TransCanada Reports Third Quarter Results

TransCanada Reports Third Quarter Results 
Bruce Power Unit 1 Enters Commercial Service, Unit 2 to Follow 
CALGARY, ALBERTA -- (Marketwire) -- 10/30/12 -- TransCanada
Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today
announced comparable earnings for third quarter 2012 of $349 million
or $0.50 per share. Net income attributable to common shares for
third quarter 2012 was $369 million or $0.52 per share. TransCanada's
Board of Directors also declared a quarterly dividend of $0.44 per
common share for the quarter ending December 31, 2012, equivalent to
$1.76 per common share on an annualized basis. 
"TransCanada's diverse, high-quality energy infrastructure assets
performed well in the third quarter," said Russ Girling,
TransCanada's president and chief executive officer. "While the
majority of our assets continued to generate stable and predictable
earnings and cash flow, plant outages at Bruce Power and Sundance A
along with a lower contribution from certain natural gas pipelines
did adversely affect our financial results. Looking forward,
TransCanada is well positioned to grow earnings, cash flow and
dividends as we complete our current capital program, benefit from a
recovery in natural gas and power prices and secure attractive new
growth opportunities." 
Over the next three years, TransCanada expects to complete $13
billion of projects that are currently in advanced stages of
development. They include the Bruce Power Unit 1 and 2 Restart
Project, the Gulf Coast Project, Keystone XL, the Tamazunchale
extension, Canadian Solar and the ongoing expansion of the Alberta
System. 
Since the beginning of 2012, TransCanada has also commercially
secured an additional $7 billion of long-life, contracted energy
infrastructure opportunities that are expected to be placed into
service in 2016 and beyond. They include the Coastal GasLink Pipeline
Project that would move natural gas to Canada's West Coast for
liquefaction and shipment to Asian markets, the Northern Courier and
Grand Rapids Oil Pipeline Projects in Northern Alberta and the 900
megawatt Napanee Generating Station in Eastern Ontario. TransCanada
expects each of these projects to generate significant, sustained
earnings and cash flow and deliver superior returns to its
shareholders. 
Highlights 
(Al
l financial figures are unaudited and in Canadian dollars unless
noted otherwise) 


 
--  Third quarter financial results 
    --  Comparable earnings of $349 million or $0.50 per share 
    --  Net income attributable to common shares of $369 million or $0.52
        per share 
    --  Comparable earnings before interest, taxes, depreciation and
        amortization (EBITDA) of $1.1 billion 
    --  Funds generated from operations of $866 million 
--  Declared a quarterly dividend of $0.44 per common share for the quarter
    ending December 31 
--  Bruce Power completed the refurbishment of Units 1 and 2 and placed
    Unit 1 into commercial service on October 22. Unit 2 is expected to
    commence commercial operations shortly. TransCanada's share of the net
    capital cost is approximately $2.4 billion. 
--  Signed a memorandum of understanding with the Ontario Power Authority
    (OPA) to develop a new 900 megawatt (MW) natural gas-fired power plant
    in Eastern Ontario 
--  Continued to advance several growth initiatives in the Oil Pipelines
    business 
    --  Commenced construction on the US$2.3 billion Gulf Coast Project that
        will transport crude oil from Cushing, Oklahoma to the U.S. Gulf
        Coast 
    --  Submitted an alternative route in Nebraska for the US$5.3 billion
        Keystone XL Project 
    --  Selected to develop the proposed $660 million Northern Courier
        Pipeline in Northern Alberta 
    --  Entered into binding agreements to jointly develop the proposed $3
        billion Grand Rapids Pipeline project that includes both a bitumen
        and a diluent line 

 
Comparable earnings for third quarter 2012 were $349 million or $0.50
per share compared to $416 million or $0.59 per share for the same
period in 2011. Higher earnings from Keystone and recently
commissioned assets were more than offset by lower contributions from
Bruce Power, Western Power and certain natural gas pipelines
including the Canadian Mainline, ANR and Great Lakes. 
Net income attributable to common shares for third quarter 2012 was
$369 million or $0.52 per share compared to $386 million or $0.55 per
share in third quarter 2011. 
Notable recent developments in Oil Pipelines, Natural Gas Pipelines,
Energy and Corporate include:  
Oil Pipelines: 


 
--  Gulf Coast Project: In August 2012, TransCanada started construction on
    the US$2.3 billion Gulf Coast Project. The 36-inch pipeline, which will
    extend from Cushing, Oklahoma to the U.S. Gulf Coast, is expected to
    have an initial capacity of up to 700,000 barrels per day (bbl/d) with
    an ultimate capacity of 830,000 bbl/d. Included in the US$2.3 billion
    cost is US$300 million for the 76 kilometre (km) (47-mile) Houston
    Lateral pipeline that will transport crude oil to Houston area
    refineries. TransCanada expects the Gulf Coast Project to be in service
    in late 2013. As of September 30, 2012, approximately US$900 million has
    been invested in the project. 
 
--  Keystone XL: In May 2012, TransCanada filed a Presidential Permit
    application (cross border permit) with the U.S. Department of State
    (DOS) for the Keystone XL Pipeline which will extend from the
    U.S./Canada border in Montana to Steele City, Nebraska. TransCanada will
    supplement the application with an alternative route in Nebraska as soon
    as that route is selected. 
 
    The Company continues to work collaboratively with the Nebraska
    Department of Environmental Quality (NDEQ) to finalize an alternative
    route that avoids the Nebraska Sandhills. In September 2012, the Company
    submitted a Supplemental Environmental Report to the NDEQ for the
    preferred alternative route. The NDEQ has indicated that it will
    complete its review by the end of 2012. TransCanada has also provided an
    environmental report to the DOS which is required as part of the DOS
    review of the Company's Presidential Permit application.
 
    Subject to regulatory approvals, TransCanada expects the Keystone XL
    Pipeline to be in service in late 2014 or early 2015. The approximate
    cost of the 36-inch, 830,000 bbl/d line is US$5.3 billion. As of
    September 30, 2012, US$1.6 billion has been invested in this project. 
 
--  Northern Courier Pipeline: In August 2012, TransCanada announced that it
    had been selected by Fort Hills Energy Limited Partnership (Fort Hills)
    to design, build, own and operate the proposed Northern Courier Pipeline
    project. The project, with an estimated capital cost of $660 million, is
    a 90 km (54-mile) pipeline system that will transport bitumen and
    diluent between the Fort Hills mine site and the Voyageur Upgrader
    located north of Fort McMurray, Alberta. The pipeline is fully
    subscribed under long-term contract to service the Fort Hills mine,
    which is jointly owned by Suncor Energy Inc., Total E&P Canada Ltd. and
    Teck Resources Limited. Northern Courier is conditional on and subject
    to the Fort Hills project receiving sanction by its co-owners and
    obtaining regulatory approval. TransCanada expects to file its initial
    regulatory application in early 2013. 
 
--  Grand Rapids: In October, TransCanada announced that it has entere
d
    into binding agreements with Phoenix Energy Holdings Limited (Phoenix)
    to develop the Grand Rapids Pipeline Project in Northern Alberta.
    TransCanada and Phoenix will each own 50 per cent of the proposed $3
    billion pipeline project that includes both a crude oil and a diluent
    line to transport volumes approximately 500 km (300-miles) between the
    producing area northwest of Fort McMurray and the Edmonton / Heartland
    region. The Grand Rapids Pipeline system is expected to be in service by
    early 2017, subject to regulatory approvals, and will have the capacity
    to move up to 900,000 bbl/d of crude oil and 330,000 bbl/d of diluent.
    TransCanada will operate the system and Phoenix has entered a long-term
    commitment to ship crude oil and diluent on the system. 
 
--  Canadian Mainline Conversion: TransCanada has determined a conversion of
    a portion of the Canadian Mainline natural gas pipeline system to crude
    oil service is both technically and economically feasible. Through a
    combination of converted natural gas pipeline and new construction, the
    proposed pipeline would deliver crude oil between Hardisty, Alberta and
    markets in Eastern Canada. The Company has begun soliciting input from
    stakeholders and prospective shippers to determine market acceptance of
    the proposed project. 

 
Natural Gas Pipelines: 


 
--  Alberta System:  During the first nine months of 2012, TransCanada
    continued to expand its Alberta System by completing and placing in
    service twelve separate pipeline projects at a total cost of
    approximately $680 million. This included the completion of the
    approximate $250 million Horn River project in May 2012 that extended
    the Alberta System into the Horn River shale play in British Columbia.
 
    The National Energy Board (NEB) has approved additional pipeline
    expansions with aggregate costs of approximately $630 million, including
    the $162 million Leismer-Kettle River Crossover project, which is
    intended to provide increased capacity to meet demand in northeast
    Alberta. Approximately $340 million of projects are still awaiting NEB
    approval, including the Komie North project which would extend the
    Alberta System further into the Horn River area. 
 
--  Canadian Mainline:  In 2011, TransCanada filed a comprehensive
    application with the NEB to change the business structure and the terms
    and conditions of service for the Canadian Mainline, and to set tolls
    for 2012 and 2013. The hearing, with respect to this application, began
    on June 4, 2012 with final arguments to be heard from TransCanada and
    the intervenors beginning November 13, 2012. A final decision from the
    NEB is not expected before late first quarter 2013.
 
    In May 2012, TransCanada received NEB approval to construct new pipeline
    infrastructure to provide southern Ontario with additional natural gas
    supply from the Marcellus shale basin. Construction continues on the new
    pipeline facilities and it is expected that the Marcellus shale supply
    will begin moving to market on November 1, 2012. 
 
--  Coastal GasLink: TransCanada announced in second quarter it was selected
    by Shell Canada Limited (Shell) and its partners to design, build, own
    and operate the proposed Coastal GasLink Pipeline Project, an estimated
    $4 billion pipeline that will transport natural gas from the Montney
    gas-producing region near Dawson Creek, British Columbia (B.C.) to the
    recently announced LNG Canada liquefied natural gas export facility
    near Kitimat, B.C. The LNG Canada project is a joint venture led by
    Shell, with partners Korea Gas Corporation, Mitsubishi Corporation and
    PetroChina Company Limited. The approximate 700 km (420-mile)
    pipeline is expected to have an initial capacity of more than 1.7
    billion cubic feet per day and be placed in service toward the end of
    the decade. A proposed contractual extension of the Alberta System
    using capacity on the Coastal GasLink pipeline, to a point near
    Vanderhoof, B.C., will allow TransCanada to also offer gas transmission
    service to interconnecting natural gas pipelines serving the West
    Coast. TransCanada expects to elicit interest in and commitments for
    such service through an open season process in early 2013 subject to
    the overall project schedule. 

 
Energy: 


 
--  Bruce Power: In October 2012, Bruce Power completed the refurbishment
    of Unit 1 and returned this unit to service on October 22, 2012.  Bruce
    Power also synchronized Unit 2 to Ontario's electrical grid on October
    16, 2012 and commercial operations for this unit are expected to
    commence shortly. Units 1 and 2 are expected to produce clean and
    reliable power for the province of Ontario until at least 2037.
    Following the return to service of both Units 1 and 2, Bruce Power will
    be capable of producing 6,200 MW of emission-free power.
 
    TransCanada's share of the total net capital cost for the refurbishment
    project is approximately $2.4 billion.
 
    In August 2012, Bruce Power continued to invest in its strategy to
    maximize the lives of its reactors by commencing an expanded outage
    investment program on Unit 4. The outage, expected to conclude in late
    fourth quarter 2012, will extend the operating life of Unit 4 to at
    least 2021, and align it with Unit 3. In June 2012, Bruce Power returned
    Unit 3 to service after completing the seven month West Shift Plus life
    extension outage. 
 
--  Ravenswood: In 2011, TransCanada and other parties jointly filed two
    formal complaints with the Federal Energy Regulatory Commission (FERC)
    regarding the manner in which the New York Independent System Operator
    (NYISO) has applied pricing rules for two new power plants that have
    recently begun service in the New York Zone J market. In June 2012, the
    FERC addressed the first complaint and indicated it will take steps to
    increase transparency and accountability with regard to future
    Mitigation Exemption Test (MET) decisions which determine whether a new
    facility is exempt from offering its capacity at a floor price.
 
    In September 2012, the FERC granted an order on the second complaint.
    The FERC directed the NYISO to retest the two new facilities, making
    changes to several parameters that form the basis of the MET
    calculations. Based on the changes the FERC has ordered, the
    recalculation could result in one or both entrants having to offer
    their capacity at a floor price which TransCanada anticipates will
    result in higher capacity auction prices in the future. The order is
    prospective and will not impact capacity prices for prior periods. 
 
--  Sundance A: In July 2012, a decision was received relating to the
    binding arbitration hearing to address the Sundance A Power Purchase
    Arrangement (PPA) force majeure and economic destruction claims. The
    arbitration panel determined the PPA should not be terminated and
    ordered TransAlta Corporation (TransAlta) to rebuild Units 1 and 2. The
    panel also limited TransAlta's force majeure claim from November 20,
    2011 until such time the units can reasonably be returned to service.
    According to the terms of the arbitration decision, TransAlta has an
    obligation under the PPA to exercise all reasonable efforts to mitigate
    or limit the effects of the force majeure. TransAlta announced that it
    expects the units to be returned to service in the fall of 2013. Until
    TransAlta returns the Sundance A units to service, TransCanada will not
    realize the generation or related revenues it would otherwise be
    entitled to under the PPA but will be relieved of the associated
    capacity payments. 
 
 
--  Napanee Generating Station:  In September 2012, TransCanada, the
    Government of Ontario, the OPA and Ontario Power Generation announced
    that two Memorandums of Understanding (MOU) were executed authorizing
    TransCanada to develop, construct, own and operate a new 900 MW facility
    at Ontario Power Generation's Lennox site in Eastern Ontario in the town
    of Greater Napanee. The Napanee Generating Station would act as a
    replacement facility for one that was planned and subsequently can
celled
    in the community of Oakville. Under the terms of the MOUs, TransCanada
    will be reimbursed for approximately $250 million of verifiable costs,
    primarily for natural gas turbines at Oakville which will be deployed
    at Napanee. The Company will further invest approximately $1.0 billion
    in the replacement Napanee facility. Definitive contracts are expected
    to be executed by mid-December and include a 20-year Clean Energy Supply
    contract.
 
 
--  Cartier Wind:  The 111 MW second phase of Gros-Morne is expected to be
    operational in November 2012. This will complete construction of the 590
    MW Cartier Wind project in Quebec. All of the power produced by Cartier
    Wind is sold under 20-year PPAs to Hydro-Quebec. 

 
Corporate: 


 
--  The Board of Directors of TransCanada declared a quarterly dividend of
    $0.44 per share for the quarter ending December 31, 2012 on
    TransCanada's outstanding common shares. The quarterly amount is
    equivalent to $1.76 per common share on an annual basis. 
 
--  In August 2012, TransCanada issued US$1.0 billion of senior notes
    maturing on August 1, 2022 and bearing interest at an annual rate of 2.5
    per cent. The net proceeds of the offering were used for general
    corporate purposes and to reduce short-term indebtedness. 
 
--  As previously disclosed, TransCanada adopted U.S. generally accepted
    accounting principles (U.S. GAAP) effective January 1, 2012.
    Accordingly, the 2012 financial information, along with comparative
    financial information for 2011, has been prepared in accordance with
    U.S. GAAP. 

 
Teleconference - Audio and Slide Presentation: 
TransCanada will hold a teleconference and webcast on Tuesday,
October 30, 2012 to discuss its third quarter 2012 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 at
9:00 a.m. (MDT) / 11:00 a.m. (EDT). 
Analysts, members of the media and other interested parties are
invited to participate by calling 866.226.1793 or 416.340.2218
(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 6, 2012. Please
call 905.694.9451 or 800.408.3053 (North America only) and enter pass
code 8130635. 
The unaudited interim Consolidated Financial Statements and
Management's Discussion and Analysis (MD&A) are available on SEDAR at
www.sedar.com, with the U.S. Securities and Exchange Commission on
EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website
at www.transcanada.com. 
With more than 60 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 operates a network
of natural gas pipelines that extends more than 68,500 kilometres
(42,500 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 10,900
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/ or check us out on Twitter @TransCanada. 
Forward Looking Information   
This news release contains certain information that is
forward-looking and is subject to important risks and uncertainties
(such statements are usually accompanied by words such as
"anticipate", "expect", "would", "believe", "may", "will", "plan",
"intend" or other similar words). 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.
All forward-looking statements reflect TransCanada's beliefs and
assumptions based on information available at the time the statements
were made and as such are not guarantees of future performance.
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 news release, and not to use future-oriented
information or financial outlooks for anything other than their
intended purpose. TransCanada undertakes no obligation to update or
revise any forward-looking information except as required by law. For
additional information on the assumptions made, and the risks and
uncertainties which could cause actual results to differ from the
anticipated results, refer to TransCanada's MD&A filed February 15,
2012 under TransCanada's profile on SEDAR at www.sedar.com and other
reports filed by TransCanada with Canadian securities regulators and
with the U.S. Securities and Exchange Commission. 
Non-GAAP Measures  
This news release contains references to non-GAAP measures that do
not have any standardized meaning as prescribed by U.S. GAAP and may
therefore not be comparable to similar measures used by other
companies. These non-GAAP measures are calculated on a consistent
basis from period to period and are adjusted for specific items in
each period, as applicable. For more information on non-GAAP
measures, refer to TransCanada's Quarterly Report to Shareholders
dated October 29, 2012.  


 
                   Third Quarter 2012 Financial Highlights                  
 
Operating Results(1)                                                        
 
                                      Three months ended   Nine months ended
(unaudited)                                 September 30        September 30
(millions of dollars)                     2012      2011      2012      2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Revenues                                 2,126     2,043     5,918     5,824
 
Comparable EBITDA(2)                     1,083     1,188     3,193     3,424
 
Net Income Attributable to Common                                           
 Shares                                    369       386       993     1,150
 
Comparable Earnings(2)                     349       416     1,012     1,194
 
Cash Flows                                                                  
  Funds generated from operations(2)       866       928     2,466     2,614
  Decrease in operating working                                             
   capital                                 235        80        80       145
                                    ----------------------------------------
  Net cash provided by operations        1,101     1,008     2,546     2,759
                                    ----------------------------------------
                                    ----------------------------------------
 
Capital Expenditures                       694       505     1,555     1,593
                                    ----------------------------------------
                                    ----------------------------------------
 
Common Share Statistics                                                     
 
                                      Three months ended   Nine months ended
                                            September 30        September 30
(unaudited)                               2012      2011      2012      2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Net Income per Common Share - Basic      $0.52     $0.55     $1.41     $1.64
 
Comparable Earnings per Common                                              
 Share(2)                                $0.50     $0.59     $1.44     $1.70
 
Dividends Declared per Common Share      $0.44     $0.42     $1.32     $1.26
 
Basic Common Shares Outstanding                                             
 (millions)                                                                 
  Average for the period                   705       703       704       701
  End of period                            705       703       705       703
                                    ----------------------------------------
                                    ---------------------
-------------------
 
(1) Certain comparative figures have been reclassified to conform with the  
    financial statement presentation adopted for the current period.        
(2) Refer to the Non-GAAP Measures section in TransCanada's Quarterly Report
    to Shareholders dated October 29, 2012 for further discussion of        
    Comparable EBITDA, Comparable Earnings, Funds Generated from Operations 
    and Comparable Earnings per Share.                                      

 
TRANSCANADA CORPORATION - THIRD QUARTER 2012 
Quarterly Report to Shareholders  
Management's Discussion and Analysis  
This Management's Discussion and Analysis (MD&A) dated October 29,
2012 should be read in conjunction with the accompanying unaudited
Condensed Consolidated Financial Statements of TransCanada
Corporation (TransCanada or the Company) for the three and nine
months ended September 30, 2012. The condensed consolidated financial
statements of the Company have been prepared in accordance with
United States (U.S.) generally accepted accounting principles (U.S.
GAAP). Comparative figures, which were previously presented in
accordance with Canadian generally accepted accounting principles as
defined in Part V of the Canadian Institute of Chartered Accountants
Handbook (CGAAP), have been adjusted as necessary to be compliant
with the Company's accounting policies under U.S. GAAP, which is
discussed further in the Changes in Accounting Policies section in
this MD&A. This MD&A should also be read in conjunction with the
audited Consolidated Financial Statements and notes thereto, and the
MD&A contained in TransCanada's 2011 Annual Report, as prepared in
accordance with CGAAP, for the year ended December 31, 2011.
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's profile. "TransCanada" or "the Company" includes
TransCanada Corporation and its subsidiaries, unless otherwise
indicated. Amounts are stated in Canadian dollars unless otherwise
indicated. Abbreviations and acronyms used but not otherwise defined
in this MD&A are identified in the Glossary of Terms contained in
TransCanada's 2011 Annual Report. 
Forward-Looking Information  
This MD&A contains certain information that is forward looking and is
subject to important risks and uncertainties. The words "anticipate",
"expect", "believe", "may", "will", "should", "estimate", "project",
"outlook", "forecast", "intend", "target", "plan" or other similar
words are typically used to identify such forward-looking
information. Forward-looking statements in this document are intended
to provide TransCanada security holders and potential investors with
information regarding TransCanada and its subsidiaries, including
management's assessment of TransCanada's and its subsidiaries' future
plans and financial outlook. Forward-looking statements in this
document may include, but are not limited to, statements regarding: 


