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TransCanada Reports Increase in Second Quarter Results, Comparable Earnings to $357 Million or $0.51 Per Share, Funds Generated

TransCanada Reports Increase in Second Quarter Results, Comparable Earnings to 
$357 Million or $0.51 Per Share, Funds Generated from
Operations of $955 Million 
CALGARY, ALBERTA -- (Marketwired) -- 07/26/13 -- TransCanada
Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today
announced comparable earnings for second quarter 2013 of $357 million
or $0.51 per share, compared to $300 million or $0.43 per share for
the same period in 2012. Net income attributable to common shares for
second quarter 2013 was $365 million or $0.52 per share.
TransCanada's Board of Directors also declared a quarterly dividend
of $0.46 per common share for the quarter ending September 30, 2013,
equivalent to $1.84 per common share on an annualized basis. 
"All three of our business segments generated strong results during
the second quarter," said Russ Girling, TransCanada's president and
chief executive officer. "Higher power prices in Alberta, an increase
in capacity prices in New York, the return to an eight unit site at
Bruce Power and a higher Canadian Mainline allowed return on equity
all contributed to a significant increase in earnings when compared
to the same period last year. We were also pleased by the significant
shipper interest in our Energy East Pipeline project, which would
transport crude oil from western Canada to eastern Canadian markets
and add to our existing $26 billion portfolio of commercially secured
projects that are targeted for completion by the end of the decade." 
Over the next three years, subject to required approvals, we expect
to complete $13 billion of projects that are currently in advanced
stages of development. They include the Gulf Coast Project, Keystone
XL, the Keystone Hardisty Terminal, the initial phase of the Grand
Rapids Pipeline, the Heartland Pipeline and TC Terminals projects,
the Tamazunchale Pipeline Extension, the acquisition of nine Ontario
Solar projects and ongoing expansion of the NGTL System. 
We have also commercially secured an additional $13 billion of
long-life, contracted energy infrastructure projects that are
expected to be placed into service in 2016 and beyond. They include
the Coastal GasLink and Prince Rupert Gas Transmission projects that
would move natural gas to Canada's West Coast for liquefaction and 
shipment to Asian markets, the Topolobampo and Mazatlan Gas Pipeline
projects in Mexico, completion of the Grand Rapids and Northern
Courier oil pipeline projects in Northern Alberta, and the Napanee
Generating Station in Eastern Ontario. TransCanada expects these
projects to generate predictable, sustained earnings and cash flow. 
Highlights  
(All financial figures are unaudited and in Canadian dollars unless
noted otherwise) 


 
--  Second quarter financial results 
    --  Net income attributable to common shares of $365 million or $0.52
        per share 
    --  Comparable earnings of $357 million or $0.51 per share 
    --  Comparable earnings before interest, taxes, depreciation and
        amortization (EBITDA) of $1.1 billion 
    --  Funds generated from operations of $955 million 
--  Declared a quarterly dividend of $0.46 per common share for the quarter
    ending September 30 
--  Construction on the US$2.3 billion Gulf Coast Project, excluding the
    Houston Lateral, is now 85 per cent complete 
--  Comment period on the U.S. Department of State (DOS) Draft Supplemental
    Environmental Impact Statement for the Keystone XL Pipeline closed on
    April 22 
--  Concluded Energy East open season to obtain firm commitments for a
    pipeline to transport crude oil from western receipt points to eastern
    Canadian markets 
--  For the first time in two decades, Bruce Power is operating as an eight
    unit site with the return of Unit 4 on April 13 and the recent restart
    of Units 1 and 2 
--  Acquired the first of nine Ontario Solar projects for $55 million on
    June 28 
--  Sold a 45 per cent interest in each of GTN and Bison to TC PipeLines, LP
    for US$1.05 billion on July 2 

 
Comparable earnings for second quarter 2013 were $357 million or
$0.51 per share compared to $300 million or $0.43 per share for the
same period in 2012. Higher earnings from the Canadian Mainline,
Western Power, Bruce Power and U.S. Power were partially offset by
lower contributions from U.S. Natural Gas Pipelines. 
Net income attributable to common shares for second quarter 2013 was
$365 million or $0.52 per share compared to $272 million or $0.39 per
share in second quarter 2012. 
Notable recent developments in Oil Pipelines, Natural Gas Pipelines,
Energy and Corporate include:  
Oil Pipelines: 


 
--  Gulf Coast Project: We are constructing a 36-inch pipeline from Cushing,
    Oklahoma to the U.S. Gulf Coast and expect to begin delivering crude oil
    to Port Arthur, Texas at the end of 2013. Construction is approximately
    85 per cent complete and we estimate the cost of the Cushing to Port
    Arthur facilities to be US$2.3 billion. 
    
    Construction of the 76 kilometre (km) (47 mile) Houston Lateral pipeline
    to transport crude oil to Houston refineries is expected to be complete
    in 2014 at a cost of US$300 million.
    
    The Gulf Coast Project will have a capacity of up to 700,000 barrels per
    day (bbl/d). 
 
--  Keystone XL: On March 1, 2013, the DOS released its Draft Supplemental
    Environmental Impact Statement for the Keystone XL Pipeline. The impact
    statement reaffirmed that construction of the proposed pipeline from the
    U.S./Canada border in Montana to Steele City, Nebraska would not result
    in any significant impact to the environment. The DOS continues to
    review submissions on the impact statement that it received during a
    public comment period that ended on April 22, 2013. Once the DOS has
    completed its review, it is anticipated it will issue a Final
    Supplemental Environmental Impact Statement and then consult with other
    government agencies and provide an additional opportunity for the public
    to comment during a National Interest Determination period of up to 90
    days, before making a decision on our Presidential Permit application. 
    
    We anticipate the pipeline to be in service approximately two years
    following the receipt of the Presidential Permit. The US$5.3 billion
    cost estimate will increase depending on the timing of the permit. As of
    June 30, 2013, we had invested US$1.9 billion in the project. 
 
--  Energy East Pipeline: On June 17, 2013, we concluded an open season to
    obtain firm commitments for a pipeline to transport up to 850,000 bbl/d
    of crude oil from western receipt points to eastern Canadian markets and
    are currently reviewing the results. 
    
    The Energy East Pipeline project involves converting natural gas
    pipeline capacity in approximately 3,000 km (1,870 miles) of our
    existing Canadian Mainline to crude oil service and constructing up to
    approximately 1,400 km (870 miles) of new pipeline. 
    
    We have begun Aboriginal and stakeholder engagement and associated field
    work as part of our initial design and planning. If we determine that
    there is sufficient commercial support for the project, we will apply
    for regulatory approval to build and operate the facilities, with a
    potential in-service date of late 2017. 
 
--  Heartland Pipeline and TC Terminals: On May 2, 2013, we announced we had
    secured binding long-term shipping agreements to build, own and operate
    the proposed Heartland Pipeline and TC Terminals projects. 
    
    The proposed projects will include a 200 km (125 mile) crude oil
    pipeline connecting the Edmonton region to facilities in Hardisty,
    Alberta, and a terminal facility in the Heartland industrial area north
    of Edmonton. We anticipate the pipeline could transport up to 900,000
    bbl/d, while the terminal is expected to have storage capacity for up to
    1.9 million barrels of crude oil. These projects together have a
    combined cost estimated at $900 million and are expected to come into
    service during the second half of 2015.
    
    On May 30, 2013, we filed a permit application for the terminal facility
    with the Alberta Energy Regulator and we expect to file an application
    for the pipeline later in 2013. 
 
--  Northern Courier Pipeline: On April 25, 2013, we filed a permit
    application with the Alberta Energy Regulator after completing the
    required Aboriginal and stakeholder engagement and associated field
    work. We continue to work with the Fort Hills Energy Limited Partnership
    on the development of this project. 
 
