011, the Company expected to begin reporting under IFRS. Prior to the developments noted below, the Company's IFRS conversion project was proceeding as planned to meet the January 1, 2011 conversion date.

Rate-Regulated Accounting

In accordance with Canadian GAAP, TransCanada currently follows specific accounting policies unique to a rate-regulated business. These rate-regulated accounting (RRA) standards allow the timing of recognition of certain expenses and revenues to differ from that which may otherwise be expected under Canadian GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. These timing differences are recorded as regulatory assets and regulatory liabilities on TransCanada's consolidated balance sheet and represent current rights and obligations regarding cash flows expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities. As at September 30, 2010, TransCanada reported $1.7 billion of regulatory assets and $0.4 billion of regulatory liabilities using RRA in addition to certain other impacts of RRA.

In July 2009, the IASB issued an Exposure Draft "Rate-Regulated Activities" which proposed a form of RRA under IFRS. At its September 2010 meeting, the IASB concluded that the development of RRA under IFRS requires further analysis. The IASB is now considering what form a future project might take, if any, to address RRA. As a result of these developments, TransCanada does not expect a final RRA standard under IFRS to be effective for 2011.

In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises that use RRA in order to permit these entities to defer the adoption of IFRS for one year. Due to the continued uncertainty around the timing, scope and eventual adoption of an RRA standard under IFRS, TransCanada will defer its adoption of IFRS accordingly and continue preparing its consolidated financial statements in 2011 in accordance with Canadian GAAP in order to continue using RRA. During the deferral period, TransCanada will continue to actively monitor IASB developments with respect to RRA and other IFRS, but has also undertaken a project to position the Company to instead adopt U.S. GAAP. During the one year deferral period, if it is determined through absence of a new RRA standard or through application of existing IFRS that TransCanada cannot apply RRA under IFRS, the Company expects to re-evaluate its decision to adopt IFRS and, instead, adopt U.S. GAAP.

As a result of these developments related to RRA under IFRS, TransCanada cannot reasonably quantify the full impact that adopting IFRS would have on its financial position and future results if it proceeded with adopting IFRS. Alternatively, the impact of adopting U.S. GAAP is expected to be consistent with that currently reported in its publicly filed "Reconciliation to United States GAAP".

3. Segmented Information 

Three months ended                                                          
 September 30           Pipelines      Energy(1)   Corporate       Total    
                     -------------- -------------- ---------- --------------
                     -------------- -------------- ---------- --------------
(unaudited)(millions                                                        
 of dollars)           2010   2009    2010   2009  2010 2009    2010   2009 
----------------------------------- -------------- ---------- --------------
----------------------------------- -------------- ---------- --------------
                                                                            
Revenues              1,080  1,152   1,049    897     -    -   2,129  2,049 
Plant operating                                                             
 costs and other       (366)  (422)   (433)  (386)  (18) (28)   (817)  (836)
Commodity purchases                                                         
 resold                   -      -    (301)  (205)    -    -    (301)  (205)
Depreciation and                                                            
 amortization          (232)  (255)    (94)   (88)    -    -    (326)  (343)
                     -------------- -------------- ---------- --------------
                        482    475     221    218   (18) (28)    685    665 
                     -------------- -------------- ----------               
                     -------------- -------------- ----------               
Interest expense                                                (159)  (216)
Interest expense of                                                         
 joint ventures                                                  (13)   (17)
Interest income and                                                         
 other                                                            27     43 
Income taxes                                                    (120)  (107)
Non-controlling                                                             
 interests                                                       (29)   (23)
                                                              --------------
Net Income                                                       391    345 
Preferred share                                                             
 dividends                                                       (14)     - 
                                                              --------------
Net Income Applicable to Common Shares                           377    345 
                                                              --------------
                                                              --------------
                                                                            
                                                                            
Nine months ended                                                           
 September 30           Pipelines      Energy(1)   Corporate       Total    
                     -------------- -------------- ---------- --------------
                     -------------- -------------- ---------- --------------
(unaudited)(millions                                                        
 of dollars)           2010   2009    2010   2009  2010 2009    2010   2009 
----------------------------------- -------------- ---------- --------------
----------------------------------- -------------- ---------- --------------
                                                                            