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

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


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

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


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

 
Additional information on these and other factors is available in the
reports filed by TransCanada with Canadian securities regulators and
with the U.S. Securities and Exchange Commission (SEC).  
Readers are cautioned against placing undue reliance on
forward-looking information, which is given as of the date it is
expressed in this MD&A or otherwise stated, and not to use
future-oriented information or financial outlooks for anything other
than their intended purpose. TransCanada undertakes no obligation to
publicly update or revise any forward-looking information in this
MD&A or otherwise stated, 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, Comparable Interest Expense,
Comparable Interest Income and Other, Comparable Income Taxes and
Funds Generated from Operations in this MD&A. These measures do not
have any standardized meaning as prescribed by U.S. GAAP. They are,
therefore, considered to be non-GAAP measures and are unlikely to 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 and is generally used to better measure performance and
evaluate trends of individual assets. EBITDA compr
ises earnings
before deducting interest and other financial charges, income taxes,
depreciation and amortization, net income attributable to
non-controlling interests and preferred share dividends. EBITDA
includes income from equity investments. EBIT is a measure of the
Company's earnings from ongoing operations and is generally used to
better measure performance and evaluate trends within each segment.
EBIT comprises earnings before deducting interest and other financial
charges, income taxes, net income attributable to non-controlling
interests and preferred share dividends. EBIT includes income from
equity investments.  
Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable
Interest Expense, Comparable Interest Income and Other, and
Comparable Income Taxes comprise Net Income Applicable to Common
Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other,
and Income Taxes, respectively, and are adjusted for specific items
that are significant but are not reflective of the Company's
underlying operations in the period. Specific items are subjective,
however, management uses its judgement and informed decision-making
when identifying items to be excluded in calculating these non-GAAP
measures, some of which may recur. Specific items may include but are
not limited to certain fair value adjustments relating to risk
management activities, income tax adjustments, gains or losses on
sales of assets, legal and bankruptcy settlements, and write-downs of
assets and investments. These non-GAAP measures are calculated on a
consistent basis from period to period. The specific items for which
such measures are adjusted in each applicable period may only be
relevant in certain periods and are disclosed in the Reconciliation
of Non-GAAP Measures table in this MD&A.  
The Company engages in risk management activities to reduce its
exposure to certain financial and commodity price risks by utilizing
derivatives. The risk management activities which TransCanada
excludes from Comparable Earnings provide effective economic hedges
but do not meet the specific criteria for hedge accounting treatment
and, therefore, changes in their fair values are recorded in Net
Income each year. The unrealized gains or losses from changes in the
fair value of these derivative contracts are not considered to be
representative of the underlying operations in the current period or
the positive margin that will be realized upon settlement. As a
result, these amounts have been excluded in the determination of
Comparable Earnings.  
The Reconciliation of Non-GAAP Measures table in this MD&A presents a
reconciliation of these non-GAAP measures to Net Income Attributable
to Common Shares. Comparable Earnings per Common Share is calculated
by dividing Comparable Earnings by the weighted average number of
common shares outstanding for the period.  
Funds Generated from Operations comprise Net Cash Provided by
Operations before changes in operating working capital and allows
management to better measure consolidated operating cash flow,
excluding fluctuations from working capital balances which may not
necessarily be reflective of underlying operations in the same
period. A reconciliation of Funds Generated from Operations to Net
Cash Provided by Operations is presented in the Summarized Cash Flow
table in the Liquidity and Capital Resources section in this MD&A. 
Reconciliation of Non-GAAP Measures  


 
Three months ended       Natural                                            
 September                   Gas       Oil                                  
 30(unaudited)         Pipelines Pipelines   Energy  Corporate     Total    
(millions of dollars)  2012 2011 2012 2011 2012 2011 2012 2011   2012  2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Comparable EBITDA       660  698  177  156  267  352  (21) (18) 1,083 1,188 
Depreciation and                                                            
 amortization          (231)(231) (37) (38) (70) (65)  (4)  (3)  (342) (337)
                       -----------------------------------------------------
Comparable EBIT         429  467  140  118  197  287  (25) (21)   741   851 
                       -----------------------------------------            
                       -----------------------------------------            
Other Income Statement                                                      
 Items                                                                      
Comparable interest                                                         
 expense                                                         (249) (242)
Comparable interest                                                         
 income and other                                                  22    (4)
Comparable income taxes                                          (123) (144)
Net income attributable                                                     
 to non-controlling                                                         
 interests                                                        (29)  (32)
Preferred share                                                             
 dividends                                                        (13)  (13)
                                                                ------------
Comparable Earnings                                               349   416 
 
Specific items (net of                                                      
 tax):                                                                      
  Risk management                                                           
   activities(1)                                                   20   (30)
                                                                ------------
Net Income Attributable                                                     
 to Common Shares                                                 369   386 
                                                                ------------
                                                                ------------
 
Three months ended September 30                                             
(unaudited) (millions of dollars)                                2012  2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Comparable Interest Expense                                      (249) (242)
Specific item:                                                              
  Risk management activities(1)                                     -     2 
                                                                ------------
Interest Expense                                                 (249) (240)
                                                                ------------
                                                                ------------
 
Comparable Interest Income and Other                               22    (4)
Specific item:                                                              
  Risk management activities(1)                                    12   (39)
                                                                ------------
Interest Income and Other                                          34   (43)
                                                                ------------
                                                                ------------
 
Comparable Income Taxes                                          (123) (144)
Specific items:                                                             
  Income taxes attributable to risk management activities(1)      (11)   13 
                                                                ------------
Income Taxes Expense                                             (134) (131)
                                                                ------
------
                                                                ------------
 
Comparable Earnings per Common Share                            $0.50 $0.59 
Specific items (net of tax):                                                
  Risk management activities                                     0.02 (0.04)
                                                                ------------
Net Income per Share                                            $0.52 $0.55 
                                                                ------------
                                                                ------------
 
(1) Three months ended September 30                                         
    (unaudited)(millions of dollars)                             2012  2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
    Risk Management Activities Gains/(Losses):                              
    Canadian Power                                                 11     - 
    U.S. Power                                                     20    (3)
    Natural Gas Storage                                           (12)   (3)
    Interest rate                                                   -     2 
    Foreign exchange                                               12   (39)
    Income taxes attributable to risk management activities       (11)   13 
                                                                ------------
    Risk Management Activities                                     20   (30)
                                                                ------------
                                                                ------------
 
Reconciliation of Non-GAAP Measures                                         
 
Nine months ended                                                           
 September 30                                                               
(unaudited)       Natural Gas        Oil                                    
(millions of        Pipelines  Pipelines   Energy  Corporate      Total     
 dollars)           2012  2011 2012 2011 2012 2011 2012 2011    2012   2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Comparable EBITDA  2,051 2,159  526  408  681  914  (65) (57)  3,193  3,424 
Depreciation and                                                            
 amortization       (697) (688)(109) (95)(215)(194) (11) (10) (1,032)  (987)
                   ---------------------------------------------------------
Comparable EBIT    1,354 1,471  417  313  466  720  (76) (67)  2,161  2,437 
                   -------------------------------------------              
                   -------------------------------------------              
Other Income                                                                
 Statement Items                                                            
Comparable interest                                                         
 expense                                                        (730)  (688)
Comparable interest                                                         
 income and other                                                 66     52 
Comparable income                                                           
 taxes                                                          (354)  (470)
Net income                                                                  
 attributable to                                                            
 non-controlling                                                            
 interests                                                       (90)   (96)
Preferred share                                                             
 dividends                                                       (41)   (41)
                                                              --------------
Comparable Earnings                                            1,012  1,194 
 
Specific items (net                                                         
 of tax):                                                                   
  Sundance A PPA                                                            
   arbitration                                                              
   decision                                                      (15)     - 
  Risk management                                                           
   activities(1)                                                  (4)   (44)
                                                              --------------
Net Income                                                                  
 Attributable to                                                            
 Common Shares                                                   993  1,150 
                                                              --------------
                                                              --------------
 
Nine months ended September 30                                              
(unaudited) (millions of dollars)                               2012   2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Comparable Interest Expense                                     (730)  (688)
Specific item:                                                              
  Risk management activities(1)                                    -      2 
                                                              --------------
Interest Expense                                                (730)  (686)
                                                              --------------
                                                              --------------
 
Comparable Interest Income and Other                              66     52 
Specific item:                                                              
  Risk management activities(1)                                    4    (40)
                                                              --------------
Interest Income and Other                                         70     12 
                                                              --------------
                                                              --------------
 
Comparable Income Taxes                                         (354)  (470)
Specific items:                                                             
  Income taxes attributable to Sundance A PPA arbitration                   
   decision                                                        5      - 
  Income taxes attributable to risk management activities(1)       1     21 
                                                              --------------
Income Taxes Expense                                            (348)  (449)
                                                              --------------
                                                              --------------
 
Comparable Earnings per Common Share                           $1.44  $1.70 
  Specific items (net of tax):                                              
  Sundance A PPA arbitration decision                          (0.02)     - 
Risk management activities                                     (0.01) (0.06)
                                                              --------------
Net Income per Share                                           $1.41  $1.64 
                                                              --------------
                                                              --------------
 
(1) Nine months ended September 30                                          
    (unaudited)(millions of dollars)                             2012  2011 
----------------------------------------------
------------------------------
----------------------------------------------------------------------------
 
    Risk Management Activities Gains/(Losses):                              
    Canadian Power                                                 10     1 
    U.S. Power                                                      4   (15)
    Natural Gas Storage                                           (23)  (13)
    Interest rate                                                   -     2 
    Foreign exchange                                                4   (40)
    Income taxes attributable to risk management activities         1    21 
                                                                ------------
    Risk Management Activities                                     (4)  (44)
                                                                ------------
                                                                ------------

 
Consolidated Results of Operations 
Third Quarter Results  
Comparable Earnings in third quarter 2012 were $349 million or $0.50
per share compared to $416 million or $0.59 per share for the same
period in 2011. Comparable Earnings excluded net unrealized after-tax
gains of $20 million ($31 million pre-tax) (2011 - losses of $30
million after tax ($43 million pre-tax)) resulting from changes in
the fair value of certain risk management activities.  
Comparable Earnings decreased $67 million or $0.09 per share in third
quarter 2012 compared to the same period in 2011 and reflected the
following: 


 
--  decreased Canadian Natural Gas Pipelines Comparable net income primarily
    due to lower earnings from the Canadian Mainline which excluded
    incentive earnings and reflected a lower investment base; 
 
 
--  decreased U.S. and International Natural Gas Pipelines EBIT which 
    primarily reflected lower revenue from ANR as well as the impact of
    capacity sold at lower rates on Great Lakes; 
 
 
--  increased Oil Pipelines Comparable EBIT which reflected higher revenues
    primarily due to higher contracted volumes and higher final fixed tolls
    for the Cushing Extension section of the Keystone Pipeline system which
    came into effect in July 2012; 
 
 
--  decreased Energy Comparable EBIT primarily due to the Sundance A power
    purchase arrangement (PPA) force majeure, lower Alberta PPA volumes, as
    well as a decrease in Equity Income from Bruce Power primarily due to a
    planned maintenance outage at Bruce A Unit 4, partially offset by higher
    contributions from Eastern Power due to higher Becancour contractual
    earnings, and incremental earnings from Montagne-Seche and phase one of
    Gros-Morne at Cartier Wind which were both placed in service in November
    2011; 
 
 
--  increased Comparable Interest Income and Other due to higher realized
    gains in 2012 compared to losses in 2011 on derivatives used to manage
    the Company's exposure to foreign exchange rate fluctuations on U.S.
    dollar-denominated income, as well as gains in 2012 compared to losses
    in 2011 on translation of foreign denominated working capital balances;
    and 
 
 
--  decreased Comparable Income Taxes primarily due to lower pre-tax
    earnings in 2012 compared to 2011. 

 
Comparable Earnings in the first nine months of 2012 were $1,012
million or $1.44 per share compared to $1,194 million or $1.70 per
share for the same period in 2011. Comparable Earnings in the first
nine months of 2012 excluded net unrealized after-tax losses of $4
million ($5 million pre-tax) (2011 - losses of $44 million after tax
($65 million pre-tax)) resulting from changes in the fair value of
certain risk management activities. Comparable Earnings in the first
nine months of 2012 also excluded a negative after-tax charge of $15
million ($20 million pre-tax) following the July 2012 Sundance A PPA
arbitration decision that was recorded in second quarter 2012 but
related to amounts originally recorded in fourth quarter 2011.  
Comparable Earnings decreased $182 million or $0.26 per share for the
first nine months of 2012 compared to the same period in 2011 and
reflected the following: 


 
--  decreased Canadian Natural Gas Pipelines Comparable net income primarily
    due to lower earnings from the Canadian Mainline which excluded
    incentive earnings and reflected a lower investment base; 
 
 
--  decreased U.S. and International Natural Gas Pipelines EBIT which
    primarily reflected lower revenue resulting from uncontracted capacity 
    and lower rates on Great Lakes as well as lower revenue from ANR, 
    partially offset by incremental earnings from the Guadalajara pipeline,
    which was placed in service in June 2011; 
 
 
--  increased Oil Pipelines Comparable EBIT as the Company commenced
    recording earnings from the Keystone Pipeline System in February 2011
    and higher final fixed tolls for the Cushing Extension and the Wood
    River/Patoka sections which came into effect in July 2012 and May 2011,
    respectively, as well as higher volumes; 
 
 
--  decreased Energy Comparable EBIT primarily as a result of the Sundance A
    PPA force majeure, a decrease in Equity Income from Bruce Power
    primarily due to lower volumes resulting from increased planned outage
    days, lower realized power prices and reduced waterflows at U.S. hydro
    facilities and lower Natural Gas Storage revenue, partially offset by
    higher contributions from Eastern Power primarily due to higher
    Becancour contractual earnings and incremental earnings from Montagne-
    Seche and phase one of Gros-Morne which were placed in service in
    November 2011; 
 
 
--  increased Comparable Interest Expense due to the negative impact of a
    stronger U.S. dollar on U.S. dollar-denominated interest, incremental
    interest expense on new debt issues in 2012 and 2011 and lower
    capitalized interest as assets under construction were placed in
    service; 
 
 
--  increased Comparable Interest Income and Other due to gains in 2012
    compared to losses in 2011 on translation of foreign denominated working
    capital balances; and 
 
 
--  decreased Comparable Income Taxes primarily due to lower pre-tax
    earnings in 2012 compared to 2011. 

 
U.S. Dollar-Denominated Balances  
On a consolidated basis, the impact of changes in the value of the
U.S. dollar on U.S. operations is partially offset by other U.S.
dollar-denominated items as set out in the following table. The
resultant pre-tax net exposure is managed using derivatives, further
reducing the Company's exposure to changes in Canadian-U.S. foreign
exchange rates. The average exchange rates to convert a U.S. dollar
to a Canadian dollar for the three and nine months ended September
30, 2012 were 0.99 and 1.00, respectively (2011 - 0.98 and 0.98,
respectively). 
Summary of Significant U.S. Dollar-Denominated Amounts 


 
                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of U.S. dollars)               2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
U.S. Natural Gas Pipelines                                                  
 Comparable EBIT(1)                       139       166       501       578 
U.S. Oil Pipelines Comparable                                               
 EBIT(1)                                   92        78       269       210 
U.S. Power Comparable EBIT(1)              57        63        71       160 
Interest on U.S. dollar-denominated                                         
 long-term debt                          (185)     (187)     (554)     (549)
Capitalized interest on U.S. capital                                        
 expenditures                              28        21        81        93 
U.S. non-controlling inter
ests and                                          
 other                                    (44)      (48)     (140)     (143)
                                    ----------------------------------------
                                           87        93       228       349 
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Refer to the Non-GAAP Measures section in this MD&A for further         
    discussion of Comparable EBIT.                                          

 
Natural Gas Pipelines  
Natural Gas Pipelines' Comparable EBIT was $429 million and $1.4
billion in the three and nine months ended September 30, 2012,
respectively, compared to $467 million and $1.5 billion,
respectively, for the same periods in 2011.  


 
Natural Gas Pipelines Results                                               
 
                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of dollars)                    2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Canadian Natural Gas Pipelines                                              
Canadian Mainline                         247       264       744       796 
Alberta System                            194       191       554       557 
Foothills                                  29        31        90        96 
Other (TQM(1), Ventures LP)                 7         9        22        26 
                                    ----------------------------------------
Canadian Natural Gas Pipelines                                              
 Comparable EBITDA(2)                     477       495     1,410     1,475 
Depreciation and amortization(3)         (179)     (177)     (533)     (533)
                                    ----------------------------------------
Canadian Natural Gas Pipelines                                              
 Comparable EBIT(2)                       298       318       877       942 
                                    ----------------------------------------
 
U.S. and International Natural Gas                                          
 Pipelines (in U.S. dollars)                                                
ANR                                        41        55       191       233 
GTN(4)                                     28        29        84       105 
Great Lakes(5)                             16        26        51        81 
TC PipeLines, LP(1)(6)(7)                  19        22        57        64 
Other U.S. Pipelines (Iroquois(1),                                          
 Bison(8), Portland(7)(9))                 22        18        79        80 
International (Tamazunchale,                                                
 Guadalajara(10), TransGas(1), Gas                                          
 Pacifico/INNERGY(1))                      27        27        85        52 
General, administrative and support                                         
 costs                                      -        (2)       (4)       (6)
Non-controlling interests(7)               39        45       122       127 
                                    ----------------------------------------
U.S. and International Natural Gas                                          
 Pipelines Comparable EBITDA(2)           192       220       665       736 
Depreciation and amortization(3)          (53)      (54)     (164)     (158)
                                    ----------------------------------------
U.S. and International Natural Gas                                          
 Pipelines Comparable EBIT(2)             139       166       501       578 
Foreign exchange                           (1)       (3)        1       (12)
                                    ----------------------------------------
U.S. and International Natural Gas                                          
 Pipelines Comparable EBIT(2) (in                                           
 Canadian dollars)                        138       163       502       566 
                                    ----------------------------------------
 
Natural Gas Pipelines Business                                              
 Development Comparable EBITDA and                                          
 EBIT(2)                                   (7)      (14)      (25)      (37)
                                    ----------------------------------------
 
Natural Gas Pipelines Comparable                                            
 EBIT(2)                                  429       467     1,354     1,471 
                                    ----------------------------------------
                                    ----------------------------------------
 
Summary:                                                                    
Natural Gas Pipelines Comparable                                            
 EBITDA(2)                                660       698     2,051     2,159 
Depreciation and amortization(3)         (231)     (231)     (697)     (688)
                                    ----------------------------------------
Natural Gas Pipelines Comparable                                            
 EBIT(2)                                  429       467     1,354     1,471 
                                    ----------------------------------------
                                    ----------------------------------------
 
(1)  Results from TQM, Northern Border, Iroquois, TransGas and Gas          
     Pacifico/INNERGY reflect the Company's share of equity income from     
     these investments.                                                     
(2)  Refer to the Non-GAAP Measures section in this MD&A for further        
     discussion of Comparable EBITDA and Comparable EBIT.                   
(3)  Does not include depreciation and amortization from equity investments.
(4)  Results reflect TransCanada's direct ownership interest of 75 per cent 
     effective May 2011 and 100 per cent prior to that date.                
(5)  Represents TransCanada's 53.6 per cent direct ownership interest.      
(6)  Effective May 2011, TransCanada's ownership interest in TC PipeLines,  
     LP decreased from 38.2 per cent to 33.3 per cent. As a result, the TC  
     PipeLines, LP results include TransCanada's decreased ownership in TC  
     PipeLines, LP and TransCanada's effective ownership through TC         
     PipeLines, LP of 8.3 per cent of each of GTN and Bison since May 2011. 
(7)  Non-Controlling Interests reflects Comparable EBITDA for the portions  
     of TC PipeLines, LP and Portland not owned by TransCanada.             
(8)  Results reflect TransCanada's direct ownership of 75 per cent of Bison 
     effective May 2011 when 25 per cent was sold to TC PipeLines, LP and   
     100 per cent since January 2011 when Bison was placed in service.      
(9)  Represents TransCanada's 61.7 per cent ownership interest.             
(10) Includes Guadalajara's operations since June 2011 when the asset was   
     placed in service.                                                     
 
Net Income for Wholly Owned Canadian Natural Gas Pipelines                  
 
                                      Three months ended   Nine months ended
(unaudited)                                 September 30        September 30
(millions of U.S. dollars)                2012      2011      2012      2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Canadian Mainline                           47        61       140       186
Alberta System                              53        51       153       149
Foothills                                 
   4         6        14        18
                                    ----------------------------------------
                                    ----------------------------------------

 
Canadian Natural Gas Pipelines  
Canadian Mainline's net income of $47 million and $140 million in the
three and nine months ended September 30, 2012, respectively,
decreased $14 million and $46 million from $61 million and $186
million in the same periods in 2011. Canadian Mainline's net income
for the three and nine months ended September 30, 2011 included
incentive earnings earned under an incentive arrangement in the
five-year tolls settlement which expired December 31, 2011. In the
absence of a National Energy Board (NEB) decision with respect to the
2012-2013 tolls application, which is not expected until late first
quarter 2013, Canadian Mainline's 2012 year-to-date results continued
to reflect the last NEB-approved rate of return on common equity of
8.08 per cent on deemed common equity of 40 per cent and excluded
incentive earnings. In addition, Canadian Mainline's 2012
year-to-date net income decreased as a result of a lower average
investment base compared to the prior year.  
The Alberta System's net income in the three and nine months ended
September 30, 2012, was $53 million and $153 million, respectively,
compared to $51 million and $149 million for the same periods in
2011. The positive impact on 2012 net income from a higher average
investment base was mostly offset by lower incentive earnings for the
three and nine months ending September 30, 2012.  
Canadian Mainline's Comparable EBITDA for the three and nine months
ended September 30, 2012 of $247 million and $744 million,
respectively, decreased $17 million and $52 million compared to the
same periods in 2011. EBITDA from the Canadian Mainline reflects the
net income variances discussed above as well as variances in
depreciation, financial charges and income taxes which are recovered
in revenue on a flow-through basis and, therefore, do not impact net
income. 
U.S. and International Natural Gas Pipelines  
ANR's Comparable EBITDA in the three and nine months ended September
30, 2012 was US$41 million and US$191 million, respectively, compared
to US$55 million and US$233 million for the same periods in 2011. The
decreases were primarily due to lower transportation and storage
revenues, higher operating and maintenance costs, lower incidental
commodity sales and a second quarter 2011 settlement with a
counterparty.  
GTN's Comparable EBITDA in the three and nine months ended September
30, 2012 was US$28 million and US$84 million, respectively, compared
to US$29 million and US$105 million for the same periods in 2011. The
decrease in the nine months ended September 2012 compared to 2011 was
primarily due to TransCanada's sale of a 25 per cent interest in GTN
to TC PipeLines, LP in May 2011.  
Great Lakes' Comparable EBITDA in the three and nine months ended
September 30, 2012 was US$16 million and US$51 million, respectively,
compared to US$26 million and US$81 million for the same periods in
2011. The decreases were due to lower transportation revenue
resulting from unsold long-haul winter capacity as well as summer
capacity sold under short-term contracts at lower rates compared to
the same period in 2011.  
International Comparable EBITDA increased US$33 million for the nine
months ended September 30, 2012 compared to the same period in 2011.
The increase was primarily due to incremental earnings from the
Guadalajara pipeline which was placed in service in June 2011. 
Business Development  
Natural Gas Pipelines' Business Development Comparable EBITDA loss
from business development activities decreased $7 million and $12
million in the three and nine months ended September 30, 2012,
respectively, compared to the same periods in 2011. The decreases in
business development costs were primarily related to reduced activity
in 2012 for the Alaska Pipeline Project and a levy charged by the NEB
in March 2011 to recover the Aboriginal Pipeline Group's
proportionate share of costs relating to the Mackenzie Gas Project
hearings. 
Depreciation and Amortization  
Natural Gas Pipelines' Depreciation and Amortization increased $9
million for the nine months ended September 30, 2012 compared to the
same period in 2011. The increase was primarily due to incremental
depreciation for the Guadalajara pipeline which was placed in service
in June 2011. 