--  Grand Rapids Pipeline: On May 23, 2013, we filed a permit application
    with the Alberta Energy Regulator after completing the required
    Aboriginal and stakeholder engagement and associated field work. The
    Grand Rapids Pipeline system will be the first pipeline to connect the
    growing oil sands region west of the Athabasca River to the
    Edmonton/Heartland region and will be capable of moving up to 900,000
    bbl/d of crude oil and 330,000 bbl/d of diluent. 

 
Natural Gas Pipelines: 


 
--  National Energy Board (NEB) decision on the Canadian Restructuring
    Proposal: On March 27, 2013, the NEB issued its decision on our
    application to change the business structure and the terms and
    conditions of service for the Canadian Mainline. The decision
    significantly alters the regulatory framework that has formed the basis
    for more than $10 billion of regulated pipeline investment over the last
    sixty years. 
    
    On May 1, 2013, we filed an application for a review and variance of the
    decision and order. The NEB dismissed the review and variance
    application on June 11, 2013, and released its reasons for dismissal on
    July 22, 2013. The NEB did, however, recognize that certain changes
    proposed by TransCanada to the Canadian Mainline's tariff should be
    considered as a separate application through an oral hearing process
    that will commence on September 3, 2013. 
    
    We are effectively operating under the new framework set out by the NEB
    in its decision as of July 1. We have submitted the tariff change
    application and will manage that process through the oral hearing and
    await a decision on those changes. 
 
--  NGTL System: We continue to expand the NGTL System and have placed $700
    million of new facilities into service in 2013. We have applied and
    received approval from the NEB for an additional $130 million of new
    facilities. To date in 2013, we have applied for an additional $145
    million of facilities, which remain subject to NEB approval, and are
    planning regulatory applications for further expansion into British
    Columbia (B.C.), which we estimate will cost between $1.0 billion and
    $1.5 billion, to connect and transport new gas supply that will be
    delivered to the Prince Rupert Gas Transmission Project as well as other
    markets served by the NGTL System. In third quarter 2013, we expect to
    begin an open season to provide delivery service through a
    transportation by others arrangement on Coastal GasLink to Vanderhoof,
    B.C. 
 
--  Prince Rupert Gas Transmission Project: The B.C. Environmental
    Assessment Office issued its Section 10 Order in June 2013 indicating
    that the project is reviewable and requires an environmental assessment
    certificate. The Canadian Environmental Assessment Agency (CEAA)
    initiated the public comment period with respect to the project in June
    2013. 
 
--  Coastal GasLink: We are currently focused on community, landowner,
    government and First Nations engagement as the project advances through
    the regulatory process with the B.C. Environmental Assessment Office and
    the CEAA. 

 
Energy: 


 
--  Bruce Power: Bruce Power returned Unit 4 to service on April 13, 2013
    after completing an expanded life extension outage program which began
    in August 2012. It is anticipated that this investment will allow Unit 4
    to operate until at least 2021. With the return of Unit 4 and the
    restart of Units 1 and 2, Bruce Power is now operating an eight unit
    site for the first time in two decades and is capable of generating
    6,200 megawatts (MW) of emission-free electricity. No further
    maintenance outages are planned at Bruce Power for the remainder of
    2013. 
    
    
--  Sundance A: TransAlta previously announced that it expected Sundance A
    Units 1 and 2 to be returned to service in the fall of 2013. They
    subsequently reported an earlier return to service for Unit 1 of July
    31, 2013. TransAlta has not announced any change in the return to
    service date for Unit 2. Combined, Units 1 and 2 are capable of
    generating 560 MW. 
    
    
--  Ontario Solar: In late 2011, we agreed to buy nine Ontario solar
    projects (combined capacity of 86 MW) from Canadian Solar Solutions Inc.
    for approximately $470 million. On June 28, 2013, we acquired the first
    project for $55 million which has a capacity of 10 MW. We expect to
    close the acquisition of the remaining projects in 2013 and 2014,
    subject to satisfactory completion of the related construction
    activities and regulatory approvals. All power produced will be sold
    under 20-year power purchase arrangements with the Ontario Power
    Authority. 
    
    
--  Becancour: In June 2013, Hydro-Quebec notified us that it would exercise
    its option to extend the agreement to suspend all electricity generation
    from the Becancour power plant through 2014. Under the suspension
    agreement, Hydro-Quebec has the option, subject to certain conditions,
    to extend the suspension every year until regional electricity demand
    levels recover. We continue to receive capacity payments while
    generation is suspended. 

 
Corporate: 


 
--  Our Board of Directors declared a quarterly dividend of $0.46 per share
    for the quarter ending September 30, 2013 on TransCanada's outstanding
    common shares. The quarterly amount is equivalent to $1.84 per common
    share on an annual basis. 
 
--  On July 2, 2013, we completed the sale of a 45 per cent interest in each
    of Gas Transmission Northwest LLC (GTN) and Bison Pipeline LLC (Bison)
    to our master limited partnership, TC PipeLines, LP, for an aggregate
    purchase price of US$1.05 billion which includes US$146 million for 45
    per cent of GTN's debt. The proceeds from the sale will contribute to
    funding a portion of our capital program. The transaction demonstrates
    one of the many financing options available to us as we execute on our
    unprecedented growth portfolio. 
    
    In May 2013, TC PipeLines, LP completed a public offering of 8,855,000
    common units at a price of US$43.85 per unit, resulting in gross
    proceeds of approximately US$388 million. We invested US$8 million to
    maintain our two per cent general partnership interest and did not
    purchase any additional common units. Upon completion of this offering,
    our ownership interest in TC PipeLines, LP decreased from 33.3 per cent
    to 28.9 per cent.
    
    In July 2013, TC PipeLines, LP entered into a five-year, US$500 million
    term loan, maturing July 2018. The proceeds from the term loan were used
    to partially finance the acquisition of the 45 per cent interest in GTN
    and Bison. 
 
--  In July 2013, we issued US$500 million of three-year LIBOR-based
    floating rate notes maturing on June 30, 2016, bearing interest at an
    initial annual rate of 0.95 per cent. 
    
    Also in July 2013, we issued $450 million and $300 million of medium
    term notes maturing on July 19, 2023 and November 15, 2041,
    respectively, and bearing interest at 3.69 and 4.55 per cent per annum,
    respectivel
y.
    
    The net proceeds of these offerings are intended to be used for general
    corporate purposes and to reduce short-term indebtedness which was used
    to fund a portion of our capital program. 

 
Teleconference - Audio and Slide Presentation: 
We will hold a teleconference and webcast on Friday, July 26, 2013 to
discuss our second quarter 2013 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 866.507.1212 or 416.695.6616
(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) on August 2, 2013. Please
call 800.408.3053 or 905.694.9451 and enter pass code 1924325. 
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 more than 400
billion cubic feet of storage capacity. A growing independent power
producer, TransCanada owns or has interests in over 11,800 megawatts
of power generation in Canada and the United States. TransCanada is
developing one of North America's largest oil delivery systems.
TransCanada's common shares trade on the Toronto and New York stock
exchanges under the symbol TRP. For more information visit:
www.transcanada.com or check us out on Twitter @TransCanada or
http://blog.transcanada.com.  
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", "believe", "may", "will", "should",
"estimate", "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 plans and financial
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 Quarterly Report to
Shareholders dated July 25, 2013 and 2012 Annual Report on our
website at www.transcanada.com or filed under TransCanada's profile
on SEDAR at www.sedar.com and with the U.S. Securities and Exchange
Commission at www.sec.gov. 
Non-GAAP Measures  
This news release contains references to non-GAAP measures, including
comparable earnings, EBITDA, funds generated from operations and
comparable earnings per share, that do not have any standardized
meaning as prescribed by U.S. GAAP and therefore are unlikely to be
comparable to similar measures presented 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 July 25, 2013. 
Quarterly report to shareholders  
Second quarter 2013  
Financial highlights  
Comparable EBITDA, comparable earnings, comparable earnings per
common share and funds generated from operations are all non-GAAP
measures. See non-GAAP measures section for more information.  