Revenues              3,270  3,558   2,737  2,637     -    -   6,007  6,195 
Plant operating                                                             
 costs and other     (1,092)(1,210) (1,170)(1,144)  (66) (89) (2,328)(2,443)
Commodity purchases                                                         
 resold                   -      -    (773)  (616)    -    -    (773)  (616)
Depreciation and                                                            
 amortization          (736)  (773)   (274)  (261)    -    -  (1,010)(1,034)
                     -------------- -------------- ---------- --------------
                      1,442  1,575     520    616   (66) (89)  1,896  2,102 
                     -------------- -------------- ----------               
                     -------------- -------------- ----------               
Interest expense                                                (528)  (770)
Interest expense of                                                         
 joint ventures                                                  (44)   (47)
Interest income and                                                         
 other                                                            33     99 
Income taxes                                                    (286)  (320)
Non-controlling                                                             
 interests                                                       (82)   (71)
                                                              --------------
Net Income                                                       989    993 
Preferred share                                                             
 dividends                                                       (31)     - 
                                                              --------------
Net Income Applicable to Common Shares                           958    993 
                                                              --------------
                                                              --------------

(1) Effective January 1, 2010, the Company records in Revenues on a net
    basis, realized and unrealized gains and losses on derivatives used to
    purchase and sell power, natural gas and fuel oil in order to manage
    Energy's assets. Comparative figures for 2009 reflect amounts
    reclassified from Commodity Purchases Resold and Plant Operating Costs
    and Other to Revenues.  


Total Assets

(unaudited)(millions of dollars)                September 30,   December 31,
                                                        2010           2009 
------------------------------------------------------------- --------------
------------------------------------------------------------- --------------
                                                                            
Pipelines                                             31,507         29,508 
Energy                                                13,037         12,477 
Corporate                                              2,074          1,856 
                                              --------------- --------------
                                                      46,618         43,841 
                                              --------------- --------------
                                              --------------- --------------

4. Long-Term Debt

In September 2010, TCPL issued US$1.0 billion of senior notes maturing October 1, 2020 and bearing interest at 3.80 per cent. These notes were issued under the US$4.0 billion debt shelf prospectus filed in December 2009.

In June 2010, TCPL issued senior notes of US$500 million and US$750 million maturing on June 1, 2015 and June 1, 2040, respectively, and bearing interest at 3.40 per cent and 6.10 per cent, respectively. These notes were issued under the US$4.0 billion debt shelf prospectus filed in December 2009.

In the three and nine months ended September 30, 2010, the Company capitalized interest related to capital projects of $160 million and $437 million, respectively (2009 - $113 million and $230 million, respectively).

5. Share Capital

Preferred Share Issuances

In June 2010, TransCanada completed a public offering of 14 million Series 5 cumulative redeemable first preferred shares, including the full exercise of an underwriters' option of two million shares, under its September 2009 base shelf prospectus. The preferred shares were issued at a price of $25 per share, resulting in gross proceeds of $350 million including the underwriters' option. The holders of the Series 5 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.10 per share, payable quarterly, yielding 4.4 per cent per annum for the initial five and a half year period ending January 30, 2016. The dividend rate will reset on January 30, 2016 and every five years thereafter to a yield per annum equal to the sum of the then five year Government of Canada bond yield and 1.54 per cent. The Series 5 preferred shares are redeemable by TransCanada on January 30, 2016 and on January 30 of every fifth year thereafter.

The Series 5 preferred shareholders will have the right to convert their shares into Series 6 cumulative redeemable first preferred shares on January 30, 2016 and on January 30 of every fifth year thereafter. The holders of Series 6 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90 day Government of Canada treasury bill rate and 1.54 per cent.

In March 2010, TransCanada completed a public offering of 14 million Series 3 cumulative redeemable first preferred shares, including the full exercise of an underwriters' option of two million shares, under its September 2009 base shelf prospectus. The preferred shares were issued at a price of $25 per share, resulting in gross proceeds of $350 million including the underwriters' option. The holders of the Series 3 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly, yielding 4.0 per cent per annum for the initial five year period ending June 30, 2015. The dividend rate will reset on June 30, 2015 and every five years thereafter to a yield per annum equal to the sum of the then five year Government of Canada bond yield and 1.28 per cent. The Series 3 preferred shares are redeemable by TransCanada on June 30, 2015 and on June 30 of every fifth year thereafter.