 
Operating Statistics                                                        
 
Nine months ended                   Canadian         Alberta                
September 30                      Mainline(1)       System(2)         ANR(3)
(unaudited)                     2012    2011    2012    2011    2012    2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Average investment base                                                     
 (millions of dollars)         5,748   6,250   5,426   5,017     n/a     n/a
Delivery volumes (Bcf)                                                      
  Total                        1,167   1,474   2,697   2,580   1,199   1,276
  Average per day                4.3     5.4     9.8     9.5     4.4     4.7
                            ------------------------------------------------
                            ------------------------------------------------
 
(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, 2012 were 659 Bcf (2011 - 912   
    Bcf); average per day was 2.4 Bcf (2011 - 3.3 Bcf).                     
(2) Field receipt volumes for the Alberta System for the nine months ended  
    September 30, 2012 were 2,747 Bcf (2011 - 2,643 Bcf); average per day   
    was 10.0 Bcf (2011 - 9.7 Bcf).                                          
(3) Under its current rates, which are approved by the FERC, ANR's results  
    are not impacted by changes in its average investment base.             

 
Oil Pipelines  
Oil Pipelines Comparable EBIT for the three and nine months ended
September 30, 2012 was $140 million and $417 million, respectively,
compared to $118 million and $313 million for the three and eight
month periods in 2011. 


 
Oil Pipelines Results                                                       
 
                                                                      Eight 
                                                    Nine months      months 
                                                          ended       ended 
                                 Three months ended   September   September 
(unaudited)                            September 30          30          30 
(millions of dollars)                2012      2011        2012        2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Keystone Pipeline System              180       157         532         410 
Oil Pipeline Business                                                       
 Development                           (3)       (1)         (6)         (2)
                                --------------------------------------------
Oil Pipelines Comparable                                                    
 EBITDA(1)                            177       156         526         408 
Depreciation and amortization         (37)      (38)       (109)        (95)
                                --------------------------------------------
Oil Pipelines Comparable EBIT(1)      140       118         417         313 
                                --------------------------------------------
                                ----------------------------------------
----
 
Comparable EBIT denominated as                                              
 follows:                                                                   
Canadian dollars                       48        41         147         108 
U.S. dollars                           92        78         269         210 
Foreign exchange                        -        (1)          1          (5)
                                --------------------------------------------
Oil Pipelines Comparable EBIT(1)      140       118         417         313 
                                --------------------------------------------
                                --------------------------------------------
 
(1) Refer to the Non-GAAP Measures section in this MD&A for further         
    discussion of Comparable EBITDA and Comparable EBIT.                    

 
Keystone Pipeline System  
The Keystone Pipeline System's Comparable EBITDA of $180 million and
$532 million for the three and nine months ended September 30, 2012,
respectively, increased $23 million and $122 million compared to the
three and eight month periods in 2011. These increases reflected
higher revenues primarily resulting from higher contracted volumes,
the impact of higher final fixed tolls on the Cushing Extension and
Wood River/Patoka sections of the system which came into effect in
July 2012 and May 2011, respectively, and nine months of earnings
being recorded in 2012 compared to eight months in 2011.  
EBITDA from the Keystone Pipeline System is primarily generated from
payments received under long-term commercial arrangements for
committed capacity that are not dependant on actual throughput.
Uncontracted capacity is offered to the market on a spot basis and,
when capacity is available, provides opportunities to generate
incremental EBITDA. 
Depreciation and Amortization  
Oil Pipelines Depreciation and Amortization increased $14 million for
the nine months ended September 30, 2012 compared to the
corresponding period in 2011 and primarily reflected nine months of
operations compared to eight months in 2011 for the Wood River/Patoka
and Cushing Extension sections of the Keystone Pipeline System. 


 
Operating Statistics                                                        
                                                                       Eight
                                                    Nine months       months
                                Three months ended        ended        ended
                                      September 30 September 30 September 30
(unaudited)                        2012       2011         2012         2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Delivery volumes (thousands                                                 
 of barrels)(1)                                                             
  Total                          44,564     39,696      139,261       92,329
  Average per day                   484        431          508          382
                             -----------------------------------------------
                             -----------------------------------------------
 
(1) Delivery volumes reflect physical deliveries.                           

 
Energy  
Energy's Comparable EBIT was $197 million and $466 million for the
three and nine months ended September 30, 2012, respectively,
compared to $287 million and $720 million, respectively, for the same
periods in 2011.  


 
Energy Results                                                              
 
                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of dollars)                    2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Canadian Power                                                              
Western Power(1)(2)                        93       150       251       341 
Eastern Power(1)(3)                        85        72       251       215 
Bruce Power(1)                              4        47        22       111 
General, administrative and support                                         
 costs                                    (12)      (11)      (34)      (28)
                                    ----------------------------------------
Canadian Power Comparable EBITDA(4)       170       258       490       639 
Depreciation and amortization(5)          (38)      (37)     (117)     (106)
                                    ----------------------------------------
Canadian Power Comparable EBIT(4)         132       221       373       533 
                                    ----------------------------------------
 
U.S. Power (in U.S. dollars)                                                
Northeast Power                           100       100       195       270 
General, administrative and support                                         
 costs                                    (13)      (10)      (34)      (29)
                                    ----------------------------------------
U.S. Power Comparable EBITDA(4)            87        90       161       241 
Depreciation and amortization             (30)      (27)      (90)      (81)
                                    ----------------------------------------
U.S. Power Comparable EBIT(4)              57        63        71       160 
Foreign exchange                           (1)        -         -        (3)
                                    ----------------------------------------
U.S. Power Comparable EBIT(4) (in                                           
 Canadian dollars)                         56        63        71       157 
                                    ----------------------------------------
 
Natural Gas Storage                                                         
Alberta Storage(1)                         20        12        54        62 
General, administrative and support                                         
 costs                                     (3)       (1)       (7)       (6)
                                    ----------------------------------------
Natural Gas Storage Comparable                                              
 EBITDA(4)                                 17        11        47        56 
Depreciation and amortization(5)           (2)       (2)       (8)       (9)
                                    ----------------------------------------
Natural Gas Storage Comparable                                              
 EBIT(4)                                   15         9        39        47 
                                    ----------------------------------------
 
Energy Business Development                                                 
 Comparable EBITDA and EBIT(1)(4)          (6)       (6)      (17)      (17)
                                    ----------------------------------------
 
Energy Comparable EBIT(1)(4)              197       287       466       720 
                                    ----------------------------------------
                                    ----------------------------------------
 
Summary:                                                                    
Energy Comparable EBITDA(4)               267       352       681       914 
Depreciation and amortization(5)          (70)      (65)     (215)     (194)
                                    ----------------------------------------
Energy Comparable EBIT(4)                 197       287       466       720 
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Results from ASTC Power Partnership, Portlands Energy, Bruc
e Power and  
    CrossAlta reflect the Company's share of equity income from these       
    investments.                                                            
(2) Includes Coolidge effective May 2011.                                   
(3) Includes Montagne-Seche and phase one of Gros-Morne at Cartier Wind     
    effective November 2011.                                                
(4) Refer to the Non-GAAP Measures section in this MD&A for further         
    discussion of Comparable EBITDA and Comparable EBIT.                    
(5) Does not include depreciation and amortization of equity investments.   
 
Canadian Power                                                              
 
Western and Eastern Canadian Power Comparable EBIT(1)(2)(3)                 
 
                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of dollars)                    2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Revenue                                                                     
  Western Power(2)                        152       239       482       603 
  Eastern Power(3)                        108        99       309       286 
  Other(4)                                 19        14        66        54 
                                    ----------------------------------------
                                          279       352       857       943 
                                    ----------------------------------------
 
Income from Equity Investments(5)          28        39        45        85 
                                    ----------------------------------------
 
Commodity Purchases Resold                                                  
  Western Power                           (70)     (103)     (207)     (279)
  Other(6)                                 (1)       (4)       (3)      (13)
                                    ----------------------------------------
                                          (71)     (107)     (210)     (292)
                                    ----------------------------------------
 
Plant operating costs and other           (58)      (62)     (160)     (180)
Sundance A PPA arbitration                                                  
 decision(7)                                -         -       (30)        - 
General, administrative and support                                         
 costs                                    (12)      (11)      (34)      (28)
                                    ----------------------------------------
Comparable EBITDA(1)                      166       211       468       528 
Depreciation and amortization(8)          (38)      (37)     (117)     (106)
                                    ----------------------------------------
Comparable EBIT(1)                        128       174       351       422 
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Refer to the Non-GAAP Measures section in this MD&A for further         
    discussion of Comparable EBITDA and Comparable EBIT.                    
(2) Includes Coolidge effective May 2011.                                   
(3) Includes Montagne-Seche and phase one of Gros-Morne at Cartier Wind     
    effective November 2011.                                                
(4) Includes sales of excess natural gas purchased for generation and       
    thermal carbon black.                                                   
(5) Results reflect equity income from TransCanada's 50 per cent ownership  
    interest in each of ASTC Power Partnership, which holds the Sundance B  
    PPA, and Portlands Energy.                                              
(6) Includes the cost of excess natural gas not used in operations.         
(7) Refer to the Recent Developments section in this MD&A for more          
    information regarding the Sundance A PPA arbitration decision.          
(8) Excludes depreciation and amortization of equity investments.           
 
Western and Eastern Canadian Power Operating Statistics(1)                  
 
                                     Three months ended   Nine months ended 
                                           September 30        September 30 
(unaudited)                              2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Volumes (GWh)                                                               
Generation                                                                  
  Western Power(2)                        652       630     1,977     1,937 
  Eastern Power(3)                      1,426     1,014     3,476     2,862 
Purchased                                                                   
  Sundance A, B and Sheerness                                               
   PPAs(4)                              1,555     2,074     4,889     6,034 
  Other purchases                           -        60        46       203 
                                    ----------------------------------------
                                        3,633     3,778    10,388    11,036 
                                    ----------------------------------------
Contracted                                                                  
  Western Power(2)                      2,012     2,182     6,048     6,256 
  Eastern Power(3)                      1,426     1,014     3,476     2,862 
Spot                                                                        
  Western Power                           195       582       864     1,918 
                                    ----------------------------------------
                                        3,633     3,778    10,388    11,036 
                                    ----------------------------------------
                                    ----------------------------------------
Plant Availability(5)                                                       
Western Power(2)(6)                        91%       98%       96%       97%
Eastern Power(3)(7)                        97%       96%       89%       96%
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Includes TransCanada's share of Equity Investments' volumes.            
(2) Includes Coolidge effective May 2011.                                   
(3) Includes Montagne-Seche and phase one of Gros-Morne at Cartier Wind     
    effective November 2011 and volumes related to TransCanada's 50 per cent
    ownership interest in Portlands Energy.                                 
(4) Includes TransCanada's 50 per cent ownership interest of Sundance B     
    volumes through the ASTC Power Partnership. No volumes were delivered   
    under the Sundance A PPA in 2012 or 2011.                               
(5) Plant availability represents the percentage of time in a period that   
    the plant is available to generate power regardless of whether it is    
    running.                                                                
(6) Excludes facilities that provide power under PPAs.                      
(7) Becancour has been excluded from the availability calculation as power  
    generation has been suspended since 2008.                               

 
Western Power's Comparable EBITDA of $93 million and $251 million for
the three and nine months ended September 30, 2012 decreased $57
million and $90 million compared to the same periods of 2011,
respectively.   
Throughout first quarter 2012, revenues and cost
s related to the
Sundance A PPA had been recorded as though the outages of Units 1 and
2 were interruptions of supply. As a result of the Sundance A PPA
arbitration decision received in July 2012, a $30 million charge,
equivalent to the amount of pre-tax income recorded in first quarter
2012, was recorded in second quarter 2012. Because the plant is now
in force majeure, revenues and costs will not be recorded until the
plant returns to service. Western Power's Comparable EBITDA for the
three and nine months ended September 30, 2011 included $48 million
and $99 million, respectively, of accrued earnings related to the
Sundance A PPA. Refer to the Recent Developments section in this MD&A
for further discussion regarding the Sundance A PPA arbitration
decision.   
The decrease in Western Power's Comparable EBITDA in third quarter
2012 compared to 2011 was primarily due to the Sundance A PPA force
majeure as well as lower volumes, partially offset by higher realized
power prices.   
The decrease in Western Power's Comparable EBITDA for the nine months
ended September 30, 2012 compared to the same period in 2011
primarily reflected the Sundance A PPA force majeure as well as the
impact of lower volumes sold, partially offset by the impact of lower
fuel costs, incremental earnings from Coolidge which was placed in
service in May 2011, and higher realized power prices.  
Purchased volumes for the three and nine months ended September 30,
2012 decreased compared to the same periods in 2011 primarily due to
decreased utilization of the Sundance B and Sheerness PPAs during
periods of lower spot market power prices and higher plant outage
days. Average spot market power prices decreased 18 per cent to $78
per megawatt hour (MWh) and 23 per cent to $59 per MWh for the three
and nine months ended September 30, 2012, respectively, compared to
the same periods in 2011. Despite the decrease in spot prices,
Western Power earned a higher realized price per MWh for the three
and nine months ended September 30, 2012 compared to the same periods
in 2011 as a result of contracting activities.  
Western Power's Power Revenue of $152 million and $482 million for
the three and nine months ended September 30, 2012, respectively,
decreased $87 million and $121 million, respectively, compared to the
same periods in 2011 primarily due to the Sundance A PPA force
majeure as well as lower purchased volumes, partially offset by
higher realized power prices. Revenue for the nine months ended
September 30, 2012 was also positively affected by Coolidge being
placed in service in May 2011.  
Western Power's Commodity Purchases Resold of $70 million and $207
million for the three and nine months ended September 30, 2012,
respectively, decreased $33 million and $72 million, respectively,
compared to the same periods in 2011 primarily due to the Sundance A
PPA force majeure, as well as lower purchased volumes.  
Eastern Power's Comparable EBITDA of $85 million and $251 million for
the three and nine months ended September 30, 2012 increased $13
million and $36 million, respectively, compared to the same periods
in 2011. Similarly, Eastern Power's Power Revenues of $108 million
and $309 million for the three and nine months ended September 30,
2012 increased $9 million and $23 million, respectively, compared to
the same periods in 2011. The increases were primarily due to higher
Becancour contractual earnings and incremental earnings from
Montagne-Seche and phase one of Gros-Morne at Cartier Wind, which
were both placed in service in November 2011.  
Income from Equity Investments of $28 million and $45 million,
respectively, for the three and nine months ended September 30, 2012
decreased $11 million and $40 million, respectively, compared to the
same periods in 2011 primarily due to lower earnings from the ASTC
Power Partnership as a result of lower Sundance B PPA volumes and
lower spot market power prices. Income from Equity Investments for
the nine months ended September 30, 2012 was also impacted by lower
earnings from Portlands Energy due to an unplanned outage in second
quarter 2012.  
Plant Operating Costs and Other, which includes fuel gas consumed in
power generation, of $58 million and $160 million for the three and
nine months ended September 30, 2012, respectively, decreased $4
million and $20 million compared to the same periods in 2011
primarily due to decreased natural gas fuel prices in 2012 compared
to 2011.  
Depreciation and Amortization for the nine months ended September 30,
2012 increased $11 million compared to the same period in 2011
primarily due to Montagne-Seche and phase one of Gros-Morne at
Cartier Wind and Coolidge being placed in service.  
Approximately 91 per cent of Western Power sales volumes were sold
under contract in third quarter 2012 compared to 81 per cent in third
quarter 2011. To reduce its exposure to spot market prices in
Alberta, as at September 30, 2012, Western Power had entered into
fixed-price power sales contracts to sell approximately 2,100
gigawatt hours (GWh) for the remainder of 2012 and 5,700 GWh for
2013.   
Eastern Power's sales volumes were 100 per cent sold under contract
and are expected to be fully contracted going forward. 


 
Bruce Power Results                                                         
 
(TransCanada's share)                Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of dollars unless                                                 
 otherwise indicated)                    2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Income/(Loss) from Equity                                                   
 Investments(1)                                                             
Bruce A                                   (39)       16       (95)       48 
Bruce B                                    43        31       117        63 
                                    ----------------------------------------
                                            4        47        22       111 
                                    ----------------------------------------
                                    ----------------------------------------
Comprised of:                                                               
Revenues                                  188       221       535       636 
Operating expenses                       (142)     (135)     (402)     (417)
Depreciation and other                    (42)      (39)     (111)     (108)
                                    ----------------------------------------
                                            4        47        22       111 
                                    ----------------------------------------
                                    ----------------------------------------
 
Bruce Power - Other Information                                             
Plant availability(2)                                                       
  Bruce A                                  59%       97%       55%       98%
  Bruce B                                  99%       94%       94%       88%
  Combined Bruce Power                     87%       95%       76%       91%
Planned outage days                                                         
  Bruce A                                  60         -       213         5 
  Bruce B                                   -        19        46        92 
Unplanned outage days                                                       
  Bruce A                                   7         4         7        13 
  Bruce B                                   2         -        25        24 
Sales volumes (GWh)(1)                                                      
  Bruce A                                 943     1,489     2,585     4,425 
  Bruce B                   
            2,241     2,111     6,197     5,903 
                                    ----------------------------------------
                                        3,184     3,600     8,782    10,328 
                                    ----------------------------------------
                                    ----------------------------------------
Realized sales price per MWh                                                
  Bruce A                                 $68       $66       $68       $66 
  Bruce B(3)                              $54       $53       $55       $54 
  Combined Bruce Power                    $57       $57       $57       $58 
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Represents TransCanada's 48.9 per cent ownership interest in Bruce A and
    31.6 per cent ownership interest in Bruce B.                            
(2) Plant availability represents the percentage of time in a year that the 
    plant is available to generate power regardless of whether it is        
    running.                                                                
(3) Includes revenue received under the floor price mechanism and from      
    contract settlements as well as volumes and revenues associated with    
    deemed generation.                                                      

 
TransCanada's Equity Income from Bruce A decreased $55 million and
$143 million for the three and nine months ended September 30, 2012,
respectively, to losses of $39 million and $95 million compared to
income of $16 million and $48 million for the same periods in 2011.
The third quarter decrease was primarily due to lower volumes
resulting from the Unit 4 planned outage which commenced on August 2,
2012. The decrease for the nine months ended September 30, 2012 also
reflected the impact of the Unit 3 West Shift Plus planned outage
which commenced in November 2011 and was completed in June 2012.
Refer to the Recent Developments section in this MD&A for further
discussion of these planned outages.  
TransCanada's Equity Income from Bruce B for the three and nine
months ended September 30, 2012 of $43 million and $117 million,
respectively, increased $12 million and $54 million compared to the
same periods in 2011. The increases were primarily due to higher
volumes and lower operating costs resulting from fewer planned outage
days, lower lease expense and higher realized prices. Provisions in
the Bruce B lease agreement with Ontario Power Generation provide for
a reduction in annual lease expense if the annual average Ontario
spot price for electricity is less than $30 per MWh. The average spot
price has been below $30 per MWh for the first nine months of 2012,
and this is expected to continue throughout 2012.   
Under a contract with the Ontario Power Authority (OPA), all output
from Bruce A in third quarter 2012 was sold at a fixed price of
$68.23 per MWh (before recovery of fuel costs from the OPA) compared
to $66.33 per MWh in third quarter 2011. Also under a contract with
the OPA, all output from the Bruce B units was subject to a floor
price of $51.62 per MWh in third quarter 2012 compared to $50.18 in
third quarter 2011. Both the Bruce A and Bruce B contract prices are
adjusted annually for inflation on April 1.  
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. With respect to 2012, TransCanada
currently expects spot prices to be less than the floor price for the
year, therefore, no amounts recorded in revenues in 2012 are expected
to be repaid.  
The Unit 4 outage, which commenced on August 2, 2012, is expected to
be completed in late fourth quarter 2012. There are no further
outages planned at Bruce Power for the remainder of 2012. In October
2012, Bruce Power completed the refurbishment of Units 1 and 2 and
returned Unit 1 to service on October 22, 2012. Bruce Power also
synchronized Unit 2 to Ontario's electrical grid on October 16, 2012
and commercial operations for this unit are expected to commence
shortly. 


 
U.S. Power                                                                  
 
U.S. Power Comparable EBIT(1)(2)                                            
 
                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of U.S. dollars)               2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Revenues                                                                    
  Power(3)                                408       336       836       931 
  Capacity                                 75        70       181       183 
  Other(4)                                  5        11        29        54 
                                    ----------------------------------------
                                          488       417     1,046     1,168 
                                    ----------------------------------------
Commodity purchases resold               (268)     (168)     (548)     (499)
Plant operating costs and other(4)       (120)     (149)     (303)     (399)
General, administrative and support                                         
 costs                                    (13)      (10)      (34)      (29)
                                    ----------------------------------------
Comparable EBITDA(1)                       87        90       161       241 
Depreciation and amortization             (30)      (27)      (90)      (81)
                                    ----------------------------------------
Comparable EBIT(1)                         57        63        71       160 
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Refer to the Non-GAAP Measures section in this MD&A for further         
    discussion of Comparable EBITDA and Comparable EBIT.                    
(2) Certain comparative figures have been reclassified to conform with the  
    financial statement presentation adopted for the current period.        
(3) The realized gains and losses from financial derivatives used to        
    purchase and sell power, natural gas and fuel oil to manage U.S. Power's
    assets are presented on a net basis in Power Revenues.                  
(4) Includes revenues and costs related to a third-party service agreement  
    at Ravenswood, the activity level of which decreased in 2011.           
 