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                          June 30             June 30       
                                   -------------------- --------------------
(unaudited - millions of $, except                                          
 per share amounts)                     2013       2012      2013      2012 
----------------------------------------------------------------------------
                                                                            
Income                                                                      
Revenue                                2,009      1,847     4,261     3,792 
Comparable EBITDA                      1,143        997     2,311     2,110 
Net income attributable to common                                           
 shares                                  365        272       811       624 
  per common share - basic             $0.52      $0.39     $1.15     $0.89 
Comparable earnings                      357        300       727       663 
  per common share                     $0.51      $0.43     $1.03     $0.94 
                                                                            
Operating cash flow                                                         
Funds generated from operations          955        729     1,871     1,600 
(Increase)/decrease in operating                                            
 working capital                        (114)        14      (324)     (155)
----------------------------------------------------------------------------
Net cash provided by operations          841        743     1,547     1,445 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Investing activities                                                        
Capital expenditures                   1,109        397     2,038       861 
Equity investments                        39        197        71       413 
Acquisition                               55          -        55         - 
                                                                            
Dividends                                                                   
Per common share                       $0.46      $0.44     $0.92     $0.88 
                                                                            
Basic common shares outstanding                                             
 (millions)                                                                 
Average for the period                   707        704       706       704 
End of period                            707        704       707       704 
----------------------------------------------------------------------------

 
Management's discussion and analysis  
July 25, 2013  
This management's discussion and analysis (MD&A) contains information
to help the reader make investment decisions about TransCanada
Corporation. It discusses our business, operations, financial
position, risks and other factors for the three and six months ended
June 30, 2013, and should be read with the accompanying unaudited
condensed consolidated financial statements for the three and six
months ended June 30, 2013 which have been prepared in accordance
with U.S. GAAP.  
This MD&A should also be read in conjunction with our December 31,
2012 audited consolidated financial statements and notes and the MD&A
in our 2012 Annual Report, which have been prepared in accordance
with U.S. GAAP.  
About this document  
Throughout this MD&A, the terms, we, us, our and TransCanada mean
TransCanada Corporation and its subsidiaries.  
Abbreviations and acronyms that are not defined in this MD&A are
defined in the glossary in our 2012 Annual Report.  
All information is as of July 25, 2013 and all amounts are in
Canadian dollars, unless noted otherwise.  
FORWARD-LOOKING INFORMATION  
We disclose forward-looking information to help current and potential
investors understand management's assessment of our future plans and
financial outlook, and our future prospects overall.  
Statements that are forward-looking are based on certain assumptions
and on what we know and expect today and generally include words like
anticipate, expect, believe, may, will, should, estimate or other
similar words.  
Forward-looking statements in this MD&A may include information about
the following, among other things:  


 
--  anticipated business prospects 
--  our financial and operational performance, including the performance of
    our subsidiaries 
--  expectations or projections about strategies and goals for growth and
    expansion 
--  expected cash flows and future financing options available to us 
--  expected costs for planned projects, including projects under
    construction and in development 
--  expected schedules for planned projects (including anticipated
    construction and completion dates) 
--  expected regulatory processes and outcomes 
--  expected impact required as a result of regulatory outcomes 
--  expected outcomes with respect to legal proceedings, including
    arbitration 
--  expected capital expenditures and contractual obligations 
--  expected operating and financial results 
--  the expected impact of future commitments and contingent liabilities 
--  expected industry, market and economic conditions. 

 
Forward-looking statements do not guarantee future performance.
Actual events and results could be significantly different because of
assumptions, risks or uncertainties related to our business or events
that happen after the date of this MD&A.  
Our forward-looking information is based on the following key
assumptions, and subject to the following risks and uncertainties: 
Assumptions 


 
--  inflation rates, commodity prices and capacity prices 
--  timing of financings and hedging 
--  regulatory decisions and outcomes 
--  foreign exchange rates 
--  interest rates 
--  tax rates 
--  planned and unplanned outages and the use of our pipeline and energy
    assets 
--  integrity and reliability of our assets 
--  access to capital markets 
--  anticipated construction costs, schedules and completion dates 
--  acquisitions and divestitures. 

 
Risks and uncertainties 


 
--  our ability to successfully implement our strategic initiatives 
--  whether our strategic initiatives will yield the expected benefits 
--  the operating performance of our pipeline and energy assets 
--  amount of capacity sold and rates achieved in our pipeline businesses 
--  the availability and price of energy commodities 
--  the amount of capacity payments and revenues we receive from our energy
    business 
--  regulatory decisions and outcomes 
--  outcomes of legal proceedings, including arbitration 
--  performance of our counterparties 
--  changes in the political environment 
--  changes in environmental and other laws and regulations 
--  competitive factors in the pipeline and energy sectors 
--  construction and completion of capital projects 
--  labour, equipment and material costs 
--  access to capital markets 
--  interest and foreign exchange rates 
--  weather 
--  cybersecurity 
--  technological developments 
--  economic conditions in North America as well as globally. 

 
You can read more about these factors and others in reports we have
filed with Canadian securities regulators and the SEC, including the
MD&A in our 2012 Annual Report.  
You should not put undue reliance on forward-looking information and
should not use future-oriented information or financial outlooks for
anything other than their intended purpose. We do not update our
forward-looking statements due to new information or future events,
unless we are required to by law. 
FOR MORE INFORMATION  
You can find more information about TransCanada in our annual
information form and other disclosure documents, which are available
on SEDAR (www.sedar.com). 
NON-GAAP MEASURES  
We use the following non-GAAP measures:  


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

 
These measures do not have any standardized meaning as prescribed by
U.S. GAAP and therefore are unlikely to be comparable to similar
measures presented by other entities. 
EBITDA and EBIT  
We use EBITDA as an approximate measure of our pre-tax operating cash
flow. It measures our earnings before deducting interest and other
financial charges, income taxes, depreciation and amortization, net
income attributable to non-controlling interests and preferred share
dividends, and includes income from equity investments. EBIT measures
our earnings from ongoing operations and is an effective measure of
our performance and an effective tool for evaluating trends in each
segment. It is calculated in the same way as EBITDA, less
depreciation and amortization.  
Funds generated from operations  
Funds generated from operations includes net cash provided by
operations before changes in operating working capital. We believe it
is an effective measure of our consolidated operating cashflow
because it does not include fluctuations from working capital
balances, which do not necessarily reflect underlying operations in
the same period. See Financial condition section for a reconciliation
to net cash provided by operations. 
Comparable measures  
We calculate the comparable measures by adjusting certain GAAP and
non-GAAP measures for specific items we believe are significant but
not reflective of our underlying operations in the period. These
comparable measures are calculated on a consistent basis from period
to period and are adjusted for specific items in each period, as
applicable. 


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

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


 
--  certain fair value adjustments relating to risk management activities 
--  income tax refunds and adjustments 
--  gains or losses on sales of assets 
--  legal and bankruptcy settlements, and 
--  write-downs of assets and investments. 