The Series 3 preferred shareholders will have the right to convert their shares into Series 4 cumulative redeemable first preferred shares on June 30, 2015 and on June 30 of every fifth year thereafter. The holders of Series 4 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90 day Government of Canada treasury bill rate and 1.28 per cent.

Dividend Reinvestment and Share Purchase Plan

In the three and nine months ended September 30, 2010, TransCanada issued 2.9 million and 7.8 million (2009 - 2.5 million and 6.0 million) common shares, respectively, under its Dividend Reinvestment and Share Purchase Plan (DRP), in lieu of making cash dividend payments of $101 million and $271 million, respectively (2009 - $73 million and $182 million, respectively). The dividends under the DRP were paid with common shares issued from treasury.

6. Financial Instruments and Risk Management

TransCanada continues to manage and monitor its exposure to counterparty credit, liquidity and market risk.

Counterparty Credit and Liquidity Risk

TransCanada's maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, the fair value of derivative assets and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table below. Letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At September 30, 2010, there were no significant amounts past due or impaired.

At September 30, 2010, the Company had a credit risk concentration of $308 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.

The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions.

Natural Gas Inventory

At September 30, 2010, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $52 million (December 31, 2009 - $73 million). The change in fair value of proprietary natural gas inventory in storage in the three and nine months ended September 30, 2010 resulted in net pre-tax unrealized losses of $1 million and $20 million, respectively (2009 - gains of $16 million and losses of $13 million, respectively), which were recorded as a decrease in Revenues and Inventories. The change in fair value of natural gas forward purchase and sale contracts in the three and nine months ended September 30, 2010 resulted in net pre-tax unrealized gains of $8 million and $12 million, respectively (2009 - losses of $2 million and gains of $7 million, respectively), which were included in Revenues.

VaR Analysis

TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its liquid open positions. VaR represents the potential change in pre-tax earnings over a given holding period. It is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its open positions will not exceed the reported VaR. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada's consolidated VaR was $6 million at September 30, 2010 (December 31, 2009 - $12 million). The decrease from December 31, 2009 was primarily due to decreased commodity prices, reduced price volatility and fewer open positions in the U.S. Power portfolio.

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations (on an after tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At September 30, 2010, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $10.1 billion (US$9.8 billion) and a fair value of $12.1 billion (US$11.8 billion). At September 30, 2010, $91 million (December 31, 2009 - $96 million) was included in Intangibles and Other Assets for the fair value of forwards and swaps used to hedge the Company's net U.S. dollar investment in foreign operations.

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

Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations

                                   September 30, 2010     December 31, 2009 
                                 --------------------- ---------------------
                                 --------------------- ---------------------
                                             Notional              Notional 
Asset/(Liability)                                  or                    or 
(unaudited)                          Fair   Principal      Fair   Principal 
(millions of dollars)             Value(1)     Amount   Value(1)     Amount 
------------------------------------------ ----------- --------- -----------
------------------------------------------ ----------- --------- -----------
                                                                            
U.S. dollar cross-currency swaps                                            
 (maturing 2010 to 2015)               87  U.S. 2,150        86  U.S. 1,850 
U.S. dollar forward foreign                                                 
 exchange contracts                                                         
 (maturing 2010)                        4    U.S. 400         9    U.S. 765 
U.S. dollar foreign exchange                                                
 options (matured 2010)                 -           -         1    U.S. 100 
                                                                            
                                 --------- ----------- --------- -----------
                                                                    
                                       91  U.S. 2,550        96  U.S. 2,715 
                                 --------- ----------- --------- -----------
                                 --------- ----------- --------- -----------

(1) Fair values equal carrying values. 