U.S. Power Operating Statistics                                             
 
                                     Three months ended   Nine months ended 
                                           September 30        September 30 
(unaudited)                              2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Physical Sales Volumes (GWh)                                                
Supply                                                                      
  Generation                            2,350     2,137     5,291     5,369 
  Purchased                             3,601     1,657     6,858     4,777 
                                    ----------------------------------------
                                        5,951     3,794    12,149    10,146 
                                    ----------------------------------------
                                    ----------------------------------------
 
Plant Availability(1)                      96%       96%       86%       88%
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Plant availability represents the percentage of time in a period that   
    the plant is available to generate power regardless of whether it is    
    running.                                                                

 
U.S Power's Comparable EBITDA of US$87 million and US$161 million for
the three and nine months ended September 30, 2012, respectively,
decreased US$3 million and US$80 million compared to the same periods
in 2011. The reductions were primarily due to lower realized power
prices, higher load serving costs, and reduced water flows at the
U.S. hydro facilities, partially offset by increased sales to
wholesale, commercial and industrial customers.   
Physical sales volumes for the three and nine months ended September
30, 2012 have increased compared to the same period in 2011 primarily
due to higher purchased volumes to serve increased sales to
wholesale, commercial and industrial customers in the PJM and New
England markets. Generation volumes have been negatively impacted by
reduced hydro volumes throughout 2012, however this was more than
offset by higher generation volumes from other U.S. Power facilities
in third quarter 2012.  
U.S Power's Power Revenue of US$408 million for the three months
ended September 30, 2012 increased US$72 million compared to the same
period in 2011. The increase was primarily due to higher sales
volumes to wholesale, commercial and industrial customers, partially
offset by lower realized power prices. Power Revenue of US$836
million for the nine months ended September 30, 2012 decreased US$95
million compared to the same period in 2011 primarily due to lower
realized power prices partially offset by increased sales volumes.   
Capacity Revenue of US$75 million for the three months ended
September 30, 2012 increased US$5 million compared to the same period
in 2011 due to higher realized capacity prices in New York partially
offset by lower New England capacity prices. Capacity Revenue of
US$181 million for the nine months ended September 30, 2012,
decreased US$2 million compared to the same period in 2011 as lower
capacity prices in New England more than offset higher realized
capacity prices in New York. 
Commodity Purchases Resold of US$268 million and US$548 million for
the three and nine months ended September 30, 2012, respectively,
increased US$100 million and US$49 million compared to the same
periods in 2011 due to higher volumes of physical power purchased for
resale under power sales commitments to wholesale, commercial and
industrial customers and higher load serving costs, partially offset
by lower power prices.  
Plant Operating Costs and Other, which includes fuel gas consumed in
generation, of US$120 million and US$303 million for the three and
nine months ended September 30, 2012, respectively, decreased US$29
million and US$96 million compared to the same periods in 2011
primarily due to lower natural gas fuel prices.   
As at September 30, 2012, approximately 1,200 GWh or 53 per cent and
2,700 GWh or 35 per cent of U.S. Power's planned generation is
contracted for the remainder of 2012 and for 2013, respectively.
Planned generation fluctuates depending on hydrology, wind
conditions, commodity prices and the resulting dispatch of the
assets. Power sales fluctuate based on customer usage. 
Natural Gas Storage 
Natural Gas Storage's Comparable EBITDA of $17 million for the three
months ended September 30, 2012 increased $6 million compared to the
same period in 2011 primarily due to higher realized natural gas
storage price spreads and lower operating costs. 
Natural Gas Storage's Comparable EBITDA of $47 million for the nine
months ended September 30, 2012 decreased $9 million compared to the
same period in 2011 primarily as a result of the impact of lower
realized natural gas storage price spreads in the first quarter of
2012, partially offset by lower operating costs throughout the year. 
Other Income Statement Items  


 
Comparable Interest Expense(1)                                         
 
                                Three months ended   Nine months ended 
(unaudited)                           September 30        September 30 
(millions of dollars)               2012      2011      2012      2011 
-----------------------------------------------------------------------
-----------------------------------------------------------------------
 
Interest on long-term debt(2)                                          
 Canadian dollar-denominated         130       121       385       365 
 U.S. dollar-denominated             185       187       554       549 
 Foreign exchange                      1        (4)        1       (12)
                               ----------------------------------------
                                     316       304       940       902 
 
Other interest and amortization        7         4        14        17 
Capitalized interest                 (74)      (66)     (224)     (231)
                               ----------------------------------------
Comparable Interest Expense(1)       249       242       730       688 
                               ----------------------------------------
                               ----------------------------------------
 
(1) Refer to the Non-GAAP Measures section in this MD&A for further         
    discussion of Comparable Interest Expense.                              
(2) Includes interest on Junior Subordinated Notes.                         

 
Comparable Interest Expense of $249 million and $730 million for the
three and nine months ended September 30, 2012 increased $7 million
and $42 million, respectively, compared to the same periods in 2011.
The increase in interest expense for the nine months ended September
30, 2012 reflected incremental interest on debt issues of US$1.0
billion in August 2012, US$500 million in March 2012 and $750 million
in November 2011, and a TC PipeLines, LP debt issue of US$350 million
in June 2011. These increases also reflected the negative impact of a
stronger U.S. dollar on U.S. dollar-denominated interest, and lower
capitalized interest for Keystone, Coolidge and Guadalajara as a
result of placing these assets in service, partially offset by higher
realized gains in 2012 compared to 2011 from derivatives used to
manage the Company's exposure to rising interest rates and the impact
of Canadian and U.S. dollar-denominated debt maturities in 2012 and
2011. 
Comparable Interest Income and Other of $22 million and $66 million
for the three and nine months ended September 30, 2012 increased $26
million and $14 million, respectively, compared to the same periods
in 2011. The increase for the three months ended September 30, 2012
was primarily due to gains in 2012 compared to losses in 2011 on
derivatives used to manage the Company's net exposure to foreign
exchange rate fluctuations on U.S. dollar-denominated income and on
translation of foreign denominated working capital balances. The
increase for the nine months ended September 30, 2012 was primarily
due to gains in 2012 compared to losses in 2011 on the translation of
foreign denominated working capital balances.  
Comparable Income Taxes were $123 million and $354 million in the
three and nine months ended September 30, 2012, respectively,
compared to $144 million and $470 million for the same periods in
2011. The decreases of $21 million and $116 million, respectively,
were primarily due to lower pre-tax earnings in 2012 compared to
2011. 
Liquidity and Capital Resources 
TransCanada believes that its financial position remains sound as
does its ability to generate cash in the short and long term to
provide liquidity, maintain financial capacity and flexibility, and
provide for planned growth. TransCanada's liquidity is underpinned by
cash flow from operations, available cash balances and unutilized
committed revolving bank lines of US$1
.0 billion, US$300 million,
US$1.0 billion and $2.0 billion, maturing in November 2012, February
2013, October 2013 and October 2017, respectively. These facilities
also support the Company's three commercial paper programs. In
addition, at September 30, 2012, TransCanada's proportionate share of
unutilized capacity on committed bank facilities at the Company's
operated affiliates was $90 million with maturity dates in 2016. As
at September 30, 2012, TransCanada had remaining capacity of $2.0
billion, $1.25 billion and US$2.5 billion under its equity, Canadian
debt and U.S. debt shelf prospectuses, respectively. TransCanada's
liquidity, market and other risks are discussed further in the Risk
Management and Financial Instruments section in this MD&A.  


 
Operating Activities                                                        
 
Funds Generated from Operations(1)                                          
 
                                      Three months ended   Nine months ended
(unaudited)                                 September 30        September 30
(millions of dollars)                     2012      2011      2012      2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Cash Flows                                                                  
  Funds generated from operations(1)       866       928     2,466     2,614
  Decrease in operating working                                             
   capital                                 235        80        80       145
                                    ----------------------------------------
  Net cash provided by operations        1,101     1,008     2,546     2,759
                                    ----------------------------------------
                                    ----------------------------------------
 
(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 $93 million in the three
months ended September 30, 2012 compared to the same period in 2011
primarily due to changes in working capital, partially offset by
increased funding for pension plans and lower distributions received
from equity investments. Net Cash Provided by Operations decreased
$213 million in the nine months ended September 30, 2012 compared to
the same periods in 2011 primarily due to lower earnings in addition
to the previously mentioned third quarter changes.  
As at September 30, 2012, TransCanada's current assets were $2.6
billion and current liabilities were $4.8 billion resulting in a
working capital deficiency of $2.2 billion. The Company believes this
shortfall can be managed through its ability to generate cash flow
from operations as well as its ongoing access to capital markets.  
Investing Activities  
In the three and nine months ended September 30, 2012, capital
expenditures totalled $694 million and $1,555 million, respectively
(2011- $505 million and $1,593 million, respectively) related to the
expansions of the Keystone Pipeline System and the Alberta System.
Equity investments of $144 million and $557 million for the three and
nine months ended September 30, 2012, respectively (2011 - $213
million and $451 million, respectively) were primarily related to the
Company's investment in the refurbishment and restart of Bruce Power
Units 1 and 2 which were completed in October 2012 and the West Shift
Plus life extension outage on Unit 3. 
Financing Activities 
In August 2012, the Company issued US$1.0 billion of senior notes
maturing on August 1, 2022 and bearing interest at an annual rate of
2.5 per cent. In March 2012, the Company issued US$500 million of
senior notes maturing on March 2, 2015 and bearing interest at an
annual rate of 0.875 per cent. These notes were issued under the
US$4.0 billion debt shelf prospectus filed in November 2011. The net
proceeds of these offerings were used for general corporate purposes
and to reduce short-term indebtedness. 
The Company believes it has the capacity to fund its existing capital
program through internally-generated cash flow, continued access to
capital markets and liquidity underpinned by in excess of $4 billion
of committed credit facilities. TransCanada's financial flexibility
is further bolstered by opportunities for portfolio management,
including an ongoing role for TC PipeLines, LP. 
Dividends 
On October 29, 2012, TransCanada's Board of Directors declared a
quarterly dividend of $0.44 per share for the quarter ending December
31, 2012 on the Company's outstanding common shares. The dividend is
payable on January 31, 2013 to shareholders of record at the close of
business on December 31, 2012. In addition, quarterly dividends of
$0.2875 and $0.25 per Series 1 and Series 3 preferred share,
respectively, were declared for the quarter ending December 31, 2012.
The dividends are payable on December 31, 2012 to shareholders of
record at the close of business on November 30, 2012. Furthermore, a
quarterly dividend of $0.275 per Series 5 preferred share was
declared for the period ending January 30, 2013, payable on January
30, 2013 to shareholders of record at the close of business on
December 31, 2012. 
Contractual Obligations 
There have been no material changes, except for an increase in
capital commitments of $1.4 billion, primarily related to the Gulf
Coast Project and Keystone XL Pipeline, offset by the decreases to
market-based commodity purchase commitments of approximately $1.3
billion, to TransCanada's contractual obligations from December 31,
2011 to September 30, 2012, including payments due for the next five
years and thereafter. For further information on these contractual
obligations, refer to the MD&A in TransCanada's 2011 Annual Report. 
Accounting Policies and Critical Accounting Estimates 
Effective January 1, 2012, TransCanada commenced reporting under U.S.
GAAP as permitted. Comparative figures, which were previously
presented in accordance with CGAAP, have been adjusted as necessary
to be compliant with the Company's accounting policies under U.S.
GAAP. The financial reporting impact of TransCanada adopting U.S.
GAAP is disclosed in Note 25 of TransCanada's 2011 audited
Consolidated Financial Statements included in TransCanada's 2011
Annual Report. The accounting policies and critical accounting
estimates applied are consistent with those outlined in TransCanada's
2011 Annual Report, except as described below, which outlines the
Company's significant accounting policies that have changed upon
adoption of U.S. GAAP. 
In preparing the 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. 
Changes to Accounting Policies Upon Adoption of U.S. GAAP 
Principles of Consolidation 
The condensed consolidated financial statements include the accounts
of TransCanada and its subsidiaries. The Company consolidates its
interests in entities over which it is able to exercise control. To
the extent there are interests owned by other parties, these
interests are included in Non-Controlling Interests. TransCanada uses
the equity method of accounting for joint ventures in which the
Company is able to exercise joint control and for investments in
which the Company is able to exercise significant influence.
TransCanada records its proportionate share of undivided interests in
certain assets. 
Inventories 
Inventories primarily consist of materials and supplies, including
spare parts and fuel, and natural gas inventory in storage, and are
carried at the lower of weighted average cost or market. 
Income Taxes 
The Company uses the liability method of accounting for income taxes.
This method requires the recognition of deferred income tax assets
and liabilities for future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred income tax assets and liabilities are measured using enacted
tax rates at the balance sheet date that are anticipated to apply to
taxable income in the years in which temporary differences are
expected to be recovered or settled. Changes to these balances are
recognized in income in the period during which they occur except for
changes in balances related to the Canadian Mainline, Alberta System
and Foothills, which are deferred until they are refunded or
recovered in tolls, as permitted by the NEB. 
Canadian income taxes are not provided on the unremitted earnings of
foreign investments that the Company does not intend to repatriate in
the foreseeable future. 
Employee Benefit and Other Plans 
The Company sponsors defined benefit pension plans (DB Plans),
defined contribution plans (DC Plans), a Savings Plan and other
post-retirement benefit plans. Contributions made by the Company to
the DC Plans and Savings Plan are expensed in the period in which
contributions are made. The cost of the DB Plans and other
post-retirement benefits received by employees is actuarially
determined using the projected benefit method pro-rated based on
service and management's best estimate of expected plan investment
performance, salary escalation, retirement age of employees and
expected health care costs.  
The DB Plans' assets are measured at fair value. The expected return
on the DB Plans' assets is determined using market-related values
based on a five-year moving average value for all of the DB Plans'
assets. Past service costs are amortized over the expected average
remaining service life of the employees. Adjustments arising from
plan amendments are amortized on a straight-line basis over the
average remaining service period of employees active at the date of
amendment. The Company recognizes the overfunded or underfunded
status of its DB Plans as an asset or liability on its Balance Sheet
and recognizes changes in that funded status through Other
Comprehensive Income/(Loss) (OCI) in the year in which the change
occurs. The excess of net actuarial gains or losses over 10 per cent
of the greater of the benefit obligation and the market-related value
of the DB Plans' assets, if any, is amortized out of Accumulated
Other Comprehensive Income/(Loss) (AOCI) over the average remaining
service period of the active employees. For certain regulated
operations, post-retirement benefit amounts are recoverable through
tolls as benefits are funded. The Company records any unrecognized
gains and losses or changes in actuarial assumptions related to these
post-retirement benefit plans as either regulatory assets or
liabilities which are then amortized on a straight-line basis over
the average remaining service life of active employees. When the
restructuring of a benefit plan gives rise to both a curtailment and
a settlement, the curtailment is accounted for prior to the
settlement.  
The Company has medium-term incentive plans, under which payments are
made to eligible employees. The expense related to these incentive
plans is accounted for on an accrual basis. Under these plans,
benefits vest when certain conditions are met, including the
employees' continued employment during a specified period and
achievement of specified corporate performance targets. 
Long-Term Debt Transaction Costs 
The Company records long-term debt transaction costs as deferred
assets and amortizes these costs using the effective interest method
for all costs except those related to the Canadian natural gas
regulated pipelines, which continue to be amortized on a
straight-line basis in accordance with the provisions of tolling
mechanisms. 
Guarantees 
Upon issuance, the Company records the fair value of certain
guarantees entered into by the Company on behalf of partially owned
entities for which contingent payments may be made. The fair value of
these guarantees is estimated by discounting the cash flows that
would be incurred by the Company if letters of credit were used in
place of the guarantees. Guarantees are recorded as an increase to
Equity Investments, Plant, Property and Equipment, or a charge to Net
Income, and a corresponding liability is recorded in Deferred
Amounts. 
Changes in Accounting Policies for 2012 
Fair Value Measurement 
Effective January 1, 2012, the Company adopted the Accounting
Standards Update (ASU) on fair value measurements as issued by the
Financial Accounting Standards Board (FASB). Adoption of the ASU has
resulted in an increase in the qualitative and quantitative
disclosures regarding Level III measurements. 
Intangibles - Goodwill and Other 
Effective January 1, 2012, the Company adopted the ASU on testing
goodwill for impairment as issued by the FASB. Adoption of the ASU
has resulted in a change in the accounting policy related to testing
goodwill for impairment, as the Company is now permitted under U.S.
GAAP to first assess qualitative factors affecting the fair value of
a reporting unit in comparison to the carrying amount as a basis for
determining whether it is required to proceed to the two-step
quantitative impairment test. 
Future Accounting Changes 
Balance Sheet Offsetting/Netting 
In December 2011, the FASB issued amended guidance to enhance
disclosures that will enable users of the financial statements to
evaluate the effect, or potential effect, of netting arrangements on
an entity's financial position. The amendments result in enhanced
disclosures by requiring additional information regarding financial
instruments and derivative instruments that are either offset in
accordance with current U.S. GAAP or subject to an enforceable master
netting arrangement. This guidance is effective for annual periods
beginning on or after January 1, 2013. Adoption of these amendments
is expected to result in an increase in disclosure regarding
financial instruments which are subject to offsetting as described in
this amendment. 
Financial Instruments and Risk Management 
TransCanada continues to manage and monitor its exposure to market
risk, counterparty credit risk and liquidity 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 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,
2012, there were no significant amounts past due or impaired.  
At September 30, 2012, the Company had a credit risk concentration of
$266 million due from a counterparty. This amount is expected to be
fully collectible and is secured by a guarantee from the
counterparty's parent company. 
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.  
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, 2012, the
Company had designated as a net investment hed
ge U.S.
dollar-denominated debt with a carrying value of $11.0 billion
(US$11.2 billion) and a fair value of $14.4 billion (US$14.6
billion). At September 30, 2012, $60 million (December 31, 2011 - $79
million) was included in Other Current Assets, $96 million (December
31, 2011 - $66 million) was included in Intangibles and Other Assets,
$6 million (December 31, 2011 - $15 million) was included in Accounts
Payable and $18 million (December 31, 2011 - $41 million) was
included in Deferred Amounts for the fair value of forwards and swaps
used to hedge the Company's net U.S. dollar investment in
self-sustaining foreign operations. 
Derivatives Hedging Net Investment in Self-Sustaining Foreign
Operations 
The fair values and notional principal amounts for the derivatives
designated as a net investment hedge were as follows: 


 
                                      September 30, 2012   December 31, 2011
                                    ----------------------------------------
                                    ----------------------------------------
                                                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 2012 to 2019)(2)               131   US 3,950       93   US 3,850
U.S. dollar forward foreign exchange                                        
 contracts (maturing 2012)                  1     US 100       (4)    US 725
 
                                    ----------------------------------------
                                          132   US 4,050       89   US 4,575
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Fair values equal carrying values.                                      
(2) Consolidated Net Income in the three and nine months ended September 30,
    2012 included net realized gains of $8 million and $22 million,         
    respectively (2011 - gains of $8 million and $20 million, respectively) 
    related to the interest component of cross-currency swap settlements.   

 
Non-Derivative Financial Instruments Summary 
The carrying and fair values of non-derivative financial instruments
were as follows: 


 
                                     September 30, 2012   December 31, 2011 
                                    ----------------------------------------
                                    ----------------------------------------
 (unaudited)                         Carrying      Fair  Carrying      Fair 
(millions of dollars)                Amount(1)  Value(2) Amount(1)  Value(2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Financial Assets                                                            
Cash and cash equivalents                 494       494       654       654 
Accounts receivable and other(3)        1,102     1,158     1,359     1,403 
Available-for-sale assets(3)               32        32        23        23 
                                    ----------------------------------------
                                        1,628     1,684     2,036     2,080 
                                    ----------------------------------------
                                    ----------------------------------------
 
Financial Liabilities(4)                                                    
Notes payable                           1,470     1,470     1,863     1,863 
Accounts payable and deferred                                               
 amounts(5)                             1,069     1,069     1,329     1,329 
Accrued interest                          346       346       365       365 
Long-term debt                         18,969    24,938    18,659    23,757 
Junior subordinated notes                 983     1,048     1,016     1,027 
                                    ----------------------------------------
                                       22,837    28,871    23,232    28,341 
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Recorded at amortized cost, except for US$350 million (December 31, 2011
    - US$350 million) of Long-Term Debt that is recorded at fair value. This
    debt which is recorded at fair value on a recurring basis is classified 
    in Level II of the fair value category using the income approach based  
    on interest rates from external data service providers.                 
(2) The fair value measurement of financial assets and liabilities recorded 
    at amortized cost for which the fair value is not equal to the carrying 
    value would be included in Level II of the fair value hierarchy using   
    the income approach based on interest rates from external data service  
    providers.                                                              
(3) At September 30, 2012, the Condensed Consolidated Balance Sheet included
    financial assets of $873 million (December 31, 2011 - $1.1 billion) in  
    Accounts Receivable, $39 million (December 31, 2011 - $41 million) in   
    Other Current Assets and $222 million (December 31, 2011 - $247 million)
    in Intangibles and Other Assets.                                        
(4) Consolidated Net Income in the three and nine months ended September 30,
    2012 included losses of $2 million and $14 million, respectively (2011 -
    losses of $7 million and $18 million, respectively) for fair value      
    adjustments related to interest rate swap agreements on US$350 million  
    (2011 - US$350 million) of Long-Term Debt. There were no other          
    unrealized gains or losses from fair value adjustments to the non-      
    derivative financial instruments.                                       
(5) At September 30, 2012, the Condensed Consolidated Balance Sheet included
    financial liabilities of $967 million (December 31, 2011 - $1.2 billion)
    in Accounts Payable and $102 million (December 31, 2011 - $137 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, 2012                                                          
(unaudited)                                                                 
(millions of Canadian                                                       
 dollars unless otherwise                   Natural     Foreign             
 indicated)                       Power         Gas    Exchange    Interest 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Derivative Financial                                                        
 Instruments Held for                                                       
 Trading(1)                                                                 
Fair Values(2)                                                              
 Assets                       $     168   $     107   $       7   $      16 
 Liabilities                  $    (195)  $    (126)  $     (13)  $     (16)
Notional Values                                                             
 Volumes(3)                                                                 
  Purchases                      31,717          99           -           - 
  Sales                          32,700          73           -           - 
 Canadian dollars                     -           -           -         620 
 U.S. dollars                         -           -    US 1,255      US 200 
 Cross-currency                       -           -    47/US 37           - 
 
Net unrealized                                                              
 gains/(losses) in the                                                      
 period(4)                                                                  
 Three months ended                                                         
  September 30, 2012          $       1   $      12   $      13           - 
 Nine months ended September                                                
  30, 2012                    $     (17)  $       2   $       5           - 
 
Net realized (losses)/gains                                                 
 in the period(4)                                                           
 Three months ended                                                         
  September 30, 2012          $       4   $      (4)  $       6           - 
 Nine months ended September                                                
  30, 2012                    $       8   $     (19)  $      21           - 
 
Maturity Dates                2012-2016   2012-2016   2012-2013   2013-2016 
 
Derivative Financial                                                        
 Instruments in Hedging                                                     
 Relationships(5)(6)                                                        
Fair Values(2)                                                              
 Assets                       $      85           -           -   $      13 
 Liabilities                  $    (130)  $      (6)  $     (41)          - 
Notional Values                                                             
 Volumes(3)                                                                 
  Purchases                      17,745           3           -           - 
  Sales                           7,467           -           -           - 
 U.S. dollars                         -           -       US 42      US 350 
Cross-currency                        -           -   136/US 100          - 
 
Net realized gains/(losses)                                                 
 in the period(4)                                                           
 Three months ended                                                         
  September 30, 2012          $     (49)  $      (7)          -   $       2 
 Nine months ended September                                                
  30, 2012                    $    (101)  $     (21)          -   $       5 
 
Maturity dates                2012-2018   2012-2013   2012-2014   2013-2015 
                            ------------------------------------------------
                            ------------------------------------------------
 