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


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $, except                                          
 per share amounts)                     2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Comparable EBITDA                      1,143       997      2,311     2,110 
Comparable depreciation and                                                 
 amortization                           (356)     (346)      (710)     (690)
----------------------------------------------------------------------------
Comparable EBIT                          787       651      1,601     1,420 
----------------------------------------------------------------------------
Other income statement items                                                
Comparable interest expense             (252)     (239)      (509)     (481)
Comparable interest income and                                              
 other                                    (2)       19         16        44 
Comparable income taxes                 (133)      (91)      (292)     (231)
Net income attributable to non-                                             
 controlling interests                   (23)      (26)       (54)      (61)
Preferred share dividends                (20)      (14)       (35)      (28)
----------------------------------------------------------------------------
Comparable earnings                      357       300        727       663 
Specific items (net of tax):                                                
  Canadian restructuring proposal -                                         
   2012                                    -         -         84         - 
  Income tax adjustment                   25         -         25         - 
  Sundance A PPA arbitration                                                
   decision - 2011                         -       (15)         -       (15)
  Risk management activities(1)          (17)      (13)       (25)      (24)
----------------------------------------------------------------------------
Net income attributable to common                                           
 shares                                  365       272        811       624 
----------------------------------------------------------------------------
Comparable depreciation and                                                 
 amortization                           (356)     (346)      (710)     (690)
Specific item:                                                              
  Canadian restructuring proposal -                                         
   2012                                    -         -        (13)        - 
----------------------------------------------------------------------------
Depreciation and amortization           (356)     (346)      (723)     (690)
----------------------------------------------------------------------------
Comparable interest expense             (252)     (239)      (509)     (481)
Specific item:                                                              
  Canadian restructuring proposal -                                         
   2012                                    -         -         (1)        - 
----------------------------------------------------------------------------
Interest expense                        (252)     (239)      (510)     (481)
----------------------------------------------------------------------------
Comparable interest income and                                              
 other                                    (2)       19         16        44 
Specific items:                                                             
  Canadian restructuring proposal -                                         
   2012                                    -         -          1         - 
  Risk management activities(1)           (9)      (14)       (15)       (8)
----------------------------------------------------------------------------
Interest income and other                (11)        5          2        36 
----------------------------------------------------------------------------
Comparable income taxes                 (133)      (91)      (292)     (231)
Specific items:                                                             
  Canadian restructuring proposal -                                         
   2012                                    -         -         42         - 
  Income tax adjustment                   25         -         25         - 
  Income taxes attributable to                                              
   Sundance A PPA arbitration                                               
   decision - 2011                         -         5          -         5 
  Risk management activities(1)           10         1         12        12 
----------------------------------------------------------------------------
Income taxes expense                     (98)      (85)      (213)     (214)
----------------------------------------------------------------------------
Comparable earnings per common                                              
 share                                 $0.51     $0.43      $1.03     $0.94 
Specific items (net of tax):                                                
  Canadian restructuring proposal -                                         
   2012                                    -         -       0.12         - 
  Income tax adjustment                 0.04         -       0.04         - 
  Sundance A PPA arbitration                                                
   decision - 2011                         -     (0.02)         -     (0.02)
  Risk management activities(1)        (0.03)    (0.02)     (0.04)    (0.03)
----------------------------------------------------------------------------
Net income per common share            $0.52     $0.39      $1.15     $0.89 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                          June 30             June 30       
                                    ------------------- --------------------
(1)(unaudited - millions of $)           2013     2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Canadian Power                             (4)       1         (6)       (1)
U.S. Power                                (18)      16        (17)      (16)
Natural Gas Storage                         4      (17)         1       (11)
Foreign exchange                           (9)     (14)       (15)       (8)
Income taxes attributable to risk                                           
 management activities                     10        1         12        12 
----------------------------------------------------------------------------
Total losses from risk management                                           
 activities                               (17)     (13)       (25)      (24)
-----
-----------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
EBITDA and EBIT by business segment                                         
                                                                            
----------------------------------------------------------------------------
                                  Natural                                   
three months ended June 30, 2013      Gas       Oil                         
(unaudited - millions of $)     Pipelines Pipelines Energy Corporate  Total 
----------------------------------------------------------------------------
                                                                            
Comparable EBITDA                     644       186    330       (17) 1,143 
Comparable depreciation and                                                 
 amortization                        (245)      (37)   (69)       (5)  (356)
----------------------------------------------------------------------------
Comparable EBIT                       399       149    261       (22)   787 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
                                  Natural                                   
three months ended June 30, 2012      Gas       Oil                         
(unaudited - millions of $)     Pipelines Pipelines Energy Corporate  Total 
----------------------------------------------------------------------------
                                                                            
Comparable EBITDA                     666       176    170       (15)   997 
Comparable depreciation and                                                 
 amortization                        (234)      (36)   (72)       (4)  (346)
----------------------------------------------------------------------------
Comparable EBIT                       432       140     98       (19)   651 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
                                  Natural                                   
six months ended June 30, 2013        Gas       Oil                         
(unaudited - millions of $)     Pipelines Pipelines Energy Corporate  Total 
----------------------------------------------------------------------------
                                                                            
Comparable EBITDA                   1,390       365    607       (51) 2,311 
Comparable depreciation and                                                 
 amortization                        (485)      (74)  (143)       (8)  (710)
----------------------------------------------------------------------------
Comparable EBIT                       905       291    464       (59) 1,601 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
                                  Natural                                   
six months ended June 30, 2012        Gas       Oil                         
(unaudited - millions of $)     Pipelines Pipelines Energy Corporate  Total 
----------------------------------------------------------------------------
                                                                            
Comparable EBITDA                   1,391       349    414       (44) 2,110 
Comparable depreciation and                                                 
 amortization                        (466)      (72)  (145)       (7)  (690)
----------------------------------------------------------------------------
Comparable EBIT                       925       277    269       (51) 1,420 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Results - second quarter 2013  
Net income attributable to common shares was $365 million this
quarter compared to $272 million in second quarter 2012. Second
quarter 2013 results included a $25 million favourable income tax
adjustment due to the enactment of Canadian Federal tax legislation
relating to Part VI.I tax, in June 2013 and was excluded from
comparable earnings. Second quarter 2012 included an after-tax charge
of $37 million ($50 million pre-tax) related to the impact of the
Sundance A PPA arbitration decision. Of this amount, $15 million ($20
million pre-tax) is excluded from 2012 comparable earnings as it
related to 2011.  
Net income attributable to common shares was $811 million for the six
months ended June 30, 2013 compared to $624 million for the same
period in 2012. The 2013 results included $84 million of net income
related to 2012 from the NEB decision on the Canadian Restructuring
Proposal. Also included was the $25 million of net income resulting
from the favourable income tax adjustment noted above. These amounts
were excluded from comparable earnings. The 2012 results included an
after-tax charge of $15 million ($20 million pre-tax) that was
excluded from 2012 comparable earnings as it related to 2011.  
Comparable earnings this quarter were $357 million and $0.51 per
share, $57 million and $0.08 per share higher than second quarter
2012.  
This was the result of: 


 
--  higher earnings from Western Power because of higher realized power
    prices, higher purchased PPA volumes as well as the Sundance A PPA
    charge recorded in second quarter 2012  
--  higher equity income from Bruce Power because of incremental earnings
    from Units 1 and 2, which were returned to service in October 2012, and
    the completion of the Unit 3 West Shift Plus planned outage in June
    2012, partially offset by higher planned outage days in second quarter
    2013 
--  higher realized power prices from U.S. Power 
--  higher earnings from the Canadian Mainline because of the higher ROE of
    11.50 per cent in 2013 compared to 8.08 per cent in 2012. 

 
These increases were partly offset by: 


 
--  lower contribution from U.S. natural gas pipelines 
--  higher comparable interest expense reflecting lower capitalized interest
    primarily as a result of the return to service of Bruce Power Units 1
    and 2 
--  lower comparable interest income and other because we had realized
    losses in 2013 compared to realized gains in 2012 on derivatives used to
    manage our exposure to foreign exchange rate fluctuations on U.S.
    dollar-denominated income 
--  higher comparable income taxes because of higher pre-tax earnings. 

 
Comparable earnings for the six months ended June 30, 2013 were $727
million and $1.03 per share, $64 million and $0.09 per share higher
than the same period in 2012.  
This was the result of: 


 
--  higher equity income from Bruce Power because of incremental earnings
    from Units 1, 2 and 3 and the recognition of an insurance recovery in
    first quarter 2013 partly offset by an increase in planned outage days 
--  higher realized power prices in Western Power and U.S. Power 
--  higher earnings from the Canadian Mainline because of the higher ROE of
    11.50 per cent in 2013 compared to 8.08 per cent in 2012. 

 
These increases were partly offset by: 


 
--  lower contribution from U.S. natural gas pipelines 
--  lower comparable interest income and other because we had realized
    losses in 2013 compared to realized gains in 2012 on derivatives used to
    manage our exposure to foreign exchange rate fluctuations on U.S.
    dollar-denominated income 
--  higher comparable income taxes because of higher pre-tax earnings. 