Non-Derivative Financial Instruments Summary

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

                                     September 30, 2010   December 31, 2009 
                                     ------------------- -------------------
                                     ------------------- -------------------
(unaudited)                          Carrying      Fair  Carrying      Fair 
(millions of dollars)                  Amount     Value    Amount     Value 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Financial Assets(1)                                                         
Cash and cash equivalents               1,094     1,094       997       997 
Accounts receivable and other(2)(3)     1,557     1,615     1,432     1,483 
Available-for-sale assets(2)               23        23        23        23 
                                     --------- --------- --------- ---------
                                        2,674     2,732     2,452     2,503 
                                     --------- --------- --------- ---------
                                     --------- --------- --------- ---------
                                                                            
Financial Liabilities(1)(3)                                                 
Notes payable                           1,613     1,613     1,687     1,687 
Accounts payable and deferred                                               
 amounts(4)                             1,298     1,298     1,538     1,538 
Accrued interest                          325       325       377       377 
Long-term debt                         18,383    22,710    16,664    19,377 
Junior subordinated notes               1,020       968     1,036       976 
Long-term debt of joint ventures          889     1,021       965     1,025 
                                     --------- --------- --------- ---------
                                       23,528    27,935    22,267    24,980 
                                     --------- --------- --------- ---------
                                     --------- --------- --------- ---------

(1) Consolidated Net Income in 2010 included gains of $11 million (2009 - $9
    million) for fair value adjustments related to interest rate swap
    agreements on US$150 million (2009 - US$300 million) of long-term debt.
    There were no other unrealized gains or losses from fair value
    adjustments to the financial instruments.
(2) At September 30, 2010, the Consolidated Balance Sheet included financial
    assets of $1,123 million (December 31, 2009 - $966 million) in Accounts
    Receivable, $41 million (December 31, 2009 - nil) in Other Current
    Assets and $416 million (December 31, 2009 - $489 million) in
    Intangibles and Other Assets.
(3) Recorded at amortized cost, except for certain long-term debt which is
    recorded at fair value. 
(4) At September 30, 2010, the Consolidated Balance Sheet included financial
    liabilities of $1,261 million (December 31, 2009 - $1,513 million) in
    Accounts Payable and $37 million (December 31, 2009 - $25 million) in
    Deferred Amounts.


Derivative Financial Instruments Summary

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

September 30, 2010                                                          
(unaudited) (all amounts                                                    
 in millions unless                       Natural       Foreign             
 otherwise indicated)           Power         Gas      Exchange    Interest 
-------------------------------------- ----------- ------------- -----------
-------------------------------------- ----------- ------------- -----------
                                                                            
Derivative Financial                                                        
 Instruments Held for                                                       
 Trading(1)                                                                 
Fair Values(2)                                                              
 Assets                    $      238  $      176             -  $       27 
 Liabilities               $     (189) $     (179) $         (9) $      (38)
Notional Values                                                             
 Volumes(3)                                                                 
  Purchases                    15,466         114             -           - 
  Sales                        17,965          96             -           - 
 Canadian dollars                   -           -             -         759 
 U.S. dollars                       -           -    U.S. 1,189    U.S. 350 
 Cross-currency                     -           -    47/U.S. 37           - 
                                                                            
Net unrealized                                                              
 (losses)/gains in the                                                      
 period(4)                 $       (1) $        4  $         10  $       50 
 Three months ended                                                         
  September 30, 2010                                                        
 Nine months ended                                                          
  September 30, 2010       $      (27) $        9  $         (1) $       33 
                                                                            
Net realized                                                                
 gains/(losses) in the                                                      
 period(4)                                                                  
 Three months ended                                                         
  September 30, 2010       $       13  $      (10) $          6  $      (54)
 Nine months ended                                                          
  September 30, 2010       $       50  $      (39) $          8  $      (64)
                                                                            
Maturity dates              2010-2015   2010-2015     2010-2012   2010-2016 
                                                                            
Derivative Financial                                                        
 Instruments in Hedging                                                     
 Relationships(5)(6)                                                        
Fair Values(2)                                                              
 Assets                    $      163           -             -  $       11 
 Liabilities               $     (256) $      (85) $        (44) $      (36)
Notional Values                                                             
 Volumes(3)                                                                 
  Purchases                    15,563          60             -           - 
  Sales                        12,655           -             -           - 
 U.S. dollars                       -           -      U.S. 120  U.S. 1,025 
 Cross-currency                     -           -  136/U.S. 100           - 
                                                                            