(1) All derivative financial instruments held for trading 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 derivative financial        
    instruments held for trading used to purchase and sell power and
    natural gas are included net in Revenues. Realized and unrealized gains
    and losses on interest rate and foreign exchange derivative financial  
    instruments held for trading are included in Interest Expense and       
    Interest Income and Other, respectively. The effective portion of       
    unrealized gains and losses on derivative financial instruments in cash 
    flow hedging relationships is initially recognized in Other             
    Comprehensive Income and reclassified to Revenues, Interest Expense and 
    Interest Income and Other, as appropriate, as the original hedged item  
    settles.                                                                
(5) All hedging relationships are designated as cash flow hedges except for 
    interest rate derivative financial instruments designated as fair value 
    hedges with a fair value of $13 million and a notional amount of US$350 
    million. Net realized gains on fair value hedges for the three and nine 
    months ended September 30, 2012 were $2 million and $6 million,         
    respectively, and were included in Interest Expense. In the three and   
    nine months ended September 30, 2012, the Company did not record any    
    amounts in Net Income related to ineffectiveness for fair value hedges. 
(6) For the three and nine months ended September 30, 2012, there were no   
    gains or losses included in Net Income for discontinued cash flow hedges
    where it was probable that the anticipated transaction would not occur. 
    No amounts have been excluded from the assessment of hedge              
    effectiveness.                                                          
 
2011                                                                        
(unaudited)                                                                 
(millions of Canadian                                                       
 dollars unless otherwise                   Natural     Foreign             
 indicated)                       Power         Gas    Exchange    Interest 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Derivative Financial                                                        
 Instruments Held for                                                       
 Trading(1)                                                                 
Fair Values(2)(3)                                                           
 Assets                       $     185   $     176           3   $      22 
 Liabilities                  $    (192)  $    (212)  $     (14)  $     (22)
Notional Values(3)                                                          
 Volumes(4)                                                                 
  Purchases                      21,905         103           -           - 
  Sales                          21,334          82           -           - 
 Canadian dollars                     -           -           -         684 
 U.S. dollars                         -           -    US 1,269      US 250 
 Cross-currency                       -           -    47/US 37           - 
 
Net unrealized                                                              
 gains/(losses) in the                                                      
 period(5)                                                                  
 Three months ended                                                         
  September 30, 2011          $       6   $     (13)  $     (41)  $       1 
 Nine months ended September                                                
  30, 2011                    $       9   $     (39)  $     (41)  $       1 
 
Net realized gains/(losses)                                                 
 in the period(5)                                                           
 Three months ended                                                         
  September 30, 2011          $      15   $     (20)  $      (7)          - 
 Nine months ended September                                                
  30, 2011                    $      20   $     (61)  $      26   $       1 
 
Maturity dates                2012-2016   2012-2016        2012   2012-2016 
 
Derivative Financial                                                        
 Instruments in Hedging                                                     
 Relationships(6)(7)                                                        
Fair Values(2)(3)                                                           
 Assets                       $      16   $       3           -   $      13 
 Liabilities                  $    (277)  $     (22)  $     (38)  $      (1)
 Notional Values(3)                                                         
 Volumes(4)                                                                 
  Purchases                      17,188           8           -           - 
  Sales                           8,061           -           -           - 
 U.S. dollars                         -           -       US 73      US 600 
Cross-currency                       -           -   136/US 100           - 
 
Net realized losses in the                                                  
 period(5)                                                                  
 Three months ended                                                         
  September 30, 2011          $     (56)  $      (6)          -   $      (4)
 Nine months ended September                                                
  30, 2011                    $    (112)  $     (14)          -   $     (13)
 
Maturity dates                2012-2017   2012-2013   2012-2014   2012-2015 
                            ------------------------------------------------
                            ------------------------------------------------
 
(1) All derivative financial instruments held for trading 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) As at December 31, 2011.                                                
(4) Volumes for power and natural gas derivatives are in GWh and Bcf,       
    respectively.                                                           
(5) Realized and unrealized gains and losses on derivative financial        
    instruments held for trading used to purchase and sell power and natural
    gas are included net in Revenues. Realized and unrealized gains and     
    losses on interest rate and foreign exchange derivative financial       
    instruments held for trading are included in Interest Expense and       
    Interest Income and Other, respectively. The effective portion of       
    unrealized gains and losses on derivative financial instruments in cash 
    flow hedging relationships is initially recognized in Other             
    Comprehensive Income and reclassified to Revenues, Interest Expense and 
    Interest Income and Other, as appropriate, as the original hedged item  
    settles.                                                                
(6) All hedging relationships are designated as cash flow hedges except for 
    interest rate derivative financial instruments designated as fair value 
    hedges with a fair value of $13 million and a notional amount of US$350 
    million at December 31, 2011. Net realized gains on fair value hedges   
    for the three and nine months ended September 30, 2011 were $1 million  
    and $5 million, respectively, and were included in Interest Expense. In 
    the three and nine months ended September 30, 2011, the Company did not 
    record any amounts in Net Income related to ineffectiveness for fair    
    value hedges.                                                           
(7) For the three and nine months ended September 30, 2011, there were no   
    gains or losses included in Net Income for discontinued cash flow hedges
    where it was probable that the anticipated transaction would not occur. 
    No amounts were 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 2012     December 31 2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Current                                                                     
Other current assets                               302                  361 
Accounts payable                                  (340)                (485)
 
Long term                                                                   
Intangibles and other assets                       250                  202 
Deferred amounts                                  (211)                (349)
                                  ------------------------------------------
                                  ------------------------------------------
 
Derivatives in Cash Flow Hedging Relationships                              
 
The components of OCI related to derivatives in cash flow hedging           
 relationships are as follows:                                              
 
                                              Cash Flow Hedges              
                                --------------------------------------------
                                --------------------------------------------
Three months ended September 30               Natural     Foreign           
(unaudited)                         Power         Gas    Exchange  Interest 
(millions of dollars, pre-tax)  2012 2011  2012  2011  2012  2011 2012 2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Changes in fair value of                                                    
 derivative instruments                                                     
 recognized in OCI (effective                                               
 portion)                         96  (25)   (3)  (14)   (5)   13    -   (1)
Reclassification of gains and                                               
 (losses) on derivative                                                     
 instruments from AOCI to Net                                               
 Income (effective portion)       54   26    15    27     -     -    4   11 
Gains on derivative instruments                                             
 recognized in earnings                                                     
 (ineffective portion)             5    1     1     1     -     -    -    - 
                                --------------------------------------------
                                --------------------------------------------
 
                                              Cash Flow Hedges              
                                --------------------------------------------
                                --------------------------------------------
Nine months ended September 30                Natural     Foreign           
(unaudited)                         Power         Gas    Exchange  Interest 
(millions of dollars, pre-tax)  2012 2011  2012  2011  2012  2011 2012 2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Changes in fair value of         
                                           
 derivative instruments                                                     
 recognized in OCI (effective                                               
 portion)                         74 (128)  (17)  (39)   (5)    6    -   (1)
Reclassification of gains on                                                
 derivative instruments from                                                
 AOCI to Net Income (effective                                              
 portion)                        129   58    43    80     -     -   14   33 
Gains on derivative instruments                                             
 recognized in earnings                                                     
 (ineffective portion)             6    2     -     -     -     -    -    - 
                                --------------------------------------------
                                --------------------------------------------

 
Derivative contracts entered into to manage market risk often contain
financial assurance provisions that allow parties to the contracts to
manage credit risk. These provisions may require collateral to be
provided if a credit-risk-related contingent event occurs, such as a
downgrade in the Company's credit rating to non-investment grade.
Based on contracts in place and market prices at September 30, 2012,
the aggregate fair value of all derivative instruments with
credit-risk-related contingent features that were in a net liability
position was $41 million (2011 - $77 million), for which the Company
had provided collateral of nil (2011 - $6 million) in the normal
course of business. If the credit-risk-related contingent features in
these agreements were triggered on September 30, 2012, the Company
would have been required to provide collateral of $41 million (2011 -
$71 million) to its counterparties. Collateral may also need to be
provided should the fair value of derivative instruments exceed
pre-defined contractual exposure limit thresholds. The Company has
sufficient liquidity in the form of cash and undrawn committed
revolving bank lines to meet these contingent obligations should they
arise.  
Fair Value Hierarchy  
The Company's assets and liabilities recorded at fair value have been
classified into three categories based on the fair value hierarchy.  
In Level I, the fair value of assets and liabilities is determined by
reference to quoted prices in active markets for identical assets and
liabilities that the Company has the ability to access at the
measurement date.  
In Level II, the fair value of interest rate and foreign exchange
derivative assets and liabilities is determined using the income
approach. The fair value of power and gas commodity assets and
liabilities is determined using the market approach. Under both
approaches, valuation is based on the extrapolation of inputs, other
than quoted prices included within Level I, for which all significant
inputs are observable directly or indirectly. Such inputs include
published exchange rates, interest rates, interest rate swap curves,
yield curves, and broker quotes from external data service providers.
Transfers between Level I and Level II would occur when there is a
change in market circumstances. There were no transfers between Level
I and Level II in the nine months ended September 30, 2012 and 2011.  
In Level III, the fair value of assets and liabilities measured on a
recurring basis is determined using a market approach based on inputs
that are unobservable and significant to the overall fair value
measurement. Assets and liabilities measured at fair value can
fluctuate between Level II and Level III depending on the proportion
of the value of the contract that extends beyond the time frame for
which inputs are considered to be observable. As contracts near
maturity and observable market data becomes available, they are
transferred out of Level III and into Level II.   
Long-dated commodity transactions in certain markets where liquidity
is low are included in Level III of the fair value hierarchy, as the
related commodity prices are not readily observable. Long-term
electricity prices are estimated using a third-party modelling tool
which takes into account physical operating characteristics of
generation facilities in the markets in which the Company operates.
Inputs into the model include market fundamentals such as fuel
prices, power supply additions and retirements, power demand,
seasonal hydro conditions and transmission constraints. Long-term
North American natural gas prices are based on a view of future
natural gas supply and demand, as well as exploration and development
costs. Long-term prices are reviewed by management and the Board on a
periodic basis. Significant decreases in fuel prices or demand for
electricity or natural gas, or increases in the supply of electricity
or natural gas may result in a lower fair value measurement of
contracts included in Level III.   
The fair value of the Company's assets and liabilities measured on a
recurring basis, including both current and non-current portions, are
categorized as follows: 


 
                                  Significant                               
                 Quoted Prices          Other    Significant                
                     in Active     Observable   Unobservable                
                       Markets         Inputs         Inputs                
                      (Level I)     (Level II)    (Level III)         Total 
                ------------------------------------------------------------
                ------------------------------------------------------------
(unaudited)                                                                 
 (millions of                                                               
 dollars, pre-  Sept 30 Dec 31 Sept 30 Dec 31 Sept 30 Dec 31 Sept 30 Dec 31 
 tax)              2012   2011    2012   2011    2012   2011    2012   2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative                                                                  
 Financial                                                                  
 Instrument                                                                 
 Assets:                                                                    
 Interest rate                                                              
  contracts           -      -      29     36       -      -      29     36 
 Foreign                                                                    
  exchange                                                                  
  contracts           -      -     160    141       -      -     160    141 
 Power commodity                                                            
  contracts           -      -     242    201       9      -     251    201 
 Gas commodity                                                              
  contracts          90    124      17     55       -      -     107    179 
Derivative                                                                  
 Financial                                                                  
 Instrument                                                                 
 Liabilities:                                                               
 Interest rate                                                              
  contracts           -      -     (16)   (23)      -      -     (16)   (23)
 Foreign                                                                    
  exchange                                                                  
  contracts           -      -     (75)  (102)      -      -     (75)  (102)
 Power commodity                                                            
  contracts           -      -    (318)  (454)     (5)   (15)   (323)  (469)
 Gas commodity                                                              
  contacts         (114)  (208)    (18)   (26)      -      -    (132)  (234)
Non-Derivative                                                              
 Financial                                                                  
 Instruments:                                                               
 Available-for-                                                             
  sale assets        32     23       -      -       -      -      32     23 
                ------------------------------------------------------------
                      8    (61)     21   (172)      4    (15)     33   (248)
                ------------------------------------------------------------
                ------------------------------------------------------------

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


 
                                               Derivatives(1)               
                                --------------------------------------------
                                --------------------------------------------
                                   Three months ended     Nine months ended 
(unaudited                               September 30          September 30 
(millions of dollars, pre-tax)        2012       2011       2012       2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Balance at beginning of period           7        (30)       (15)        (8)
New contracts                            -          -          -          1 
Settlements                              -          1         (1)         1 
Transfers out of Level III             (12)         2        (10)         2 
Total gains included in Net                                                 
 Income(2)                               7          -          8          - 
Total gains/(losses) included in                                            
 OCI                                     2         10         22        (13)
                                --------------------------------------------
Balance at end of period                 4        (17)         4        (17)
                                --------------------------------------------
                                --------------------------------------------
 
 
(1) The fair value of derivative assets and liabilities is presented on a   
    net basis.                                                              
(2) For the three and nine months ended September 31, 2012, the unrealized  
    gains or losses included in Net Income attributed to derivatives that   
    were still held at the reporting date was a loss of $1 million (2011 -  
    nil).                                                                   

 
A 10 per cent increase or decrease in commodity prices, with all
other variables held constant, would result in a $6 million decrease
or increase, respectively, in the fair value of outstanding
derivative financial instruments included in Level III as at
September 30, 2012. 
Other Risks  
Additional risks faced by the Company are discussed in the MD&A in
TransCanada's 2011 Annual Report. These risks remain substantially
unchanged since December 31, 2011.  
Controls and Procedures  
As of September 30, 2012, 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 at a
reasonable assurance level as at September 30, 2012.  
During the quarter ended September 30, 2012, there have been no
changes in TransCanada's internal controls over financial reporting
that have materially affected, or are reasonably likely to materially
affect, the Company's internal controls over financial reporting. 
Outlook  
Since the disclosure in TransCanada's 2011 Annual Report, the
Company's overall earnings outlook for 2012 will be negatively
impacted by the Sundance A PPA arbitration decision received in July
2012 which is expected to result in the Company not recording
earnings from the Sundance A PPA in 2012. In addition, reduced demand
for natural gas and electricity due to unseasonably warm winter
weather, combined with continued strong U.S. natural gas production,
has resulted in historically high natural gas storage levels and low
natural gas prices, which are having a negative impact on revenues in
U.S. Pipelines as well as power prices in Canadian and U.S. Power.
Delays in restarting the Bruce Power Units 1 and 2 as well as an
expanded planned outage at Unit 4 have also reduced the 2012 earnings
outlook. For further information on outlook, refer to the MD&A in
TransCanada's 2011 Annual Report. 
Recent Developments 
Natural Gas Pipelines 
Canadian Pipelines 
Canadian Mainline 
2012-2013 Tolls Application  
In 2011, TransCanada filed a comprehensive tolls application with the
NEB to change the business structure and the terms and conditions of
service for the Canadian Mainline and to set tolls for 2012 and 2013.
The hearing with respect to this application began on June 4, 2012
with final arguments to be heard from TransCanada and the intervenors
beginning November 13, 2012. A final decision from the NEB on the
application is not expected before late first quarter 2013.   
As part of the Canadian Mainline hearing, TransCanada filed an
updated throughput forecast for 2013 through 2020. Based on natural
gas prices being lower by approximately US$1.40 per million BTUs in
2010 dollars on an annual average basis compared to the previous
forecast, the Western Mainline Receipts are expected to be lower, on
average, by approximately one billion cubic feet (Bcf) per day over
the forecasted period. 
Marcellus Facilities Expansion  
In May 2012, TransCanada received NEB approval with respect to an
application that was re-filed in November 2011 to construct new
pipeline infrastructure to provide Southern Ontario with additional
natural gas supply from the Marcellus shale basin. Construction
continues on the new pipeline facilities and it is expected that the
Marcellus shale gas supply will begin moving to market as of November
1, 2012. 
Mainline New Capacity Open Season  
In response to requests for capacity to bring additional Marcellus
shale gas volumes into Canada, TransCanada held a new capacity open
season that closed in May 2012 for firm transportation service on the
integrated Canadian Mainline from Niagara and Chippawa as well as
from other receipt points to all delivery points, including points
east of Parkway. As a result of revised project timelines for the
approval and construction of the necessary facilities, TransCanada is
in the process of amending the Precedent Agreements resulting from
the open season to reflect a revised contract in-service date of
November 2015. The ultimate facilities requirements associated with
the Precedent Agreements are still being assessed. 
Alberta System 
Expansion Projects  
In the first three quarters of 2012, TransCanada continued to expand
its Alberta System by completing and placing in service 12 separate
pipeline projects at a total cost of approximately $680 million. This
included the completion of the approximate $250 million Horn River
project in May 2012 that extended the Alberta System into the Horn
River shale play in British Columbia.  
The NEB has approved additional Alberta System expansions totaling
approximately $630 million, including the Leismer-Kettle River
Crossover project, a 30 inch, 77 kilometre (km) pipeline which was
approved in June 2012. This project has an estimated construction
cost of $162 million and is intended to provide increased capacity to
meet demand in Northeast Alberta. Approximately $340 million of
projects are still awaiting NEB approval, including the Komie North
project which would extend the Alberta System further into the Horn
River area.  
NGL Extraction Convention  
In October 2012, the Alberta System withdrew its NEB application to
implement the NGL Extraction Convention (NEXT) extraction rights
model. Business circumstances have significantly changed since the
model was developed that could negatively impact gas production. As a
result, the application to implement the model was withdrawn. 
Coastal GasLink Pipeline Project  
TransCanada has been selected by Shell Canada Limited (Shell) and its
partners to design, build, own and operate the proposed Coastal
GasLink Pipeline Project, an estimated $4 billion pipeline that will
transport natural gas from the Montney gas-producing region near
Dawson Creek, British Columbia (B.C.) to the recently announced LNG
Canada liquefied natural gas (LNG) export facility near Kitimat, B.C.
The LNG Canada project is a joint venture led by Shell, with partners
Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company
Limited. The approximately 700 km pipeline is expected to have an
initial capacity of more than 1.7 Bcf/d and be placed in service
toward the end of the decade. A proposed contractual extension of the
Alberta System using capacity on the Coastal GasLink pipeline, to a
point near Vanderhoof, B.C., will allow TransCanada to also offer gas
transmission service to interconnecting natural gas pipelines serving
the West Coast. TransCanada expects to elicit interest in and
commitments for such service through an open season process in early
2013 subject to the overall project schedule. 
U.S. Pipelines 
Northern Border  
Northern Border filed with the Federal Energy Regulatory Commission
(FERC) a settlement with its customers to modify its transportation
rates beginning in January 2013. If approved by the FERC, the
settlement will result in an 11 per cent reduction in rates relative
to current rates, includes a three-year moratorium on filing rate
cases or challenging the settlement rates and requires Northern
Border to file for new rates no later than January 1, 2018. Although
Northern Border's revenues will decrease beginning in January 2013,
the settlement provides rate certainty for up to five years. Northern
Border is 50 per cent owned by TC PipeLines LP and TransCanada owns
33 per cent of the TC PipeLines LP units. 
ANR  
The FERC issued an Order in June 2012 approving the sale of the
offshore assets by ANR to its affiliate TC Offshore LLC, a newly
created wholly-owned subsidiary of ANR, and allowing TC Offshore LLC
to operate these assets as a standalone interstate pipeline. The FERC
issued two orders in September 2012 that facilitate the commercial
start up of TC Offshore as a new interstate natural gas pipeline
entity comprised of ANR's offshore assets and authorized the tariff
services and rate structure for this new entity. TC Offshore LLC is
expected to begin commercial operations on November 1, 2012. 
Alaska Pipeline Project  
The Alaska North Slope producers (ExxonMobil, ConocoPhillips and BP),
along with TransCanada through its participation in the Alaska
Pipeline Project, have agreed on a work plan aimed at commercializing
North Slope natural gas resources via an LNG option. In May 2012,
TransCanada received approval from the State of Alaska to curtail its
activities on the Alaska/Alberta route and focus on the LNG
alternative, thereby allowing TransCanada to defer its obligation to
file for a FERC certificate for the Alberta route beyond the original
fall 2012 deadline. TransCanada held an open season in September 2012
to solicit interest in the LNG option and the project received a
number of non-binding expressions of interest from potential shippers
from a broad range of industry sectors located in North America and
Asia. 
Mackenzie Gas Project  
Project activities have been curtailed largely due to natural gas
market conditions. TransCanada's future funding obligations for the
Aboriginal Pipeline Group during such curtailment are expected to be
nominal. 
Oil Pipelines 
Keystone Pipeline System  
In May 2012, TransCanada filed revised fixed tolls for the Cushing
Extension section of the Keystone Pipeline System with both the NEB
and the FERC. The revised tolls, which reflect the final project
costs of the Keystone Pipeline System, became effective July 1, 2012. 
Gulf Coast Project  
The Company announced in February 2012 that what had previously been
the Cushing to U.S. Gulf Coast portion of the Keystone XL Project has
its own independent value to the marketplace and will be constructed
as the stand-alone Gulf Coast Project, which is not part of the
Presidential Permit process. The 36-inch pipeline, which will extend
from Cushing, Oklahoma to the U.S. Gulf Coast, is expected to have an
initial capacity of up to 700,000 barrels per day (bbl/d) with an
ultimate capacity of 830,000 bbl/d. TransCanada started construction
in August 2012 and expects to place the Gulf Coast Project in service
in late 2013. As of September 30, 2012, US$0.9 billion has been
invested in the project. Included in the US$2.3 billion cost is
US$300 million for the 76 km (47 mile) Houston Lateral pipeline that
will transport crude oil to Houston refineries. 
Keystone XL Pipeline  
In May 2012, TransCanada filed a Presidential Permit application
(cross border permit) with the U.S. Department of State (DOS) for the
Keystone XL Pipeline from the U.S./Canada border in Montana to Steele
City, Nebraska. TransCanada will supplement that application with an
alternative route in Nebraska as soon as that route is selected.  
The Company continues to work collaboratively with the Nebraska
Department of Environmental Quality (NDEQ) to finalize an alternative
route that avoids the Nebraska Sandhills. A proposed route submitted
by TransCanada in April 2012 has been modified in response to
comments received from the NDEQ and the public. In September 2012,
the Company submitted a Supplemental Environmental Report (SER) to
the NDEQ for the preferred alternative route. The NDEQ has indicated
that it will complete its review by the end of 2012. In addition to
submitting a SER to the NDEQ, TransCanada has provided an
environmental report to the DOS. The environmental report is required
as part of the DOS review of the Company's Presidential Permit
application.  
The approximate cost of the 36-inch line is US$5.3 billion and,
subject to regulatory approvals, TransCanada expects the Keystone XL
Pipeline to be in service in late 2014 or early 2015. As of September
30, 2012, US$1.6 billion has been invested in this project. 
Keystone Hardisty Terminal  
In May 2012, TransCanada announced that it had secured binding
long-term commitments exceeding 500,000 bbl/d for the Keystone
Hardisty Terminal. As a result of strong commercial support for the
project, the Company has expanded the proposed two million barrel
project to a 2.6 million barrel terminal located at Hardisty,
Alberta. The Keystone Hardisty Terminal Project will provide new
crude oil batch accumulation tankage and pipeline infrastructure for
Western Canadian producers and access to the Keystone Pipeline
System. The project is expected to be operational in late 2014 and
cost approximately $275 million. 
Northern Courier Pipeline  
In August 2012, TransCanada announced that it had been selected by
Fort Hills Energy Limited Partnership to design, build, own and
operate the proposed Northern Courier Pipeline Project. The project,
with an estimated capital cost of $660 million, is a 90 km (54 mile)
pipeline system that will transport bitumen and diluent between the
Fort Hills mine site and the Voyageur Upgrader located north of Fort
McMurray, Alberta.  
Northern Courier Pipeline is fully subscribed under long-term
contracts to service the Fort Hills Mine, which is jointly owned by
Suncor Energy Inc, Total E&P Canada Ltd. and Teck Resources Limited
and is operated by Suncor Energy Operating Inc. The Northern Courier
Pipeline Project is conditional on and subject to the Fort Hills
project receiving sanction by its co-owners and obtaining regulatory
approval. TransCanada expects to file its initial regulatory
application in early 2013. 
Grand Rapids  
In October, TransCanada announced that it has entered into binding
agreements with Phoenix Energy Holdings Limited (Phoenix)to develop
the Grand Rapids Pipelines project in Northern Alberta. TransCanada
and Phoenix will each own 50 per cent of the proposed $3 billion
pipeline project that includes both a crude oil and a diluent line to
transport volumes approximately 500 km (300 miles) between the
producing area northwest of Fort McMurray and the Edmonton/ Heartland
region. The Grand Rapids Pipeline system is expected to be in service
by early 2017, subject to regulatory approvals, and will have the
capacity to move up to 900,000 bbl/d of crude oil and 330,000 bbl/d
of diluent. TransCanada will operate the system and Phoenix has
entered a long-term commitment to ship crude oil and diluent on the
system.  
Canadian Mainline Conversion  
TransCanada has determined a conversion of a portion of the Canadian
Mainline natural gas pipeline system to crude oil service is both
technically and economically feasible. Through a combination of
converted natural gas pipeline and new construction, the proposed
pipeline would deliver crude oil between Hardisty, Alberta and
markets in Eastern Canada. The Company has begun soliciting input
from stakeholders and prospective shippers to determine market
acceptance of the proposed project. 
Energy 
Bruce Power 
In October 2012, Bruce Power completed the refurbishment of Unit 1
and returned this unit to service on October 22, 2012. Bruce Power
also synchronized Unit 2 to Ontario's electrical grid on October 16,
2012 and commercial operations for this unit are expected to commence
shortly. Units 1 and 2 are expected to produce clean and reliable
power for the province of Ontario until at least 2037. Following the
return to service of both Units 1 and 2, Bruce Power will be capable
of producing 6,200 megawatts (MW) of emission-free power. 
The return to service of Units 1 and 2 had been delayed as a result
of a May 2012 incident which occurred within the Unit 2 electrical
generator on the non-nuclear side of the plant. Bruce Power's force
majeure claim related to this incident was accepted by the OPA and
Bruce Power continues to receive the contracted price for power
generated at Bruce A.  
In August 2012, Bruce Power continued to invest in its strategy to
maximize the lives of its reactors by commencing an expanded outage
investment program on Unit 4 in support of extending the life of the
unit. The Unit 4 outage, expected to conclude in late fourth quarter
2012, will align the lifespan of Unit 4 to that of Unit 3. In June
2012, Bruce Power returned Unit 3 to service after completing the
West Shift Plus life extension outage which commenced in November
2011 at a cost of approximately $300 million. This investment is
expected to allow Unit 3 to produce low cost electricity until at
least 2021. 
Sundance A  
In December 2010, Sundance Units 1 and 2 were withdrawn from service
and were subject to a force majeure claim by TransAlta Corporation
(TransAlta) in January 2011. In February 2011, TransAlta notified
TransCanada that it had determined it was uneconomic to repair Units
1 and 2 and that the Sundance A PPA should therefore be terminated.
TransCanada disputed both the force majeure and economic destruction
claims under the binding dispute resolution process provided in the
PPA. The binding arbitration proceedings concluded during second
quarter 2012 and a decision was received in July 2012. The
arbitration panel determined that the PPA should not be terminated
and ordered TransAlta to rebuild Units 1 and 2. The panel also
limited TransAlta's force majeure claim from November 20, 2011 until
such time that the units can reasonably be returned to service.
According to the terms of the arbitration decision, TransAlta has an
obligation under the PPA to exercise all reasonable efforts to
mitigate or limit the effects of the force majeure. TransAlta
announced that it expects the units to be returned to service in the
fall of 2013.  
The impact of this decision was recorded in the results for second
quarter 2012. TransCanada had recorded $188 million of EBITDA from
the commencement of the outages in December 2010 to the end of March
2012 as it considered the outages to be an interruption of supply. As
a result of the decision, the Company realized $138 million of this
amount. The difference of $50 million was recorded as a charge to
second quarter 2012 earnings. The net book value of the Sundance A
PPA recorded in Intangibles and Other Assets remains fully
recoverable. TransCanada will not realize revenues from the Sundance
A PPA until the units return to service. 
Ravenswood  
In 2011, TransCanada and other parties jointly filed two formal
complaints with the FERC regarding the manner in which the New York
Independent System Operator (NYISO) has applied pricing rules for two
new power plants that have recently begun service in the New York
Zone J market. In June 2012, the FERC addressed the first complaint
and indicated it will take steps to increase transparency and
accountability with regard to future Mitigation Exemption Test (MET)
decisions which determine whether a new facility is exempt from
offering its capacity at a floor price.  
In September 2012, the FERC granted an order on the second complaint.
The FERC directed the NYISO to retest the two new facilities, making
changes to several parameters that form the basis of the MET
calculations. Based on the changes the FERC has ordered, the
recalculation could result in one or both entrants having to offer
their capacity at a floor price which TransCanada anticipates will
result in higher capacity auction prices in the future. The order is
prospective and will not impact capacity prices for prior periods. 
Ontario Solar  
In late 2011, TransCanada agreed to purchase nine Ontario solar
projects from Canadian Solar Solutions Inc., with a combined capacity
of 86 megawatts, for approximately $470 million. Under the terms of
the agreement, each of the nine solar projects will be developed and
constructed by Canadian Solar Solutions Inc. using photovoltaic
panels. TransCanada will purchase each project once construction and
acceptance testing have been completed and operations have begun
under 20-year PPAs with the OPA under the Feed-In Tariff program in
Ontario. TransCanada expects the acquisitions of these two projects
to occur in early 2013 once acceptance testing has been completed.
TransCanada anticipates the remaining projects will be placed in
service and acquired in 2013 and 2014, subject to regulatory
approvals. 
Napanee Generating Station  
In September 2012, TransCanada, the Government of Ontario, the OPA
and Ontario Power Generation announced that two Memorandums of
Understanding (MOU) were executed authorizing TransCanada to develop,
construct, own and operate a new 900 MW facility at Ontario Power
Generation's Lennox site in Eastern Ontario in the town of Greater
Napanee. The Napanee Generating Station would act as a replacement
facility for one that was planned and subsequently cancelled in the
community of Oakville. Under the terms of the MOUs, TransCanada will
be reimbursed for approximately $250 million of verifiable costs,
primarily for natural gas turbines at Oakville which will be deployed
at Napanee. The Company will further invest approximately $1.0
billion in the replacement Napanee facility. Definitive contracts are
expected to be executed by mid-December and include a 20-year Clean
Energy Supply contract. 
Cartier Wind  
The 111 MW second phase of Gros-Morne is expected to be operational
in November 2012. This will complete construction of the 590 MW
Cartier Wind project in Quebec. All of the power produced by Cartier
Wind is sold under 20-year PPAs to Hydro-Quebec. 
Becancour  
In June 2012, Hydro-Quebec notified TransCanada it would exercise its
option to extend the agreement to suspend all electricity generation
from the Becancour power plant throughout 2013. Under the terms of
the suspension agreement, Hydro-Quebec has the option, subject to
certain conditions, to extend the suspension on an annual basis until
such time as regional electricity demand levels recover. TransCanada
will continue to receive capacity payments under the agreement
similar to those that would have been received under the normal
course of operation while energy production and payments are
suspended. 
Share Information  
At October 25, 2012, TransCanada had 705 million issued and
outstanding common shares, and had 22 million Series 1, 14 million
Series 3 and 14 million Series 5 issued and outstanding first
preferred shares that are convertible to 22 million Series 2, 14
million Series 4 and 14 million Series 6 preferred shares,
respectively. In addition, there were eight million outstanding
options to purchase common shares, of which five million were
exercisable as at October 25, 2012.  
Selected Quarterly Consolidated Financial Data(1)(2) 