 
Comparable earnings do not include net unrealized after-tax losses
resulting from changes in the fair value of certain risk management
activities:  


 
--  $17 million ($27 million before tax) for the three months ended June 30,
    2013 compared to $13 million ($14 million before tax) for the same
    period in 2012 
--  $25 million ($37 million before tax) for the six months ended June 30,
    2013 compared to $24 million ($36 million before tax) for the same
    period in 2012.

 
Outlook  
While the NEB's March 27, 2013 decision on the Canadian Restructuring
Proposal for tolls and services on the Canadian Mainline may result
in increased variability and seasonality of cash flow, we expect it
to have a positive impact on the earnings outlook for 2013 previously
included in our 2012 Annual Report. The NEB approved an allowed ROE
of 11.50 per cent on 40 per cent deemed common equity ratio,
multi-year tolls through 2017 and a new incentive mechanism. In
addition, we expect the recent increase in 2013 power prices in
Western Power to also have a positive impact on our previously
disclosed earnings outlook for 2013. See the MD&A in our 2012 Annual
Report for further information about our outlook.  
Natural Gas Pipelines  
Comparable EBITDA and comparable EBIT are non-GAAP measures. See
non-GAAP measures section for more information.  


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $)             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Canadian Pipelines                                                          
Canadian Mainline                        263       247        543       497 
NGTL System                              193       183        375       360 
Foothills                                 28        30         57        61 
Other Canadian (TQM(1), Ventures                                            
 LP)                                       7         7         13        15 
----------------------------------------------------------------------------
Canadian Pipelines - comparable                                             
 EBITDA                                  491       467        988       933 
Comparable depreciation and                                                 
 amortization(2)                        (190)     (177)      (374)     (354)
----------------------------------------------------------------------------
Canadian Pipelines - comparable                                             
 EBIT                                    301       290        614       579 
                                                                            
U.S. and International (US$)                                                
ANR                                       32        53        122       150 
GTN(3)                                    26        26         54        56 
Great Lakes(4)                             8        17         18        35 
TC PipeLines, LP(1,5)                     13        18         30        38 
Other U.S. pipelines (Iroquois(1),                                          
 Bison(3), Portland(6))                   23        23         66        57 
International (Gas                                                          
 Pacifico/INNERGY(1), Guadalajara,                                          
 Tamazunchale, TransGas(1))               25        30         51        58 
General, administrative and support                                         
 costs                                    (3)       (2)        (5)       (4)
Non-controlling interests(7)              31        38         74        83 
----------------------------------------------------------------------------
U.S. Pipelines and International -                                          
 comparable EBITDA                       155       203        410       473 
Comparable depreciation and                                                 
 amortization(2)                         (54)      (56)      (109)     (111)
----------------------------------------------------------------------------
U.S. Pipelines and International -                                          
 comparable EBIT                         101       147        301       362 
Foreign exchange                           2         2          4         2 
----------------------------------------------------------------------------
U.S. Pipelines and International -                                          
 comparable EBIT (Cdn$)                  103       149        305       364 
                                                                            
Business Development comparable                                             
 EBITDA and EBIT                          (5)       (7)       (14)      (18)
----------------------------------------------------------------------------
Natural Gas Pipelines - comparable                                          
 EBIT                                    399       432        905       925 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Summary                                     
                                
----------------------------------------------------------------------------
Natural Gas Pipelines - comparable                                          
 EBITDA                                  644       666      1,390     1,391 
Comparable depreciation and                                                 
 amortization(2)                        (245)     (234)      (485)     (466)
----------------------------------------------------------------------------
Natural Gas Pipelines - comparable                                          
 EBIT                                    399       432        905       925 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Results from TQM, Northern Border, Iroquois, TransGas and Gas           
    Pacifico/INNERGY reflect our share of equity income from these          
    investments.                                                            
(2) Does not include depreciation and amortization from equity investments. 
(3) Represents our 75 per cent direct ownership interest.                   
(4) Represents our 53.6 per cent direct ownership interest.                 
(5) Effective May 22, 2013, our ownership interest in TC PipeLines, LP      
    decreased from 33.3 per cent to 28.9 per cent. Results reflect our 28.9 
    per cent ownership interest effective May 22, 2013 and 33.3 per cent    
    from January 1 to May 22, 2013. Our effective ownership through TC      
    PipeLines, LP prior to May 22, 2013 was 8.3 per cent of each of GTN and 
    Bison, 16.7 per cent of Northern Border and an additional effective     
    ownership of 15.4 per cent of Great Lakes. Our effective ownership      
    through TC PipeLines, LP effective May 22, 2013 was 7.2 per cent of each
    of GTN and Bison, 14.4 per cent of Northern Border and an additional    
    effective ownership of 13.4 per cent of Great Lakes.                    
(6) Represents our 61.7 per cent ownership interest.                        
(7) Comparable EBITDA for the portions of TC PipeLines, LP and Portland we  
    do not own.                                                             
                                                                            
NET INCOME - WHOLLY OWNED CANADIAN PIPELINES                                
                                                                            
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                          June 30              June 30      
                                   -------------------- --------------------
(unaudited - millions of $)              2013      2012       2013      2012
----------------------------------------------------------------------------
                                                                            
Canadian Mainline - net income             67        46        218        93
Canadian Mainline - comparable                                              
 earnings                                  67        46        134        93
NGTL System                                58        52        114       100
Foothills                                   5         4          9         9
----------------------------------------------------------------------------
                                                                            
OPERATING STATISTICS - WHOLLY OWNED PIPELINES                               
                                                                            
----------------------------------------------------------------------------
                                          Canadian      NGTL                
six months ended June 30                 Mainline(1)  System(2)    ANR(3)   
                                        ------------------------------------
(unaudited)                               2013  2012  2013  2012  2013  2012
----------------------------------------------------------------------------
                                                                            
Average investment base (millions of $)  5,871 5,775 5,882 5,359   n/a   n/a
Delivery volumes (Bcf)                                                      
  Total                                    704   804 1,832 1,844   823   844
  Average per day                          3.9   4.4  10.1  10.1   4.6   4.6
----------------------------------------------------------------------------
                                                                            
(1) Canadian Mainline's throughput volumes represent physical deliveries to 
    domestic and export markets. Physical receipts originating at the       
    Alberta border and in Saskatchewan for the six months ended June 30,    
    2013 were 397 Bcf (2012 - 455 Bcf). Average per day was 2.2 Bcf (2012 - 
    2.5 Bcf).                                                               
(2) Field receipt volumes for the NGTL System for the six months ended June 
    30, 2013 were 1,840 Bcf (2012 - 1,856 Bcf). Average per day was 10.2 Bcf
    (2012 - 10.2 Bcf).                                                      
(3) Under its current rates, which are approved by the FERC, changes in     
    average investment base do not affect results.                          