Net realized                                                                
 gains/(losses) in the                                                      
 period(4)                                                                  
 Three months ended                                                         
  September 30, 2010       $       37  $      (19)            -  $       (7)
 Nine months ended                                                          
  September 30, 2010       $       (6) $      (28)            -  $      (26)
                                                                            
Maturity dates              2010-2015   2010-2013    2010- 2014   2011-2013 
                           ----------- ----------- ------------- -----------
                           ----------- ----------- ------------- -----------

(1) All derivative financial instruments in the held-for-trading
    classification have been entered into for risk management purposes and
    are subject to the Company's risk management strategies, policies and
    limits. These include derivatives that have not been designated as
    hedges or do not qualify for hedge accounting treatment but have been
    entered into as economic hedges to manage the Company's exposures to
    market risk.
(2) Fair values equal carrying values. 
(3) Volumes for power and natural gas derivatives are in gigawatt hours
    (GWh) and billion cubic feet (Bcf), respectively.
(4) Realized and unrealized gains and losses on power and natural gas
    derivative financial instruments held for trading are included 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 unrealized gains and losses on
    derivative financial instruments in hedging relationships are initially
    recognized in Other Comprehensive Income and are 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 $11 million and a notional amount of US$150
    million. Net realized gains on fair value hedges for the three and nine
    months ended September 30, 2010 were $1 million and $3 million,
    respectively, and were included in Interest Expense. In third quarter
    2010, the Company did not record any amounts in Net Income related to
    ineffectiveness for fair value hedges.
(6) Losses included in Net Income for the three and nine months ended
    September 30, 2010 were nil and $1 million, respectively, for changes in
    the fair value of power and natural gas cash flow hedges that were
    ineffective in offsetting the change in fair value of their related
    underlying positions. There were no gains or losses included in Net
    Income for the three and nine months ended September 30, 2010 for
    discontinued cash flow hedges. No amounts have been excluded from the
    assessment of hedge effectiveness. 

2009                                                                        
(unaudited) (all                                                            
 amounts in                                                                 
 millions unless                                                            
 otherwise                       Natural       Oil       Foreign            
 indicated)            Power         Gas  Products      Exchange   Interest 
----------------------------- ----------  -------- ------------- -----------
----------------------------- ----------  -------- ------------- -----------
                                                                            
Derivative                                                                  
 Financial                                                                  
 Instruments Held                                                           
 for Trading                                                                
Fair Values(1)(2)                                                           
 Assets            $     150  $     107   $     5             -  $       25 
 Liabilities       $     (98) $    (112)  $    (5) $        (66) $      (68)
Notional Values(2)                                                          
Volumes(3)                                                                  
 Purchases            15,275        238       180             -           - 
 Sales                13,185        194       180             -           - 
Canadian dollars           -          -         -             -         574 
U.S. dollars               -          -         -      U.S. 444  U.S. 1,325 
Cross-currency             -          -         -  227/U.S. 157           - 
                                                                            
Net unrealized                                                              
 (losses)/gains in                                                          
 the period(4)                                                              
Three months ended                                                          
 September 30,                                                              
 2009              $      (8) $      21   $    (1) $          2  $       (7)
Nine months ended                                                           
 September 30,                                                              
 2009              $      11  $      (4)  $     1  $          4  $       20 
                                                                            
Net realized                                                                
 gains/(losses) in                                                          
 the period(4)                                                              
Three months ended                                                          
 September 30,                                                              
 2009              $      23  $     (43)  $     1  $         11  $       (5)
Nine months ended                                                           
 September 30,                                                              
 2009              $      53  $     (56)        -  $         28  $      (14)
                                                                            
Maturity dates(2)  2010-2015  2010-2014      2010     2010-2012   2010-2018 
                                                                            
Derivative                                                                  
 Financial                                                                  
 Instruments in                                                             
 Hedging                                                                    
 Relationships(5)(6)                                                        
Fair Values(1)(2)                                                           
 Assets            $     175  $       2         -             -  $       15 
 Liabilities       $    (148) $     (22)        -  $        (43) $      (50)
Notional Values(2)                                                          
Volumes(3)                                                                  
 Purchases            13,641         33         -             -           - 
 Sales                14,311          -         -             -           - 
U.S. dollars               -          -         -      U.S. 120  U.S. 1,825 
Cross-currency             -          -         -  136/U.S. 100           - 
                                                                            