 
                                2012                   2011             2010
                         ------------------ ------------------------- ------
(millions of dollars,                                                       
 except per share                                                           
 amounts)                Third Second First Fourth Third Second First Fourth
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Revenues                 2,126  1,847 1,945  2,015 2,043  1,851 1,930  1,743
Net income attributable                                                     
 to controlling                                                             
 interests                 382    286   366    390   399    367   425    277
 
Share Statistics                                                            
Net Income per common                                                       
 share                                                                      
  Basic                  $0.52  $0.39 $0.50  $0.53 $0.55  $0.50 $0.59  $0.38
  Diluted                $0.52  $0.39 $0.50  $0.53 $0.55  $0.50 $0.59  $0.37
 
Dividend declared per                                                       
 common share            $0.44  $0.44 $0.44  $0.42 $0.42  $0.42 $0.42  $0.40
                         ---------------------------------------------------
                         ---------------------------------------------------
 
(1) The selected quarterly consolidated financial data has been prepared in 
    accordance with U.S. GAAP and is presented in Canadian dollars.         
(2) Certain comparative figures have been reclassified to conform with the  
    financial statement presentation adopted for the current period.        

 
Factors Affecting Quarterly Financial Information  
In Natural Gas Pipelines, which consists primarily of the Company's
investments in regulated natural gas 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 Oil Pipelines, which consists of the Company's investment in the
Keystone Pipeline System, earnings are primarily generated by
contractual arrangements for committed capacity that are not
dependent on actual throughput. Quarter-over-quarter revenues, EBIT
and net income during any particular fiscal year remain relatively
stable with fluctuations resulting from planned and unplanned
outages, and changes in the amount of spot volumes transported and
the associated rate charged. Spot volumes transported are affected by
customer demand, market pricing, planned and unplanned outages of
refineries, terminals and pipeline facilities, and developments
outside of the normal course of operations.  
In Energy, which consists primarily of the Company's investments in
electrical power generation plants and non-regulated natural gas
storage facilities, quarter-over-quarter revenues, EBIT and net
income are affected by seasonal weather conditions, customer demand,
market prices, hydrology, capacity prices, planned and unplanned
plant outages, acquisitions and divestitures, certain fair value
adjustments and developments outside of the normal course of
operations.  
Significant developments that affected the last eight quarters' EBIT
and Net Income are as follows: 


 
--  Third Quarter 2012, EBIT included net unrealized gains of $31 million
    pre-tax ($20 million after tax) from certain risk management activities.
 
--  Second Quarter 2012, EBIT included a $50 million pre-tax ($37 million
    after tax) charge from the Sundance A PPA arbitration decision and net
    unrealized losses of $14 million pre-tax ($13 million after tax) from
    certain risk management activities. 
 
--  First Quarter 2012, EBIT included net unrealized losses of $22 million
    pre-tax ($11 million after tax) from certain risk management activities.
 
--  Fourth Quarter 2011, EBIT included net unrealized gains of $13 million
    pre-tax ($11 million after tax) resulting from certain risk management
    activities. 
 
--  Third Quarter 2011, Energy's EBIT included the positive impact of higher
    prices for Western Power. EBIT included net unrealized losses of $43
    million pre-tax ($30 million after tax) resulting from certain risk
    management activities. 
 
--  Second Quarter 2011, Natural Gas Pipelines' EBIT included incremental
    earnings from Guadalajara, which was placed in service in June 2011.
    Energy's EBIT included incremental earnings from Coolidge, which was
    placed in service in May 2011. EBIT included net unrealized losses of $3
    million pre-tax ($2 million after tax) resulting from certain risk
    management activities. 
 
--  First Quarter 2011, Natural Gas Pipelines' EBIT included incremental
    earnings from Bison, which was placed in service in January 2011. Oil
    Pipelines began recording EBIT for the Wood River/Patoka and Cushing
    Extension sections of the Keystone Pipeline System in February 2011.
    EBIT included net unrealized losses of $19 million pre-tax ($12 million
    after tax) resulting from certain risk management activities. 
 
--  Fourth Quarter 2010, Natural Gas Pipelines' EBIT decreased as a result
    of recording a $146 million pre-tax ($127 million after tax) valuation
    provision for advances to the Aboriginal Pipeline Group for the
    Mackenzie Gas Project. Energy's EBIT included contributions from the
    second phase of Kibby Wind, which was placed in service in October 2010,
    and net unrealized gains of $46 million pre-tax ($29 million after tax)
    resulting from certain risk management activities. 
 

 
Condensed Consolidated Statement of Income                                  
 
                                      Three months ended  Nine months ended 
(unaudited)                                 September 30       September 30 
(millions of Canadian dollars except                                        
 per share amounts)                      2012       2011     2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Revenues                                                                    
Natural Gas Pipelines                   1,058      1,036    3,177     3,107 
Oil Pipelines                             259        229      769       575 
Energy                                    809        778    1,972     2,142 
                                    ----------------------------------------
                                        2,126      2,043    5,918     5,824 
 
Income from Equity Investments             71        127      196       328 
 
Operating and Other Expenses                                                
Plant operating costs and other           758        717    2,192     1,973 
Commodity purchases resold                337        271      758       782 
Depreciation and amortization             342        337    1,032       987 
                                    ----------------------------------------
                                        1,437      1,325    3,982     3,742 
                                    ----------------------------------------
 
Financial Charges/(Income)                                                  
Interest expense                          249        240      730       686 
Interest income and other                 (34)        43      (70)      (12)
                                    ----------------------------------------
                                          215        283      660       674 
                                    ----------------------------------------
 
Income before Income Taxes                545        562    1,472     1,736 
                                    ----------------------------------------
 
Income Taxes Expense                                                        
Current                                     6         49      101       197 
Deferred                                  128         82      247       252 
                                    ----------------------------------------
                                          134        131      348       449 
                                    ----------------------------------------
 
Net Income                                411        431    1,124     1,287 
 
Net Income Attributable to Non-                                             
 Controlling Interests                     29         32       90        96 
                                    ----------------------------------------
Net Income Attributable to                                                  
 Controlling Interests                    382        399    1,034     1,191 
Preferred Share Dividends                  13         13       41        41 
                                    ----------------------------------------
Net Income Attributable to Common                                           
 Shares                                   369        386      993     1,150 
                                    ----------------------------------------
                                    ----------------------------------------
 
Net Income per Common Share                                                 
Basic and Diluted                       $0.52      $0.55    $1.41     $1.64 
                                    ----------------------------------------
                                    ----------------------------------------
 
Dividends Declared per Common Share     $0.44      $0.42    $1.32     $1.26 
                                    ----------------------------------------
                                    ----------------------------------------
 
Weighted Average Number of Common                                           
 Shares (millions)                                                          
Basic                                     705        703      704       701 
Diluted                                   706        704      705       702 
                                    ----------------------------------------
                                    ----------------------------------------
 
See accompanying notes to the condensed consolidated financial statements.  
 
Condensed Consolidated Statement of Comprehensive Income                    
 
                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of Canadian dollars)           2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Net Income                                411       431     1,124     1,287 
                                    ----------------------------------------
Other Comprehensive Income/(Loss),                                          
 Net of Income Taxes                                                        
Change in foreign currency                                                  
 translation gains and losses on                                            
 investments in foreign                                                     
 operations(1)                           (196)      416      (189)      262 
Change in fair value of derivative                                          
 instruments to hedge the net                                               
 investments in foreign                                                     
 operations(2)                             99      (213)       76      (141)
Change in fair value of derivative                                          
 instruments designated as cash flow                                        
 hedges(3)                                 60       (18)       43      (113)
Reclassification to Net Income of                                           
 losses on derivative instruments                                           
 designated as cash flow hedges(4)         47        44       119       114 
Reclassification to Net Income of                                           
 actuarial losses and prior service                                         
 costs on pension and other post-                                           
 retirement benefit plans(5)                4         2        18         7 
Other Comprehensive (Loss)/Income of                                        
 Equity Investments(6)                     (3)        1        (1)        1 
                                    ----------------------------------------
Other Comprehensive Income                 11       232        66       130 
                                    ----------------------------------------
 
Comprehensive Income                      422       663     1,190     1,417 
 
Comprehensive (Loss)/Income                                                 
 Attributable to Non-Controlling                                            
 Interests                                 (5)      104        59       150 
                                    ----------------------------------------
Comprehensive Income Attributable to                                        
 Controlling Interests                    427       559     1,131     1,267 
Preferred Share Dividends                  13        13        41        41 
                                    ----------------------------------------
Comprehensive Income Attributable to                                        
 Common Shares                            414       546     1,090     1,226 
                                    ----------------------------------------
                                    ----------------------------------------
 

 
(1) Net of income tax expense of $51 million and $48 million for the three  
    and nine months ended September 30, 2012, respectively (2011 - recovery 
    of $97 million and $57 million, respectively).                          
(2) Net of income tax expense of $34 million and $26 million for the three  
    and nine months ended September 30, 2012, respectively (2011 - recovery 
    of $78 million and $51 million, respectively).                          
(3) Net of income tax expense of $28 million and $9 million for the three   
    and nine months ended September 30, 2012, respectively (2011 - recovery 
    of $9 million and $49 million, respectively).                           
(4) Net of income tax expense of $26 million and $67 million for the three  
    and nine months ended September 30, 2012, respectively (2011 - expense  
    of $20 million and $57 million, respectively).                          
(5) Net of income tax expense of $2 million and recovery of $1 million for  
    the three and nine months ended September 30, 2012, respectively (2011 -
    expense of $1 million and $3 million, respectively).                    
(6) Primarily related to reclassification to Net Income of actuarial losses 
    on pension and other post-retirement benefit plans, gains and losses on 
    derivative instruments designated as cash flow hedges, offset by change 
    in gains and losses on derivative instruments designated as cash flow   
    hedges, net of income tax recovery of $1 million and nil for the three  
    and nine months ended September 30, 2012, respectively (2011 - recovery 
    of $2 million and expense of $3 million, respectively).                 
 
See accompanying notes to the condensed consolidated financial statements.  
 
Condensed Consolidated Statement of Cash Flows                              
 
                                     Three months ended   Nine months ended 
(unaudited)                                September 30        September 30 
(millions of Canadian dollars)           2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Cash Generated from Operations                                              
Net income                                411       431     1,124     1,287 
Depreciation and amortization             342       337     1,032       987 
Deferred income taxes                     128        82       247       252 
Income from equity investments            (71)     (127)     (196)     (328)
Distributions received from equity                                          
 investments                               95       127       252       307 
Employee future benefits expense                                            
 (less than)/in excess of funding         (23)        6       (11)        4 
Other                                     (16)       72        18       105 
Decrease in operating working                                               
 capital                                  235        80        80       145 
                                    ----------------------------------------
Net cash provided by operations         1,101     1,008     2,546     2,759 
                                    ----------------------------------------
 
Investing Activities                                                        
Capital expenditures                     (694)     (505)   (1,555)   (1,593)
Equity investments                       (144)     (213)     (557)     (451)
Deferred amounts and other                 40        93        82       133 
                                    ----------------------------------------
Net cash used in investing                                                  
 activities                              (798)     (625)   (2,030)   (1,911)
                                    ----------------------------------------
 
Financing Activities                                                        
Dividends on common and preferred                                           
 shares                                  (322)     (308)     (956)     (706)
Distributions paid to non-                                                  
 controlling interests                    (33)      (33)     (101)      (87)
Notes payable (repaid)/issued, net       (930)      154      (341)     (257)
Long-term debt issued, net of issue                                         
 costs                                    995        54     1,488       573 
Reduction of long-term debt               (12)     (206)     (782)     (946)
Common shares issued                       17        14        35        39 
Partnership units of subsidiary                                             
 issued, net of costs                       -         -         -       321 
                                    ----------------------------------------
Net cash used in financing                                                  
 activities                              (285)     (325)     (657)   (1,063)
                                    ----------------------------------------
 
Effect of Foreign Exchange Rate                                             
 Changes on Cash and Cash                                                   
 Equivalents                              (14)       27       (19)       12 
                                    ----------------------------------------
 
 
Increase/(Decrease) in Cash and Cash                                        
 Equivalents                                4        85      (160)     (203)
                                    ----------------------------------------
 
Cash and Cash Equivalents                                                   
Beginning of period                       490       372       654       660 
                                    ----------------------------------------
 
Cash and Cash Equivalents                                                   
End of period                             494       457       494       457 
                                    ----------------------------------------
                                    ----------------------------------------
 
See accompanying notes to the condensed consolidated financial statements.  
 
Condensed Consolidated Balance Sheet                                        
 
(unaudited)                                      September 30   December 31 
(millions of Canadian dollars)                           2012          2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
ASSETS                                                                      
Current Assets                                                              
Cash and cash equivalents                                 494           654 
Accounts receivable                                       873         1,094 
Inventories                                               214           248 
Other                                                     973         1,114 
                                                ----------------------------
                                                        2,554         3,110 
Plant, Property and Equipment, net of                                       
 accumulated depreciation of $16,259 and                                    
 $15,406, respectively                                 32,379        32,467 
Equity Investments                                      5,520         5,077 
Goodwill                                                3,419         3,534 
Regulatory Assets                                       1,629         1,684 
Intangibles and Other Assets                            1,440         1,466 
                                                ----------------------------
                                                       46,941        47,338 
                                                ----------------------------
                                                ----------------------------
 
LIABILITIES                                                                 
Current Liabilities                                                         
Notes payable                                           1,470         1,863 
Accounts payable                                        1,877         2,359 
Accrued interest                                          346           365 
Current portion of long-term debt                       1,070           935 
                                                ----------------------------
                                                        4,763         5,522 
Regulatory Liabilities                                    321           297 
Deferred Amounts                                          706           929 
Deferred Income Tax Liabilities                         3,858         3,591 
Long-Term Debt                                         17,899        17,724 
Junior Subordinated Notes                                 983         1,016 
                                                ----------------------------
                                                       28,530        29,079 
EQUITY                                                                      
Common shares, no par value                            12,049        12,011 
Issued and outstanding: September 30, 2012 - 705                            
 million shares                                                             
December 31, 2011 - 704 million shares                                      
Preferred shares                                        1,224         1,224 
Additional paid-in capital                                380           380 
Retained earnings                                       4,691         4,628 
Accumulated other comprehensive loss                   (1,352)       (1,449)
                                                ----------------------------
Controlling Interests                                  16,992        16,794 
Non-controlling interests                               1,419         1,465 
                                                ----------------------------
Equity                                                 18,411        18,259 
                                                ----------------------------
                                                       46,941        47,338 
                                                ----------------------------
                                                ----------------------------
 
Contingencies and Guarantees (Note 8)                                       
 
 
See accompanying notes to the condensed consolidated financial statements.  
 