 
CANADIAN PIPELINES  
Comparable EBITDA and net income for our rate-regulated Canadian
Pipelines are affected by our approved ROE, our investment base, the
level of deemed common equity and incentive earnings. Changes in
depreciation, financial charges and taxes also impact comparable
EBITDA and EBIT but do not impact net income as they are recovered in
revenue on a flow-through basis.  
Canadian Mainline's comparable earnings increased by $21 million for
the three months ended June 30, 2013 and $41 million for the six
months ended June 30, 2013 compared to the same periods in 2012
because of the impact of the NEB's March 2013 decision (the NEB
decision) on the Canadian Restructuring Proposal. Among other items,
the NEB approved an ROE of 11.50 per cent on a 40 per cent deemed
common equity for the years 2012 through to 2017 compared to the last
approved ROE of 8.08 per cent on a deemed common equity of 40 per
cent that was used to record earnings in 2012. Net income of $218
million for the six months ended June 30, 2013 included $84 million
related to the 2012 impact of the NEB decision.  
Net income for the NGTL System (formerly known as the Alberta System)
increased by $6 million for the three months ended June 30, 2013 and
$14 million for the six months ended June 30, 2013, compared to the
same periods in 2012 because of a higher average investment base and
termination of the annual fixed OM&A costs component included in the
2010 - 2012 Revenue Requirement Settlement which expired at the end
of 2012. Results for 2013 reflect the last approved ROE of 9.70 per
cent on deemed common equity of 40 per cent and no incentive
earnings. 
U.S. PIPELINES AND INTERNATIONAL  
EBITDA for our U.S. operations is generally affected by contracted
volume levels, volumes delivered and the rates charged, as well as by
the cost of providing services, including OM&A and property taxes.
ANR is also affected by the contracting and pricing of its storage
capacity and incidental commodity sales.  
Comparable EBITDA for the U.S. and international pipelines was US$155
million for the three months ended June 30, 2013 and US$410 million
for the six months ended June 30, 2013 compared to US$203 million and
US$473 million for the same periods in 2012. This was the net effect
of: 


 
--  higher costs at ANR relating to services provided by other pipelines as
    well as lower second quarter revenues 
--  lower revenues at Great Lakes because of lower rates and uncontract
ed
    capacity 
--  lower contributions from TransGas and Gas Pacifico/INNERGY 
--  higher short term and interruptible revenues at Portland. 

 
COMPARABLE DEPRECIATION AND AMORTIZATION  
Comparable depreciation and amortization was $245 million for the
three months ended June 30, 2013 and $485 million for the six months
ended June 30, 2013 compared to $234 million and $466 million for the
same periods in 2012 mainly because of a higher investment base on
the NGTL System and the impact of the NEB decision on the Canadian
Mainline.  
Oil Pipelines  
Comparable EBITDA and comparable EBIT are non-GAAP measures. See
non-GAAP measures section for more information.  


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $)             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Keystone Pipeline System                 187       178        373       352 
Oil Pipelines Business Development        (1)       (2)        (8)       (3)
----------------------------------------------------------------------------
Oil Pipelines - comparable EBITDA        186       176        365       349 
Comparable depreciation and                                                 
 amortization                            (37)      (36)       (74)      (72)
----------------------------------------------------------------------------
Oil Pipelines - comparable EBIT          149       140        291       277 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable EBIT denominated as                                              
 follows:                                                                   
Canadian dollars                          52        51         99        99 
U.S. dollars                              95        88        189       177 
Foreign exchange                           2         1          3         1 
----------------------------------------------------------------------------
                                         149       140        291       277 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Comparable EBITDA for the Keystone Pipeline System increased by $9
million for the three months ended June 30, 2013 and $21 million for
the six months ended June 30, 2013 compared to the same periods in
2012. These increases reflected higher revenues primarily resulting
from:  


 
--  higher contracted volumes 
--  higher final fixed tolls on committed pipeline capacity to Cushing,
    Oklahoma, which came into effect in July 2012. 

 
BUSINESS DEVELOPMENT  
Business development expenses in the first six months of 2013 were $5
million higher than the same period in 2012 because of increased
activity on various development projects. 
Energy  
Comparable EBITDA and comparable EBIT are non-GAAP measures. See
non-GAAP measures section for more information.  


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $)             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Canadian Power                                                              
Western Power(1)                         123        27        202       158 
Eastern Power(1,2)                        75        73        170       166 
Bruce Power(1)                            59        31         90        18 
General, administrative and support                                         
 costs                                   (12)      (11)       (22)      (22)
----------------------------------------------------------------------------
Canadian Power - comparable                                                 
 EBITDA(1)                               245       120        440       320 
Comparable depreciation and                                                 
 amortization(3)                         (43)      (39)       (86)      (79)
----------------------------------------------------------------------------
Canadian Power - comparable EBIT(1)      202        81        354       241 
U.S. Power (US$)                                                            
Northeast Power                           92        49        169        95 
General, administrative and support                                         
 costs                                   (12)      (11)       (22)      (21)
----------------------------------------------------------------------------
U.S. Power - comparable EBITDA            80        38        147        74 
Comparable depreciation and                                                 
 amortization                            (23)      (30)       (51)      (60)
----------------------------------------------------------------------------
U.S. Power - comparable EBIT              57         8         96        14 
Foreign exchange                           1         1          2         1 
----------------------------------------------------------------------------
U.S. Power - comparable EBIT (Cdn$)       58         9         98        15 
----------------------------------------------------------------------------
Natural Gas Storage                                                         
Alberta Storage                           11        19         31        34 
General, administrative and support                                         
 costs                                    (2)       (2)        (4)       (4)
----------------------------------------------------------------------------
Natural Gas Storage - comparable                                            
 EBITDA(1)                                 9        17         27        30 
Comparable depreciation and                                                 
 amortization(3)                          (2)       (3)        (5)       (6)
----------------------------------------------------------------------------
Natural Gas Storage - comparable                                            
 EBIT(1)                                   7        14         22        24 
Business Development comparable                                             
 EBITDA and EBIT                          (6)       (6)       (10)      (11)
----------------------------------------------------------------------------
Energy - comparable EBIT(1)              261        98        464       269 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Summary                                                                     
----------------------------------------------------------------------------
Energy - comparable EBITDA(1)            330       170        607       414 
Comparable depreciation and                                                 
 amortization(3)                         (69)      (72)      (143)     (145)
----------------------------------------------------------------------------
Energy - comparable EBIT(1)              261        98
        464       269 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Includes our share of equity income from our investments in ASTC Power  
    Partnership, which holds the Sundance B PPA, Portlands Energy, Bruce    
    Power and, in 2012, CrossAlta. In December 2012, we acquired the        
    remaining 40 per cent interest in CrossAlta, bringing our ownership     
    interest to 100 per cent.                                               
(2) Includes phase two of Cartier Wind Gros-Morne starting in November 2012 
    and the acquisition of the first Ontario Solar project in June 2013.    
(3) Does not include depreciation and amortization of equity investments.   

 
Comparable EBITDA for Energy increased by $160 million for the three
months ended June 30, 2013 compared to the same period in 2012. The
increase was the effect of: 


 
--  higher earnings from Western Power primarily due to higher realized
    power prices, the Sundance A PPA charge recorded in second quarter 2012
    earnings and higher purchased PPA volumes 
--  higher earnings from U.S. Power mainly because of higher realized power
    and capacity prices in New York 
--  higher equity income from Bruce Power because of incremental earnings
    from Units 1 and 2, which were returned to service in October 2012, and
    higher earnings from Unit 3, due to an outage during first and second
    quarter 2012, partially offset by lower Bruce B volumes due to higher
    planned outage days.  

 
Comparable EBITDA for Energy increased by $193 million for the six
months ended June 30, 2013 compared to the same period in 2012. The
increase was the effect of: 


 
--  higher earnings from U.S. Power mainly because of higher realized power
    prices and higher capacity prices in New York 
--  higher equity income from Bruce Power because of incremental earnings
    from Units 1 and 2, which were returned to service in October 2012, the
    recognition of a business interruption insurance recovery in first
    quarter 2013, and higher earnings from Unit 3 due to the first and
    second quarter 2012 outage partially offset by the extended outage of
    Unit 4 in first quarter 2013 and lower Bruce B volumes due to higher
    planned outage days 
--  higher earnings from Western Power primarily due to higher realized
    power prices and higher purchased PPA volumes.  