Net realized                                                                
 gains/(losses) in                                                          
 the period(4)                                                              
Three months ended                                                          
 September 30,                                                              
 2009              $      30  $      (8)        -             -  $      (10)
Nine months ended                                                           
 September 30,                                                              
 2009              $     108  $     (28)        -             -  $      (27)
                                                                            
Maturity dates(2)  2010-2015  2010-2014       n/a     2010-2014   2010-2020 
                   ---------- ---------- --------- ------------- -----------
                   ---------- ---------- --------- ------------- -----------
                                                                            

(1) Fair values equal carrying values. 
(2) As at December 31, 2009. 
(3) Volumes for power, natural gas and oil products derivatives are in GWh,
    Bcf and thousands of barrels, respectively. 
(4) Realized and unrealized gains and losses on power, natural gas and oil
    products derivative financial instruments held for trading are included
    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 unrealized gains and losses on
    derivative financial instruments in hedging relationships are initially
    recognized in Other Comprehensive Income and are 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 $4 million and a notional amount of US$150
    million at December 31, 2009. Net realized gains on fair value hedges
    for the three and nine months ended September 30, 2009 were $1 million
    and $3 million, respectively, and were included in Interest Expense. In
    third quarter 2009, the Company did not record any amounts in Net Income
    related to ineffectiveness for fair value hedges. 
(6) Net Income for the three and nine months ended September 30, 2009
    included gains of $1 million and $2 million, respectively, for changes
    in the fair value of power and natural gas cash flow hedges that were
    ineffective in offsetting the change in fair value of their related
    underlying positions. There were no gains or losses included in Net
    Income for the three and nine months ended September 30, 2009 for
    discontinued cash flow hedges. No amounts have been excluded from the
    assessment of hedge effectiveness. 


Balance Sheet Presentation of Derivative Financial Instruments

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

(unaudited)                                                                 
(millions of dollars)                           September 30,   December 31,
                                                        2010           2009 
------------------------------------------------------------- --------------
------------------------------------------------------------- --------------
                                                                            
Current                                                                     
 Other current assets                                    357            315 
 Accounts payable                                       (442)          (340)
                                                                            
Long-term                                                                   
 Intangibles and other assets                            349            260 
 Deferred amounts                                       (394)          (272)
                                              --------------- --------------
                                              --------------- --------------

Fair Value Hierarchy

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

Financial assets and liabilities measured at fair value as of September 30, 2010, including both current and non-current portions, are categorized as follows. There were no transfers between Level I and Level II in third quarter 2010.

                                       Significant                          
                      Quoted Prices          Other   Significant            
                          in Active     Observable  Unobservable            
(unaudited) (millions       Markets         Inputs        Inputs           
 of dollars, pre-tax)      (Level I)     (Level II)   (Level III)     Total 
------------------------------------ -------------- ------------- ----------
------------------------------------ -------------- ------------- ----------
                                                                            
Natural Gas Inventory             -             52             -         52 
Derivative Financial                                                        
 Instruments:                                                               
 Assets                         122            553            25        700 
 Liabilities                   (235)          (582)          (13)      (830)
Available-for-sale                                                          
 assets                          23              -             -         23 
Guarantee                                                                   
 Liabilities(1)                   -              -           (16)       (16)
                      -------------- -------------- ------------- ----------
                                (90)            23            (4)       (71)
                      -------------- -------------- ------------- ----------
                      -------------- -------------- ------------- ----------

(1) The fair value of guarantees is included in Deferred Amounts. 