Condensed Consolidated Statement of Accumulated Other Comprehensive         
(Loss)/Income                                                               
 
                                                      Pension and           
                                                      Other Post-           
                                Currency Cash Flow     retirement           
(unaudited)(millions of      Translation    Hedges           Plan           
 Canadian dollars)           Adjustments and Other    Adjustments     Total 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at December 31, 2011        (643)     (281)          (525)   (1,449)
Change in foreign currency                                                  
 translation gains and                                                      
 losses on investments in                                                   
 foreign operations(1)              (158)        -              -      (158)
Change in fair value of                                                     
 derivative instruments to                                                  
 hedge net investments in                                                   
 foreign operations(2)                76         -              -        76 
Change in fair value of                                                     
 derivative instruments                                                     
 designated as cash flow                                                    
 hedges(3)                             -        43              -        43 
Reclassification to Net                                                     
 Income of losses on                                                        
 derivative instruments                                                     
 designated as cash flow                                                    
 hedges pertaining to prior                                                 
 periods(4)(5)                         -       119              -       119 
Reclassification of                                                         
 actuarial losses and prior                                                 
 service costs on pension                                                   
 and other post-retirement                                                  
 benefit plans(6)                      -         -             18        18 
Other Comprehensive                                                         
 (Loss)/Income of Equity                                                    
 Investments (7)                       -       (12)            11        (1)
                            ------------------------------------------------
Balance at September 30,                                                    
 2012                               (725)     (131)          (496)   (1,352)
                            ------------------------------------------------
                            ------------------------------------------------
 
                                                      Pension and           
                                                      Other Post-           
                                Currency Cash Flow     retirement           
(unaudited)(millions of      Translation    Hedges           Plan           
 Canadian dollars)           Adjustments and Other    Adjustments     Total 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at December 31, 2010        (683)     (194)          (366)   (1,243)
Change in foreign currency                                                  
 translation gains and                                                      
 losses on investments in                                                   
 foreign operations(1)               216         -              -       216 
Change in fair value of                                                     
 derivative instruments to                                                  
 hedge net investments in                                                   
 foreign operations(2)              (141)        -              -      (141)
Change in fair value of                                                     
 derivative instruments                                                     
 designated as cash flow                                                    
 hedges(3)                             -      (113)             -      (113)
Reclassification to Net                                                     
 Income of losses on                                                        
 derivative instruments                                                     
 designated as cash flow                                                    
 hedges(4)(5)                          -       106              -       106 
Reclassification of                                                         
 actuarial losses and prior                                                 
 service costs on pension                                                   
 and other post-retirement                                                  
 benefit plans(6)                      -         -              7         7 
Other Comprehensive                                                         
 (Loss)/Income of Equity                                                    
 Investments (7)                       -        (7)             8         1 
                            ------------------------------------------------
Balance at September 30,                                                    
 2011                               (608)     (208)          (351)   (1,167)
                            ------------------------------------------------
                            ------------------------------------------------
 
(1) Net of income tax expense of $48 million and non-controlling interest   
    losses of $31 million for the nine months ended September 30, 2012 (2011
    - recovery of $57 million; gain of $46 million).                        
(2) Net of income tax expense of $26 million for the nine months ended      
    September 30, 2012 (2011 - recovery of $51 million).                    
(3) Net of income tax expense of $9 million for the nine months ended       
    September 30, 2012 (2011 - recovery of $49 million).                    
(4) Net of income tax expense of $67 million and non-controlling interest   
    losses of nil for the nine months ended September 30, 2012 (2011 -      
    expense of $57 million; gain of $8 million).                            
(5) Losses related to cash flow hedges reported in AOCI and expected to be  
    reclassified to Net Income in the next 12 months are estimated to be $56
    million ($31 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.                                
(6) Net of income tax recovery of $1 million for the nine months ended      
    September 30, 2012 (2011 - expense of $3 million).                      
(7) Primarily related to reclassification to Net Income of actuarial losses 
    on pension and other post-retirement benefit plans, reclassification to 
    Net Income of gains and losses on derivative instruments designated as  
    cash flow hedges, partially offset by changes in gains and losses on    
    derivative instruments designated as cash flow hedges, net of income tax
    expense of nil for the nine months ended September 30, 2012
    (2011 - nil).
 
See accompanying notes to the condensed consolidated financial statements.  
 
Condensed Consolidated Statement of Equity                                  
 
                                                          Nine months ended 
(unaudited)                                                    September 30 
(millions of Canadian dollars)                           2012          2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Common Shares                                                               
Balance at beginning of period                         12,011        11,745 
Shares issued under dividend reinvestment plan              -           202 
Shares issued on exercise of stock options                 38            40 
                                                ----------------------------
Balance at end of period                               12,049        11,987 
                                                ----------------------------
 
Preferred Shares                                                            
Balance at beginning and end of period                  1,224         1,224 
                                                ----------------------------
 
Additional Paid-In Capital                                                  
Balance at beginning of period                            380           349 
Issuance of stock options, net of exercises                 -             1 
Dilution gain from TC PipeLines, LP units issued            -            30 
                                                ----------------------------
Balance at end of period                                  380           380 
                                                ----------------------------
 
Retained Earnings                                                           
Balance at beginning of period                          4,628         4,273 
Net income attributable to controlling interests        1,034         1,191 
Common share dividends                                   (930)         (884)
Preferred share dividends                                 (41)          (41)
                                                ----------------------------
Balance at end of period                                4,691         4,539 
                                                ----------------------------
 
Accumulated Other Comprehensive Loss                                        
Balance at beginning of period                         (1,449)       (1,243)
Other comprehensive income                                 97            76 
                                                ----------------------------
Balance at end of period                               (1,352)       (1,167)
                                                ----------------------------
 
Equity Attributable to Controlling Interests           16,992        16,963 
                                                ----------------------------
 
Equity Attributable to Non-Controlling Interests                            
Balance at beginning of period                          1,465         1,157 
Net income attributable to non-controlling                                  
 interests                                                 90            96 
Other comprehensive (loss)/income attributable                              
 to non-controlling interests                             (31)           54 
Sale of TC PipeLines, LP units                                              
  Proceeds, net of issue costs                              -           321 
  Decrease in TransCanada's ownership                       -           (50)
Distributions to non-controlling interests               (101)          (95)
Other                                                      (4)           13 
                                                ----------------------------
Balance at end of period                                1,419         1,496 
                                                ----------------------------
 
Total Equity                                           18,411        18,459 
                                                ----------------------------
                                                ----------------------------
 
See accompanying notes to the condensed consolidated financial statements.  

 
Notes to Condensed Consolidated Financial Statements 
(Unaudited) 
1. Basis of Presentation 
These condensed consolidated financial statements of TransCanada
Corporation (TransCanada or the Company) have been prepared by
management in accordance with United States generally accepted
accounting principles (U.S. GAAP). Comparative figures, which were
previously presented in accordance with Canadian generally accepted
accounting principles as defined in Part V of the Canadian Institute
of Chartered Accountants Handbook (CGAAP), have been adjusted as
necessary to be compliant with the Company's accounting policies
under U.S. GAAP. The amounts adjusted for U.S. GAAP presented in
these condensed consolidated financial statements for the three and
nine months ended September 30, 2011 are the same as those that have
been previously reported in the Company's September 30, 2011
Reconciliation to U.S. GAAP. The amounts adjusted for U.S. GAAP at
December 31, 2011 are the same as those reported in Note 25 of
TransCanada's 2011 audited Consolidated Financial Statements included
in TransCanada's 2011 Annual Report. The accounting policies and
critical accounting estimates applied are consistent with those
outlined in TransCanada's 2011 Annual Report, except as described in
Note 2, which outlines the Company's significant accounting policies
that have changed upon adoption of U.S. GAAP. Capitalized and
abbreviated terms that are used but not otherwise defined herein are
identified in the Glossary of Terms contained in TransCanada's 2011
Annual Report.  
These condensed consolidated financial statements reflect
adjustments, all of which are normal recurring adjustments that are,
in the opinion of management, necessary to reflect the financial
position and results of operations for the respective periods. These
condensed consolidated financial statements do not include all
disclosures required in the annual financial statements and should be
read in conjunction with the 2011 audited Consolidated Financial
Statements included in TransCanada's 2011 Annual Report. Certain
comparative figures have been reclassified to conform with the
financial statement presentation adopted for the current period. 
Earnings for interim periods may not be indicative of results for the
fiscal year in the Company's Natural Gas Pipeline segment due to
seasonal fluctuations in short-term throughput volumes on U.S.
pipelines. Earnings for interim periods may also not be indicative of
results for the fiscal year in the Company's Energy segment due to
the impact of seasonal weather conditions on customer demand and
market pricing in certain of the Company's investments in electrical
power generation plants and non-regulated gas storage facilities. 
Use of Estimates and Judgements  
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 condensed consolidated financial
statements have been properly prepared within reasonable limits of
materiality and within the framework of the Company's accounting
policies. 
2. Changes in Accounting Policies  
Changes to Accounting Policies Upon Adoption of U.S. GAAP 
Principles of Consolidation  
The condensed consolidated financial statements include the accounts
of TransCanada and its subsidiaries. The Company consolidates its
interests in entities over which it is able to exercise control. To
the extent there are interests owned by other parties, these
interests are included in Non-Controlling Interests. TransCanada uses
the equity method of accounting for joint ventures in which the
Company is able to exercise joint control and for investments in
which the Company is able to exercise significant influence.
TransCanada records its proportionate share of undivided interests in
certain assets. 
Inventories  
Inventories primarily consist of materials and supplies, including
spare parts and fuel, and natural gas inventory in storage, and are
carried at the lower of weighted average cost or market. 
Income Taxes  
The Company uses the liability method of accounting for income taxes.
This method requires the recognition of deferred income tax assets
and liabilities for future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred income tax assets and liabilities are measured using enacted
tax rates at the balance sheet date that are anticipated to apply to
taxable income in the years in which temporary differences are
expected to be recovered or settled. Changes to these balances are
recognized in income in the period during which they occur except for
changes in balances related to the Canadian Mainline, Alberta System
and Foothills, which are deferred until they are refunded or
recovered in tolls, as permitted by the NEB.  
Canadian income taxes are not provided on the unremitted earnings of
foreign investments that the Company does not intend to repatriate in
the foreseeable future. 
Employee Benefit and Other Plans  
The Company sponsors defined benefit pension plans (DB Plans),
defined contribution plans (DC Plans), a Savings Plan and other
post-retirement benefit plans. Contributions made by the Company to
the DC Plans and Savings Plan are expensed in the period in which
contributions are made. The cost of the DB Plans and other
post-retirement benefits received by employees is actuarially
determined using the projected benefit method pro-rated based on
service and management's best estimate of expected plan investment
performance, salary escalation, retirement age of employees and
expected health care costs.   
The DB Plans' assets are measured at fair value. The expected return
on the DB Plans' assets is determined using market-related values
based on a five-year moving average value for all of the DB Plans'
assets. Past service costs are amortized over the expected average
remaining service life of the employees. Adjustments arising from
plan amendments are amortized on a straight-line basis over the
average remaining service period of employees active at the date of
amendment. The Company recognizes the overfunded or underfunded
status of its DB Plans as an asset or liability on its Balance Sheet
and recognizes changes in that funded status through Other
Comprehensive Income/(Loss) (OCI) in the year in which the change
occurs. The excess of net actuarial gains or losses over 10 per cent
of the greater of the benefit obligation and the market-related value
of the DB Plans' assets, if any, is amortized out of Accumulated
Other Comprehensive Income/(Loss) (AOCI) over the average remaining
service period of the active employees. For certain regulated
operations, post-retirement benefit amounts are recoverable through
tolls as benefits are funded. The Company records any unrecognized
gains and losses or changes in actuarial assumptions related to these
post-retirement benefit plans as either regulatory assets or
liabilities. The regulatory assets or liabilities are amortized on a
straight-line basis over the average remaining service life of active
employees. When the restructuring of a benefit plan gives rise to
both a curtailment and a settlement, the curtailment is accounted for
prior to the settlement.   
The Company has medium-term incentive plans, under which payments are
made to eligible employees. The expense related to these incentive
plans is accounted for on an accrual basis. Under these plans,
benefits vest when certain conditions are met, including the
employees' continued employment during a specified period and
achievement of specified corporate performance targets. 
Long-Term Debt Transaction Costs  
The Company records long-term debt transaction costs as deferred
assets and amortizes these costs using the effective interest method
for all costs except those related to the Canadian natural gas
regulated pipelines, which continue to be amortized on a
straight-line basis in accordance with the provisions of tolling
mechanisms. 
Guarantees 
Upon issuance, the Company records the fair value of certain
guarantees entered into by the Company on behalf of partially owned
entities for which contingent payments may be made. The fair value of
these guarantees is estimated by discounting the cash flows that
would be incurred by the Company if letters of credit were used in
place of the guarantees. Guarantees are recorded as an increase to
Equity Investments, Plant, Property and Equipment, or a charge to Net
Income, and a corresponding liability is recorded in Deferred
Amounts. 
Changes in Accounting Policies for 2012 
Fair Value Measurement  
Effective January 1, 2012, the Company adopted the Accounting
Standards Update (ASU) on fair value measurements as issued by the
Financial Accounting Standards Board (FASB). Adoption of the ASU has
resulted in an increase in the qualitative and quantitative
disclosures regarding Level III measurements. 
Intangibles - Goodwill and Other  
Effective January 1, 2012, the Company adopted the ASU on testing
goodwill for impairment as issued by the FASB. Adoption of the ASU
has resulted in a change in the accounting policy related to testing
goodwill for impairment, as the Company is now permitted under U.S.
GAAP to first assess qualitative factors affecting the fair value of
a reporting unit in comparison to the carrying amount as a basis for
determining whether it is required to proceed to the two-step
quantitative impairment test. 
Future Accounting Changes 
Balance Sheet Offsetting/Netting  
In December 2011, the FASB issued amended guidance to enhance
disclosures that will enable users of the financial statements to
evaluate the effect, or potential effect, of netting arrangements on
an entity's financial position. The amendments result in enhanced
disclosures by requiring additional information regarding financial
instruments and derivative instruments that are either offset in
accordance with current U.S. GAAP or subject to an enforceable master
netting arrangement. This guidance is effective for annual periods
beginning on or after January 1, 2013. Adoption of these amendments
is expected to result in an increase in disclosure regarding
financial instruments which are subject to offsetting as described in
this amendment. 


 
3.  Segmented Information 
 
Three months                                                                
 ended                                                                      
September 30                                                                
(unaudited)                                                                 
(millions of   Natural Gas         Oil                                      
 Canadian        Pipelines   Pipelines      Energy Corporate          Total 
 dollars)      2012   2011  2012  2011  2012  2011 2012 2011    2012   2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Revenues      1,058  1,036   259   229   809   778    -    -   2,126  2,043 
Income from                                                                 
 equity                                                                     
 investments     37     39     -     -    34    88    -    -      71    127 
Plant                                                                       
 operating                                                                  
 costs and                                                                  
 other         (435)  (376)  (82)  (73) (220) (250) (21) (18)   (758)  (717)
Commodity                                                                   
 purchases                                                                  
 resold           -      -     -     -  (337) (271)   -    -    (337)  (271)
Depreciation                                                                
 and                                                                        
 amortization  (231)  (231)  (37)  (38)  (70)  (65)  (4)  (3)   (342)  (337)
             ---------------------------------------------------------------
                429    468   140   118   216   280  (25) (21)    760    845 
             -------------------------------------------------              
             -------------------------------------------------              
Interest                                                                    
 expense                                                        (249)  (240)
Interest                                                                    
 income and                                                                 
 other                                                            34    (43)
                                                              --------------
Income before                                                               
 Income Taxes                                                    545    562 
Income taxes                                                                
 expense                                                        (134)  (131)
                                                              --------------
Net Income                                                       411    431 
Net Income Attributable to Non-Controlling Interests             (29)   (32)
                                                              --------------
Net Income Attributable to Controlling Interests                 382    399 
Preferred                                                                   
 Share                                                                      
 Dividends                                                       (13)   (13)
                                                              --------------
Net Income Attributable to Common Shares                         369    386 
                                                              --------------
                                                              --------------
Nine months                                                                 
 ended                                                                      
September 30                                                                
(unaudited)                                                                 
(millions of   Natural Gas       Oil                                        
 Canadian        Pipelines Pipelines(1)     Energy Corporate          Total 
 dollars)      2012   2011  2012  2011  2012  2011 2012 2011    2012   2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Revenues      3,177  3,107   769   575 1,972 2,142    -    -   5,918  5,824 
Income from                                                                 
 equity                                                                     
 investments    120    117     -     -    76   211    -    -     196    328 
Plant                                                                       
 operating                                                                  
 costs and                                                                  
 other       (1,246)(1,064) (243) (167) (638) (685) (65) (57) (2,192)(1,973)
Commodity                                                                   
 purchases                                                                  
 resold           -      -     -     -  (758) (782)   -    -    (758)  (782)
Depreciation                                                                
 and                                                                        
 amortization  (697)  (688) (109)  (95) (215) (194) (11) (10) (1,032)  (987)
             ---------------------------------------------------------------
              1,354  1,472   417   313   437   692  (76) (67)  2,132  2,410 
             -------------------------------------------------              
             -------------------------------------------------              
Interest                                                                    
 expense                                                        (730)  (686)
Interest                                                                    
 income and                                                                 
 other                                                            70     12 
                                                              --------------
Income before                                                               
 Income Taxes                                                  1,472  1,736 
Income taxes                                                                
 expense                                                        (348)  (449)
                                                              --------------
Net Income                                                     1,124  1,287 
Net Income Attributable to Non-Controlling Interests             (90)   (96)
                                                              --------------
Net Income Attributable to Controlling Interests               1,034  1,191 
Preferred                                                                   
 Share                                                                      
 Dividends                                                       (41)   (41)
                                                              --------------
Net Income Attributable to Common Shares                         993  1,150 
                                                              --------------
                                                              --------------
 
(1) Commencing in February 2011, TransCanada began recording earnings       
    related to the Wood River/Patoka and Cushing Extension sections of      
    Keystone.                                                               
 
Total Assets                                                                
 
(unaudited)                                     September 30,   December 31,
(millions of Canadian dollars)                           2012           2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Natural Gas Pipelines                                  22,862         23,161
Oil Pipelines                                           9,628          9,440
Energy                                                 13,223         13,269
Corporate                                               1,228          1,468
                                              ------------------------------
                                                       46,941         47,338
                                              ------------------------------
                                              ------------------------------

 
4. Income Taxes 
At September 30, 2012, the total unrecognized tax benefit of
uncertain tax positions was approximately $50 million (December 31,
2011 - $52 million). TransCanada recognizes interest and penalties
related to income tax uncertainties in income tax expense. Included
in net tax expense for the three and nine months ended September 30,
2012 is a reversal of interest expense of $2 million and $1 million,
respectively, and nil for penalties (2011 - reversal of interest
expense of $11 million and $13 million, respectively, and nil for
penalties). At September 30, 2012, the Company had $6 million accrued
for interest expense and nil accrued for penalties (December 31, 2011
- $7 million accrued for interest expense and nil accrued for
penalties).  
The effective tax rates for the nine-month periods ended September
30, 2012 and 2011 were 23.6 per cent and 25.9 per cent, respectively.
The lower effective tax rate in 2012 was a result of a reduction in
the Canadian statutory tax rate, and changes in the proportion of
income earned between Canadian and foreign jurisdictions.  
TransCanada expects the enactment of certain Canadian Federal tax
legislation in the next twelve months which is expected to result in
a favourable income tax adjustment of approximately $25 million.
Otherwise, subject to the results of audit examinations by taxation
authorities and other legislative amendments, TransCanada does not
anticipate further adjustments to the unrecognized tax benefits
during the next twelve months that would have a material impact on
its financial statements. 
5. Long-Term Debt 
In the three and nine months ended September 30, 2012, the Company
capitalized interest related to capital projects of $74 million and
$224 million, respectively (2011 - $66 million and $231 million,
respectively). 
In January 2012, TransCanada PipeLine USA Ltd. repaid the remaining
principal of US$500 million on its five-year term loan.  
In March 2012, TransCanada PipeLines Limited (TCPL) issued US$500
million of 0.875 per cent senior notes due in 2015.  
In May 2012, TCPL retired US$200 million of 8.625 per cent senior
notes.  
In August 2012, TCPL issued US$1.0 billion of 2.5 per cent senior
notes due in 2022. 
6. Employee Post-Retirement Benefits  
The net benefit plan expense for the Company's defined benefit
pension plans and other post-retirement benefit plans is as follows:  


 
                           Three months ended   Nine months ended September 
                              September 30                   30             
                       -----------------------------------------------------
                       -----------------------------------------------------
                                     Other Post-                Other Post- 
                                      retirement                 retirement 
                             Pension     Benefit       Pension      Benefit 
(unaudited)            Benefit Plans       Plans Benefit Plans        Plans 
(millions of Canadian                                                       
 dollars)                2012   2011  2012  2011   2012   2011  2012   2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Service cost               16     14     1     -     49     41     2      1 
Interest cost              24     23     2     2     71     68     6      6 
Expected return on plan                                                     
 assets                   (28)   (29)    -     -    (85)   (85)   (1)    (1)
Amortization of                                                             
 actuarial loss             5      3     -     -     14      8     1      1 
Amortization of past                                                        
 service cost               -      -     -     -      1      1     -      - 
Amortization of                                                             
 regulatory asset           5      3     -     -     15     10     -      - 
Amortization of                                                             
 transitional                                                               
 obligation related to                                                      
 regulated business         -      -     1     -      -      -     2      1 
                       -----------------------------------------------------
Net Benefit Cost                                                            
 Recognized                22     14     4     2     65     43    10      8 
                       -----------------------------------------------------
                       -----------------------------------------------------

 
7. Financial Instruments and Risk Management  
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 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,
2012, there were no significant amounts past due or impaired.  
At September 30, 2012, the Company had a credit risk concentration of
$266 million due from a counterparty. This amount is expected to be
fully collectible and is secured by a guarantee from the
counterparty's parent company.  
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.  
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, 2012, the
Company had designated as a net investment hedge U.S.
dollar-denominated debt with a carrying value of $11.0 billion
(US$11.2 billion) and a fair value of $14.4 billion (US$14.6
billion). At September 30, 2012, $60 million (December 31, 2011 - $79
million) was included in Other Current Assets, $96 million (December
31, 2011 - $66 million) was included in Intangibles and Other Assets,
$6 million (December 31, 2011 - $15 million) was included in Accounts
Payable and $18 million (December 31, 2011 - $41 million) was
included in Deferred Amounts for the fair value of forwards and swaps
used to hedge the Company's net U.S. dollar investment in
self-sustaining foreign operations. 
Derivatives Hedging Net Investment in Self-Sustaining Foreign
Operations  
The fair values and notional principal amounts for the derivatives
designated as a net investment hedge were as follows: 


 
                                     September 30, 2012    December 31, 2011
                                  ------------------------------------------
                                  ------------------------------------------
Asset/(Liability)                           Notional or          Notional or
(unaudited)                           Fair    Principal    Fair    Principal
(millions of dollars)              Value(1)      Amount Value(1)      Amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
U.S. dollar cross-currency swaps                                            
(maturing 2012 to 2019)(2)             131     US 3,950      93     US 3,850
U.S. dollar forward foreign                                                 
 exchange contracts                                                         
(maturing 2012)                          1       US 100      (4)      US 725
 
                                  ------------------------------------------
                                       132     US 4,050      89     US 4,575
                                  ------------------------------------------
                                  ------------------------------------------
 
(1) Fair values equal carrying values.                                      
(2) Consolidated Net Income in the three and nine months ended September 30,
    2012 included net realized gains of $8 million and $22 million,         
    respectively (2011 - gains of $8 million and $20 million, respectively) 
    related to the interest component of cross-currency swap settlements.   