 
CANADIAN POWER  
Western and Eastern Power(1)  
Comparable EBITDA and comparable EBIT are non-GAAP measures. See
non-GAAP measures section for more information. 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $)             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Revenue                                                                     
Western Power                            161       106        303       330 
Eastern Power(1)                          91        98        200       201 
Other(2)                                  22        22         53        47 
----------------------------------------------------------------------------
                                         274       226        556       578 
Income from equity investments(3)         66        (6)        88        17 
----------------------------------------------------------------------------
Commodity purchases resold                                                  
Western power                            (82)      (43)      (147)     (137)
Other(4)                                  (1)        -         (3)       (2)
----------------------------------------------------------------------------
                                         (83)      (43)      (150)     (139)
----------------------------------------------------------------------------
Plant operating costs and other          (59)      (47)      (122)     (102)
Sundance A PPA arbitration decision                                         
 - 2012                                    -       (30)         -       (30)
General, administrative and support                                         
 costs                                   (12)      (11)       (22)      (22)
----------------------------------------------------------------------------
Comparable EBITDA                        186        89        350       302 
Comparable depreciation and                                                 
 amortization(5)                         (43)      (39)       (86)      (79)
----------------------------------------------------------------------------
Comparable EBIT                          143        50        264       223 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Includes phase two of Cartier Wind Gros-Morne starting in November 2012 
    and the acquisition of the first Ontario Solar project in June 2013.    
(2) Includes sale of excess natural gas purchased for generation and sales  
    of thermal carbon black.                                                
(3) Includes our share of equity income from our investments in ASTC Power  
    Partnership, which holds the Sundance B PPA, and Portlands Energy.      
(4) Includes the cost of excess natural gas not used in operations.         
(5) Does not include depreciation and amortization of equity investments.   

 
Sales volumes and plant availability  
Includes our share of volumes from our equity investments. 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited)                             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Sales volumes (GWh)                                                         
Supply                                                                      
  Generation                                                                
    Western Power                        687       654      1,357     1,325 
    Eastern Power(1)                     750       907      2,096     2,050 
  Purchased                                                                 
    Sundance A & B and Sheerness                                            
     PPAs(2)                           1,788     1,295      3,495     3,334 
    Other purchases                        -         1          -        46 
----------------------------------------------------------------------------
                                       3,225     2,857      6,948     6,755 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales                                                                       
  Contracted                                                                
    Western Power                      1,939     1,741      3,646     4,036 
    Eastern Power(1)                     750       907      2,096     2,050 
  Spot                                                                      
    Western Power                        536       209      1,206       669 
----------------------------------------------------------------------------
                                       3,225     2,857      6,948     6,755 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Plant availability(3)                                                       
Western Power(4)                          92%       97%        94%       98%
Eastern Power(1,5)                        80%       76%        88%       84%
----------------------------------------------------------------------------
                                                                            
(1) Includes phase two of Cartier Wind Gros-Morne starting in November 2012 
    and the acquisition of the first Ontario Solar project in June 2013.    
(2) Includes our 50 per cent ownership interest of Sundance B volumes       
    through the ASTC Power Partnership. No volumes were delivered under the 
    Sundance A PPA in 2012 and 2013.                                        
(3) The percentage of time the plant was available to generate power,       
    regardless of whether it was running.                                   
(4) Does not include facilities that provide power to TransCanada under     
    PPAs.                                                                   
(5) Does not include Becancour because power generation has been suspended  
    since 2008.                                                             

 
Western Power's comparable EBITDA increased by $96 million for the
three months ended June 30, 2013 compared to the same period in 2012.
The increase was mainly due to: 


 
--  increased equity income from the ASTC Power Partnership mainly due to
    higher power prices 
--  the Sundance A PPA force majeure arbitration charge recorded in second
    quarter 2012 
--  higher purchased PPA volumes due to fewer outage days 
--  higher realized power prices. 

 
Western Power's comparable EBITDA increased by $44 million for the
six months ended June 30, 2013 compared to the same period 2012. The
increase was mainly due to: 


 
--  increased equity income from the ASTC Power Partnership mainly due to
    higher power prices 
--  higher purchased PPA volumes due to fewer outage days 
--  higher realized power prices. 

 
In first quarter 2012, we recorded revenues and costs related to the
Sundance A PPA as though the outages of Units 1 and 2 were
interruptions of supply in accordance with the terms of the PPA. In
July 2012, we received the Sundance A PPA arbitration decision which
determined the units were in force majeure in first quarter 2012. In
response, we recorded a charge of $30 million in second quarter 2012
equivalent to the pre-tax income we had recorded in first quarter
2012. Because the plant continues to be in force majeure, we will not
record further revenues and costs until the units are returned to
service. See Recent Developments - Energy in this MD&A for more
information about the expected return to service of Units 1 and 2.   
Average spot market power prices in Alberta increased by 207 per cent
to $123 per MWh for the three months ended June 30, 2013 and 88 per
cent to $94 per MWh for the six months ended June 30, 2013, compared
to the same periods in 2012. These increases were mainly the result
of plant outages and increased power demand.  
Western Power's revenue increased by $55 million for the three months
ended June 30, 2013 compared to the same period in 2012 because of
higher purchased PPA volumes and higher realized power prices.  
Western Power's revenue decreased by $27 million for the six months
ended June 30, 2013 compared to the same period in 2012 because of
the Sundance A PPA revenue recorded in first quarter 2012 offset by
higher purchased PPA volumes.   
Western Power's commodity purchases resold increased by $39 million
for the three months ended June 30, 2013 compared to the same period
in 2012 because of higher purchased PPA volumes. Western Power's
commodity purchases resold increased by $10 million for the six
months ended June 30, 2013 compared to the same period in 2012 due to
higher purchased PPA volumes offset by the Sundance A PPA costs
recorded in first quarter 2012.  
Income from Equity Investments increased by $72 million for the three
months ended June 30, 2013 and $71 million for the six months ended
June 30, 2013 compared to the same periods in 2012, respectively.
Higher earnings from ASTC Power Partnership, which holds the Sundance
B PPA, reflected higher Alberta spot power prices and higher earnings
from Portlands Energy were the result of an unplanned outage in
second quarter 2012.   
Plant operating costs and other, which includes natural gas fuel
consumed in power generation, increased by $12 million for the three
months ended June 30, 2013 and $20 million for the six months ended
June 30, 2013 compared to the same periods in 2012, respectively. The
increases were mainly due to higher natural gas fuel prices in 2013.  
Approximately 78 per cent of Western Power sales volumes were sold
under contract this quarter compared to 89 per cent in second quarter
2012. To reduce exposure to spot market prices in Alberta, Western
Power enters into fixed price forward sales to secure future revenue
and a portion of our power is retained to be sold in the spot market
or under shorter-term forward arrangements. The amount sold forward
will vary depending on market conditions and market liquidity and has
historically ranged between 25 to 75 per cent of expected future
production with a higher proportion being hedged in the near term
periods. Such forward sales may be completed with medium and large
industrial and commercial companies and other market participants and
will affect our average realized price (versus spot price) in future
periods. 
BRUCE POWER  
Our proportionate share 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $ unless                                           
 noted otherwise)                       2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Income/(loss) from equity                                                   
 investments(1)                                                             
Bruce A                                   51       (23)        87       (56)
Bruce B                                    8        54          3        74 
----------------------------------------------------------------------------
                                          59        31         90        18 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comprised of:                                                               
  Revenues                               306       185        593       347 
  Operating expenses                    (172)     (125)      (344)     (260)
  Depreciation and other                 (75)      (29)      (159)      (69)
----------------------------------------------------------------------------
                                          59        31         90        18 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bruce Power - Other information                                             
Plant availability(2)                                                       
  Bruce A(3)                              88%       57%        77%       53%
  Bruce B                                 80%       95%        79%       91%
  Combined Bruce Power                    84%       84%        78%       72%
Planned outage days                                                         
  Bruce A                                 33        62        123       153 
  Bruce B                                 70         -        140        46 
Unplanned outage days                                                       
  Bruce A                                  -         -          8         - 
  Bruce B                                  3        19         12        23 
Sales volumes (GWh)(1)                                                      
  Bruce A(3)                           2,464       895      4,561     1,642 
  Bruce B                              1,726     2,047      3,460     3,956 
----------------------------------------------------------------------------
                                       4,190     2,942      8,021     5,598 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized sales price per MWh(4)                                             
  Bruce A                                $71       $68        $70       $67 
  Bruce B                                $54       $56        $53       $55 
  Combined Bruce Power                   $63       $58        $61       $58 
----------------------------------------------------------------------------
                                                                            
(1) Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per 
    cent ownership interest in Bruce B.  Sales volumes exclude deemed       
    generation.                                                             
(2) The percentage of time the plant was available to generate power,       
    regardless of whether it was running.                                   
(3) Plant availability and sales volumes for 2013 include the incremental   
    impact of Units 1 and 2 which were returned to service in October 2012. 
(4) Calculated based on actual and deemed generation. Bruce B realized sales
    prices per MWh includes revenues under the floor price mechanism and    
    revenues from contract settlements.                                     