The following table presents the net change in financial assets and
liabilities measured at fair value and included in the Level III fair value
category:

(unaudited)                                                                 
(millions of dollars, pre-                                                  
 tax)                           Derivatives(1)  Guarantees(2)         Total 
---------------------------------------------- -------------- --------------
---------------------------------------------- -------------- --------------
                                                                            
Balance at December 31, 2009               (2)            (9)           (11)
New contracts(3)                          (15)            (7)           (22)
Settlements                                (3)             -             (3)
Transfers out of Level III(4)             (20)             -            (20)
Change in unrealized gains                                                  
 recorded in Net Income                    14              -             14 
Change in unrealized gains                                                  
 recorded in Other                                                          
 Comprehensive Income                      38              -             38 
                             ----------------- -------------- --------------
Balance at September 30, 2010              12            (16)            (4)
                             ----------------- -------------- --------------
                             ----------------- -------------- --------------

(1) The fair value of derivative assets and liabilities is presented on a
    net basis. 
(2) The fair value of guarantees is included in Deferred Amounts. No amounts
    were recognized in Net Income for the periods presented. 
(3) The total amount of net losses included in Net Income attributable to
    derivatives that were entered into during the period and still held at
    the reporting date was $1 million and $1 million for the three and nine
    months ended September 30, 2010, respectively. 
(4) As contracts near maturity, they are transferred out of Level III and
    into Level II. 

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $20 million decrease or increase, respectively, in the fair value of derivative financial instruments included in Level III and outstanding as at September 30, 2010.

A 100 basis points increase or decrease in the letter of credit rate, with all other variables held constant, would result in an $8 million increase or decrease, respectively, in the fair value of guarantee liabilities outstanding as at September 30, 2010. Similarly, a 100 basis points increase or decrease in the risk-free interest rate, which is a component of the discount rate, would result in a $2 million decrease or increase, respectively, in the fair value of guarantee liabilities outstanding as at September 30, 2010.

7. Employee Future Benefits

The net benefit plan expense for the Company's defined benefit pension plans and other post-employment benefit plans is as follows:

                                       Pension Benefit      Other Benefit   
                                            Plans                Plans     
                                    -------------------  ------------------ 
Three months ended September 30     -------------------  ------------------ 
(unaudited)(millions of dollars)         2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Current service cost                       12        11         -         - 
Interest cost                              22        22         2         2 
Expected return on plan assets            (27)      (24)        -         - 
Amortization of net actuarial loss          2         2         -         1 
Amortization of past service costs          1         1         -         - 
                                    ---------- --------- --------- ---------
Net benefit cost recognized                10        12         2         3 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------


                                      Pension Benefit       Other Benefit   
                                            Plans               Plans       
                                    -------------------  ------------------ 
Nine months ended September 30      -------------------  ------------------ 
(unaudited)(millions of dollars)         2010      2009      2010      2009 
---------------------------------------------- --------- --------- ---------
---------------------------------------------- --------- --------- ---------
                                                                            
Current service cost                       37        34         1         1 
Interest cost                              67        67         6         6 
Expected return on plan assets            (81)      (75)       (1)       (1)
Amortization of transitional                                                
 obligation related to regulated                                            
 business                                   -         -         1         1 
Amortization of net actuarial loss          6         4         1         2 
Amortization of past service costs          3         3         -         - 
                                    ---------- --------- --------- ---------
Net benefit cost recognized                32        33         8         9 
                                    ---------- --------- --------- ---------
                                    ---------- --------- --------- ---------

8. Commitments and Contingencies

At September 30, 2010, TransCanada had entered into agreements since December 31, 2009 totalling approximately $395 million to purchase construction materials and services for the Cartier Wind power and Bison natural gas pipeline projects. TransCanada is currently assessing the impact on its commitments resulting from the Government of Ontario's announcement of the cancellation of the Oakville power project.

Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. No amounts recorded in revenues in the first nine months of 2010 are expected to be repaid.

----------------------------------------------------------------------------
TransCanada welcomes questions from shareholders and potential investors.
Please telephone:
 
Investor Relations, at (800) 361-6522 (Canada and U.S. Mainland) or direct
dial David Moneta/Terry Hook at (403) 920-7911. The investor fax line is 
(403) 920-2457. Media Relations: Terry Cunha/Cecily Dobson (403) 920-7859
or (800) 608-7859. 

Visit the TransCanada website at: http://www.transcanada.com.

----------------------------------------------------------------------------

TransCanada
Media Inquiries
Terry Cunha/Cecily Dobson
(403) 920-7859 or (800) 608-7859
or
Investor & Analyst Inquiries
David Moneta/Terry Hook
(403) 920-7911
(800) 361-6522 (Canada and U.S. Mainland)
www.transcanada.com