 
Non-Derivative Financial Instruments Summary 
The carrying and fair values of non-derivative financial instruments
were as follows: 


 
                                     September 30, 2012   December 31, 2011 
                                    ----------------------------------------
                                    ----------------------------------------
(unaudited)                          Carrying      Fair  Carrying      Fair 
(millions of dollars)                Amount(1)  Value(2) Amount(1)  Value(2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Financial Assets                                                            
Cash and cash equivalents                 494       494       654       654 
Accounts receivable and other(3)        1,102     1,158     1,359     1,403 
Available-for-sale assets(3)               32        32        23        23 
                                    ----------------------------------------
                                        1,628     1,684     2,036     2,080 
                                    ----------------------------------------
                                    ----------------------------------------
 
Financial Liabilities(4)                                                    
Notes payable                           1,470     1,470     1,863     1,863 
Accounts payable and deferred                                               
 amounts(5)                             1,069     1,069     1,329     1,329 
Accrued interest                          346       346       365       365 
Long-term debt                         18,969    24,938    18,659    23,757 
Junior subordinated notes                 983     1,048     1,016     1,027 
                                    ----------------------------------------
                                       22,837    28,871    23,232    28,341 
                                    ----------------------------------------
                                    ----------------------------------------
 
(1) Recorded at amortized cost, except for US$350 million (December 31, 2011
    - US$350 million) of Long-Term Debt that is recorded at fair value. This
    debt which is recorded at fair value on a recurring basis is classified 
    in Level II of the fair value category using the income approach based  
    on interest rates from external data service providers.                 
(2) The fair value measurement of financial assets and liabilities recorded 
    at amortized cost for which the fair value is not equal to the carrying 
    value would be included in Level II of the fair value hierarchy using   
    the income approach based on interest rates from external data service  
    providers.                                                              
(3) At September 30, 2012, the Condensed Consolidated Balance Sheet included
    financial assets of $873 million (December 31, 2011 - $1.1 billion) in  
    Accounts Receivable, $39 million (December 31, 2011 - $41 million) in   
    Other Current Assets and $222 million (December 31, 2011 - $247 million)
    in Intangibles and Other Assets.                                        
(4) Consolidated Net Income in the three and nine months ended September 30,
    2012 included losses of $2 million and $14 million, respectively (2011 -
    losses of $7 million and $18 million, respectively) for fair value      
    adjustments related to interest rate swap agreements on US$350 million  
    (2011 - US$350 million) of Long-Term Debt. There were no other          
    unrealized gains or losses from fair value adjustments to the non-      
    derivative financial instruments.                                       
(5) At September 30, 2012, the Condensed Consolidated Balance Sheet included
    financial liabilities of $967 million (December 31, 2011 - $1.2 billion)
    in Accounts Payable and $102 million (December 31, 2011 - $137 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, 2012                                                          
(unaudited)                                                                 
(millions of Canadian dollars                 Natural    Foreign            
 unless otherwise indicated)         Power        Gas   Exchange   Interest 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Derivative Financial Instruments                                            
 Held for Trading(1)                                                        
Fair Values(2)                                                              
  Assets                          $    168   $    107   $      7   $     16 
  Liabilities                     $   (195)  $   (126)  $    (13)  $    (16)
Notional Values                                                             
  Volumes(3)                                                                
    Purchases                       31,717         99          -          - 
    Sales                           32,700         73          -          - 
  Canadian dollars                       -          -          -        620 
  U.S. dollars                           -          -   US 1,255     US 200 
  Cross-currency                         -          -   47/US 37          - 
 
Net unrealized gains/(losses) in                                            
 the period(4)                                                              
  Three months ended September                                              
   30, 2012                       $      1   $     12   $     13          - 
  Nine months ended September                                               
   30, 2012                       $    (17)  $      2   $      5          - 
 
Net realized (losses)/gains in                                              
 the period(4)                                                              
  Three months ended September                                              
   30, 2012                       $      4   $     (4)  $      6          - 
  Nine months ended September                                               
   30, 2012                       $      8   $    (19)  $     21          - 
 
Maturity dates                   2012-2016  2012-2016  2012-2013  2013-2016 
 
Derivative Financial Instruments                                            
 in Hedging Relationships(5)(6)                                             
Fair Values(2)                                                              
  Assets                          $     85          -          -   $     13 
  Liabilities                     $   (130)  $     (6)  $    (41)         - 
Notional Values                                                             
  Volumes(3)                                                                
    Purchases                       17,745          3          -          - 
    Sales                            7,467          -          -          - 
  U.S. dollars                           -          -      US 42     US 350 
  Cross-currency                         -          - 136/US 100          - 
 
Net realized gains/(losses) in                                              
 the period(4)                                                              
  Three months ended September                                              
   30, 2012                       $    (49)  $     (7)         -   $      2 
  Nine months ended September                                               
   30, 2012                       $   (101)  $    (21)         -   $      5 
 
Maturity dates                   2012-2018  2012-2013  2012-2014  2013-2015 
                                --------------------------------------------
                                --------------------------------------------
 
(1) All derivative financial instruments held for trading 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 derivative financial        
    instruments held for trading used to purchase and sell power and natural
    gas are included net in Revenues. Realized and unrealized gains and     
    losses on interest rate and foreign exchange derivative financial       
    instruments held for trading are included in Interest Expense and       
    Interest Income and Other, respectively. The effective portion of       
    unrealized gains and losses on derivative financial instruments in cash 
    flow hedging relationships is initially recognized in Other             
    Comprehensive Income and reclassified to Revenues, Interest Expense and 
    Interest Income and Other, as appropriate, as the original hedged item  
    settles.                                                                
(5) All hedging relationships are designated as cash flow hedges except for 
    interest rate derivative financial instruments designated as fair value 
    hedges with a fair value of $13 million and a notional amount of US$350 
    million. Net realized gains on fair value hedges for the three and nine 
    months ended September 30, 2012 were $2 million and $6 million,         
    respectively, and were included in Interest Expense. In the three and   
    nine months ended September 30, 2012, the Company did not record any    
    amounts in Net Income related to ineffectiveness for fair value hedges. 
(6) For the three and nine months ended September 30, 2012, there were no   
    gains or losses included in Net Income for discontinued cash flow hedges
    where it was probable that the anticipated transaction would not occur. 
    No amounts have been excluded from the assessment of hedge              
    effectiveness.                                                          
 
2011                                                                        
(unaudited)                                                                 
(millions of Canadian dollars                 Natural    Foreign            
 unless otherwise indicated)         Power        Gas   Exchange   Interest 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Derivative Financial Instruments                                            
 Held for Trading(1)                                                        
Fair Values(2)(3)                                                           
  Assets                          $    185   $    176          3   $     22 
  Liabilities                     $   (192)  $   (212)  $    (14)  $    (22)
Notional Values(3)                                                          
  Volumes(4)                                                                
    Purchases                       21,905        103          -          - 
    Sales                           21,334         82          -          - 
  Canadian dollars                       -          -          -        684 
  U.S. dollars                           -          -   US 1,269     US 250 
  Cross-currency                         -          -   47/US 37          - 
 
Net unrealized gains/(losses) in                                            
 the period(5)                                                              
  Three months ended September                                              
   30, 2011                       $      6   $    (13)  $    (41)  $      1 
  Nine months ended September                                               
   30, 2011                       $      9   $    (39)  $    (41)  $      1 
 
Net realized gains/(losses) in                                              
 the period(5)                                                              
  Three months ended September                                              
   30, 2011                       $     15   $    (20)  $     (7)         - 
  Nine months ended September                                               
   30, 2011                       $     20   $    (61)  $     26   $      1 
 
Maturity dates                   2012-2016  2012-2016       2012  2012-2016 
 
Derivative Financial Instruments                                            
 in Hedging Relationships(6)(7)                                             
Fair Values(2)(3)                                                           
  Assets                          $     16   $      3          -   $     13 
  Liabilities                     $   (277)  $    (22)  $    (38)  $     (1)
Notional Values(3)                                                          
  Volumes(4)                                                                
    Purchases                       17,188          8          -          - 
    Sales                            8,061          -          -          - 
  U.S. dollars                           -          -      US 73     US 600 
  Cross-currency                         -          - 136/US 100          - 
 
Net realized losses in the                                                  
 period(5)                                                                  
  Three months ended September                                              
   30, 2011                       $    (56)  $     (6)         -   $     (4)
  Nine months ended September                                               
   30, 2011                       $   (112)  $    (14)         -   $    (13)
 
Maturity dates                   2012-2017  2012-2013  2012-2014  2012-2015 
                                --------------------------------------------
                                --------------------------------------------
 
(1) All derivative financial instruments held for trading 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) As at December 31, 2011.                                                
(4) Volumes for power and natural gas derivatives are in GWh and Bcf,       
    respectively.                                                           
(5) Realized and unrealized gains and losses on derivative financial        
    instruments held for trading used to purchase and sell power and natural
    gas are included net in Revenues. Realized and unrealized gains and     
    losses on interest rate and foreign exchange derivative financial       
    instruments held for trading are included in Interest Expense and       
    Interest Income and Other, respectively. The effective portion of       
    unrealized gains and losses on derivative financial instruments in cash 
    flow hedging relationships is initially recognized in Other             
    Comprehensive Income and reclassified to Revenues, Interest Expense and 
    Interest Income and Other, as appropriate, as the original hedged item  
    settles.                                                                
(6) All hedging relationships are designated as cash flow hedges except for 
    interest rate derivative financial instruments designated as fair value 
    hedges with a fair value of $13 million and a notional amount of US$350 
    million at December 31, 2011. Net realized gains on fair value hedges   
    for the three and nine months ended September 30, 2011 were $1 million  
    and $5 million, respectively, and were included in Interest Expense. In 
    the three and nine months ended September 30, 2011, the Company did not 
    record any amounts in Net Income related to ineffectiveness for fair    
    value hedges.                                                           
(7) For the three and nine months ended September 30, 2011, there were no   
    gains or losses included in Net Income for discontinued cash flow hedges
    where it was probable that the anticipated transaction would not occur. 
    No amounts were 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)                                     September 30    December 31 
(millions of dollars)                                   2012           2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Current                                                                     
Other current assets                                     302            361 
Accounts payable                                        (340)          (485)
 
Long term                                                                   
Intangibles and other assets                             250            202 
Deferred amounts                                        (211)          (349)
                                              ------------------------------
                                              ------------------------------

 
Derivatives in Cash Flow Hedging Relationships 
The components of OCI related to derivatives in cash flow hedging
relationships are as follows:  


 
                                            Cash Flow Hedges                
                            ------------------------------------------------
                            ------------------------------------------------
Three months ended September 30                                             
(unaudited)                                              Foreign            
(millions of dollars, pre-        Power Natural Gas     Exchange   Interest 
 tax)                         2012 2011  2012  2011  2012   2011  2012 2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Changes in fair value of                                                    
 derivative instruments                                                     
 recognized in OCI                                                          
 (effective portion)            96  (25)   (3)  (14)   (5)    13     -   (1)
Reclassification of gains                                                   
 and (losses) on derivative                                                 
 instruments from AOCI to                                                   
 Net Income (effective                                                      
 portion)                       54   26    15    27     -      -     4   11 
Gains on derivative                                                         
 instruments recognized in                                                  
 earnings (ineffective                                                      
 portion)                        5    1     1     1     -      -     -    - 
                            ------------------------------------------------
                            ------------------------------------------------
 
                                            Cash Flow Hedges                
                            ------------------------------------------------
                            ------------------------------------------------
Nine months ended September 30                                              
 (unaudited)                                             Foreign            
(millions of dollars, pre-        Power Natural Gas     Exchange   Interest 
 tax)                         2012 2011  2012  2011  2012   2011  2012 2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Changes in fair value of                                                    
 derivative instruments                                                     
 recognized in OCI                                                          
 (effective portion)            74 (128)  (17)  (39)   (5)     6     -   (1)
Reclassification of gains on                                                
 derivative instruments from                                                
 AOCI to Net Income                                                         
 (effective portion)           129   58    43    80     -      -    14   33 
Gains on derivative                                                         
 instruments recognized in                                                  
 earnings (ineffective                                                      
 portion)                        6    2     -     -     -      -     -    - 
                            ------------------------------------------------
                            ------------------------------------------------

 
Derivative contracts entered into to manage market risk often contain
financial assurance provisions that allow parties to the contracts to
manage credit risk. These provisions may require collateral to be
provided if a credit-risk-related contingent event occurs, such as a
downgrade in the Company's credit rating to non-investment grade.
Based on contracts in place and market prices at September 30, 2012,
the aggregate fair value of all derivative instruments with
credit-risk-related contingent features that were in a net liability
position was $41 million (2011 - $77 million), for which the Company
had provided collateral of nil (2011 - $6 million) in the normal
course of business. If the credit-risk-related contingent features in
these agreements were triggered on September 30, 2012, the Company
would have been required to provide collateral of $41 million (2011 -
$71 million) to its counterparties. Collateral may also need to be
provided should the fair value of derivative instruments exceed
pre-defined contractual exposure limit thresholds. The Company has
sufficient liquidity in the form of cash and undrawn committed
revolving bank lines to meet these contingent obligations should they
arise.  
Fair Value Hierarchy 
The Company's assets and liabilities recorded at fair value have been
classified into three categories based on the fair value hierarchy.  
In Level I, the fair value of assets and liabilities is determined by
reference to quoted prices in active markets for identical assets and
liabilities that the Company has the ability to access at the
measurement date.  
In Level II, the fair value of interest rate and foreign exchange
derivative assets and liabilities is determined using the income
approach. The fair value of power and gas commodity assets and
liabilities is determined using the market approach. Under both
approaches, valuation is based on the extrapolation of inputs, other
than quoted prices included within Level I, for which all significant
inputs are observable directly or indirectly. Such inputs include
published exchange rates, interest rates, interest rate swap curves,
yield curves, and broker quotes from external data service providers.
Transfers between Level I and Level II would occur when there is a
change in market circumstances. There were no transfers between Level
I and Level II in the nine months ended September 30, 2012 and 2011.  
In Level III, the fair value of assets and liabilities measured on a
recurring basis is determined using a market approach based on inputs
that are unobservable and significant to the overall fair value
measurement. Assets and liabilities measured at fair value can
fluctuate between Level II and Level III depending on the proportion
of the value of the contract that extends beyond the time frame for
which inputs are considered to be observable. As contracts near
maturity and observable market data becomes available, they are
transferred out of Level III and into Level II.   
Long-dated commodity transactions in certain markets where liquidity
is low are included in Level III of the fair value hierarchy, as the
related commodity prices are not readily observable. Long-term
electricity prices are estimated using a third-party modelling tool
which takes into account physical operating characteristics of
generation facilities in the markets in which the Company operates.
Inputs into the model include market fundamentals such as fuel
prices, power supply additions and retirements, power demand,
seasonal hydro conditions and transmission constraints. Long-term
North American natural gas prices are based on a view of future
natural gas supply and demand, as well as exploration and development
costs. Long-term prices are reviewed by management and the Board on a
periodic basis. Significant decreases in fuel prices or demand for
electricity or natural gas, or increases in the supply of electricity
or natural gas may result in a lower fair value measurement of
contracts included in Level III.   
The fair value of the Company's assets and liabilities measured on a
recurring basis, including both current and non-current portions, are
categorized as follows: 


 
                                  Significant                               
                 Quoted Prices          Other    Significant                
                     in Active     Observable   Unobservable                
                       Markets         Inputs         Inputs                
                      (Level I)     (Level II)    (Level III)         Total 
                ------------------------------------------------------------
                ------------------------------------------------------------
(unaudited)                                                                 
(millions of                                                                
 dollars, pre-  Sept 30 Dec 31 Sept 30 Dec 31 Sept 30 Dec 31 Sept 30 Dec 31 
 tax)              2012   2011    2012   2011    2012   2011    2012   2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative                                                                  
 Financial                                                                  
 Instrument                                                                 
 Assets:                                                                    
 Interest rate                                                              
  contracts           -      -      29     36       -      -      29     36 
 Foreign                                                                    
  exchange                                                                  
  contracts           -      -     160    141       -      -     160    141 
 Power commodity                                                            
  contracts           -      -     242    201       9      -     251    201 
 Gas commodity                                                              
  contracts          90    124      17     55       -      -     107    179 
Derivative                                                                  
 Financial                                                                  
 Instrument                                                                 
 Liabilities:                                                               
 Interest rate                                                              
  contracts           -      -     (16)   (23)      -      -     (16)   (23)
 Foreign                                                                    
  exchange                                                                  
  contracts           -      -     (75)  (102)      -      -     (75)  (102)
 Power commodity                                                            
  contracts           -      -    (318)  (454)     (5)   (15)   (323)  (469)
 Gas commodity                                                              
  contacts         (114)  (208)    (18)   (26)      -      -    (132)  (234)
Non-Derivative                                                              
 Financial                                                                  
 Instruments:                                                               
 Available-for-                                                             
  sale assets        32     23       -      -       -      -      32     23 
                ------------------------------------------------------------
                      8    (61)     21   (172)      4    (15)     33   (248)
                ------------------------------------------------------------
                ------------------------------------------------------------

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


 
                                                     Derivatives(1)         
                                            ------------------------------- 
                                            ------------------------------- 
                                               Three months     Nine months 
                                                      ended           ended 
(unaudited)                                    September 30    September 30 
(millions of dollars, pre-tax)                 2012    2011    2012    2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Balance at beginning of period                    7     (30)    (15)     (8)
New contracts                                     -       -       -       1 
Settlements                                       -       1      (1)      1 
Transfers out of Level III                      (12)      2     (10)      2 
Total gains included in Net Income(2)             7       -       8       - 
Total gains/(losses) included in OCI              2      10      22     (13)
                                            --------------------------------
Balance at end of period                          4     (17)      4     (17)
                                            --------------------------------
                                            --------------------------------
 
(1) The fair value of derivative assets and liabilities is presented on a   
    net basis.                                                              
(2) For the three and nine months ended September 31, 2012, the unrealized  
    gains or losses included in Net Income attributed to derivatives that   
    were still held at the reporting date was a loss of $1 million (2011 -  
    nil).                                                                   

 
A 10 per cent increase or decrease in commodity prices, with all
other variables held constant, would result in a $6 million decrease
or increase, respectively, in the fair value of outstanding
derivative financial instruments included in Level III as at
September 30, 2012. 
8. Contingencies and Guarantees  
TransCanada and its subsidiaries are subject to various legal
proceedings, arbitrations and actions arising in the normal course of
business. While the final outcome of such legal proceedings and
actions cannot be predicted with certainty, it is the opinion of
management that the resolution of such proceedings and actions will
not have a material impact on the Company's consolidated financial
position or results of operations. 
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. With respect to 2012, TransCanada
currently expects spot prices to be less than the floor price for the
year, therefore no amounts recorded in revenues in first nine months
of 2012 are expected to be repaid. 
Guarantees  
TransCanada and its joint venture partners on Bruce Power, Cameco
Corporation and BPC Generation Infrastructure Trust (BPC), have
severally guaranteed one-third of certain contingent financial
obligations of Bruce B related to power sales agreements, a lease
agreement and contractor services. The guarantees have terms ranging
from 2018 to perpetuity. In addition, TransCanada and BPC have each
severally guaranteed one-half of certain contingent financial
obligations related to an agreement with the Ontario Power Authority
to refurbish and restart Bruce A power generation units. The
guarantees have terms ending in 2018 and 2019. TransCanada's share of
the potential exposure under these Bruce A and Bruce B guarantees was
estimated to be $760 million at September 30, 2012. The fair value of
these Bruce Power guarantees at September 30, 2012 is estimated to be
$15 million. The Company's exposure under certain of these guarantees
is unlimited.  
In addition to the guarantees for Bruce Power, the Company and its
partners in certain other jointly owned entities have either (i)
jointly and severally, (ii) jointly or (iii) severally guaranteed the
financial performance of these entities related primarily to
redelivery of natural gas, power purchase arrangement (PPA) payments
and the payment of liabilities. TransCanada's share of the potential
maximum exposure under these assurances was estimated at September
30, 2012 to range from $160 million to $431 million. The fair value
of these guarantees at September 30, 2012 is estimated to be $68
million, which has been included in Deferred Amounts. For certain of
these entities, any payments made by TransCanada under these
guarantees in excess of its ownership interest are to be reimbursed
by its partners.
Contacts:
TransCanada
Media Enquiries:
Shawn Howard/Grady Semmens
403.920.7859 or 800.608.7859 
TransCanada
Investor & Analyst Enquiries:
David Moneta/Terry Hook/Lee Evans
403.920.7911 or 800.361.6522
www.transcanada.com
 
 
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