 
Equity income from Bruce A increased by $74 million for the three
months ended June 30, 2013 and $143 million for the six months ended
June 30, 2013 compared to the same periods in 2012. The increases
were mainly due to: 


 
--  incremental earnings from Units 1 and 2 which returned to service in
    October 2012 
--  higher earnings from Unit 3 due to the West Shift Plus planned outage
    during first and second quarter 2012 
--  recognition in first quarter 2013 of an insurance recovery of
    approximately $40 million related to the May 2012 Unit 2 electrical
    generator failure and the impact the event had on Bruce A in 2012 and
    2013. 

 
These increases were partially offset by the impact of the Unit 4
life extension planned outage which began in August 2012 and was
completed in April 2013.  
Equity income from Bruce B decreased by $46 million for the three
months ended June 30, 2013 and $71 million for the six months ended
June 30, 2013 compared to the same periods in 2012. These decreases
were mainly due to lower volumes and higher operating costs resulting
from higher planned outage days and higher lease expense.  
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. Lease expense recognized in the three and six months ended
June 30, 2012 reflected an annual average spot price below $30 per
MWh. At this time, it is uncertain if the annual average spo
t price
will be below $30 per MWh in 2013 and therefore no reduction to 2013
rent expense was recorded in second quarter 2013.   
Under the contract with the OPA, all of the output from Bruce A is
sold at a fixed price per MWh. The fixed price is adjusted annually
on April 1 for inflation and other provisions under the OPA contract.
Bruce A also recovers fuel costs from the OPA. 


 
----------------------------------------------------------------------------
Bruce A Fixed price                                              Per MWh    
----------------------------------------------------------------------------
                                                                            
April 1, 2013 - March 31, 2014                                    $70.96    
April 1, 2012 - March 31, 2013                                    $68.23    
April 1, 2011 - March 31, 2012                                    $66.33    

 
Under the same contract, all output from Bruce B is subject to a
floor price adjusted annually for inflation on April 1. 


 
----------------------------------------------------------------------------
Bruce B Floor price                                              Per MWh    
----------------------------------------------------------------------------
                                                                            
April 1, 2013 - March 31, 2014                                    $52.34    
April 1, 2012 - March 31, 2013                                    $51.62    
April 1, 2011 - March 31, 2012                                    $50.18    

 
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. We currently expect 2013 spot prices
to be less than the floor price for the year and therefore no amounts
received under the floor price mechanism in 2013 are expected to be
repaid.  
Bruce B also enters into fixed-price contracts under which it
receives or pays the difference between the contract price and the
spot price.  
The overall plant availability percentage in 2013 is expected to be
in the mid 80s for Bruce A and the high 80s for Bruce B. No further
planned maintenance is scheduled for the remainder of 2013. 
U.S. POWER  
Comparable EBITDA and comparable EBIT are non-GAAP measures. See
non-GAAP measures section for more information. 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of US $)          2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Revenue                                                                     
Power(1)                                 317       233        750       428 
Capacity                                  77        66        124       106 
Other(2)                                  17         5         46        24 
----------------------------------------------------------------------------
                                         411       304        920       558 
----------------------------------------------------------------------------
Commodity purchases resold              (197)     (163)      (503)     (280)
Plant operating costs and other(2)      (122)      (92)      (248)     (183)
General, administrative and support                                         
 costs                                   (12)      (11)       (22)      (21)
----------------------------------------------------------------------------
Comparable EBITDA                         80        38        147        74 
Comparable depreciation and                                                 
 amortization                            (23)      (30)       (51)      (60)
----------------------------------------------------------------------------
Comparable EBIT                           57         8         96        14 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) The realized gains and losses from financial derivatives used to buy and
    sell power, natural gas and fuel oil to manage U.S. Power's assets are  
    presented on a net basis in power revenues.                             
(2) Includes revenues and costs related to a third party service agreement  
    at Ravenswood, the activity level of which increased in 2013.           
                                                                            
Sales volumes and plant availability                                        
                                                                            
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited)                             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Physical sales volumes (GWh)                                                
Supply                                                                      
  Generation                           1,761     1,787      2,812     2,941 
  Purchased                            1,878     1,687      4,357     3,257 
----------------------------------------------------------------------------
                                       3,639     3,474      7,169     6,198 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Plant availability(1)                     91%       82%        85%       81%
----------------------------------------------------------------------------
                                                                            
(1) The percentage of time the plant was available to generate power,       
    regardless of whether it was running.                                   

 
U.S. Power's comparable EBITDA was US$80 million for the three months
ended June 30, 2013 and US$147 million for the six months ended June
30, 2013 compared to US$38 million and US$74 million for the same
periods in 2012. These increases included the net effect of: 


 
--  higher realized power prices 
--  higher realized capacity prices in New York 
--  higher revenues on sales to wholesale, commercial and industrial
    customers 
--  higher operating costs due to higher fuel prices. 

 
Commodity prices were higher for the three and six months ended June
30, 2013 compared to the same periods in 2012. In 2012, oversupply
conditions in the North American natural gas market reduced these
prices. In 2013, natural gas prices recovered and storage levels fell
primarily due to colder first quarter weather. The increase in gas
prices has translated into higher spot power prices in the
predominantly gas-fired New England and New York power markets in the
first half of 2013.  
Physical sales volumes for the three and six months ended June 30,
2013 were higher than the same periods in 2012 due to higher
purchased volumes to serve increased sales to wholesale, commercial
and industrial customers in the New England and PJM markets.
Generation volumes were slightly lower, mainly due to lower
generation in our natural gas fueled facilities in both New York and
New England
 partly offset by a higher generation at our hydro
facilities.  
Power revenue was US$317 million for the three months ended June 30,
2013 and US$750 million for the six months ended June 30, 2013
compared to US$233 million and US$428 million for the same periods in
2012. This was mainly due to the combination of higher realized power
prices and higher sales volumes to wholesale, commercial and
industrial customers.  
Capacity revenue was US$77 million for the three months ended June
30, 2013 and US$124 million for the six months ended June 30, 2013
compared to US$66 million and US$106 million for the same periods in
2012. New York Zone J spot capacity prices are approximately 10 per
cent higher than last year on a year to date basis. This increase in
spot capacity prices and the impact of hedging activities resulted in
higher realized prices in New York, partially offset by lower
capacity prices in New England.  
Commodity purchases resold were US$197 million for the three months
ended June 30, 2013 and US$503 million for the six months ended June
30, 2013 compared to US$163 million and US$280 million for the same
periods in 2012 because we purchased higher volumes of power at
higher prices to fulfill increased power sales commitments to
wholesale, commercial and industrial customers at higher realized
power prices.   
Plant operating costs and other, which includes fuel gas consumed in
generation, increased by US$30 million for the three months ended
June 30, 2013 and US$65 million for the six months ended June 30,
2013 compared to the same periods in 2012 because of higher natural
gas fuel prices.   
As at June 30, 2013, approximately 2,200 GWh or 44 per cent of U.S.
Power's planned generation is contracted for the remainder of 2013,
and 2,500 GWh or 28 per cent for 2014. Planned generation fluctuates
depending on hydrology, wind conditions, commodity prices and the
resulting dispatch of the assets. Power sales fluctuate based on
customer usage. 
NATURAL GAS STORAGE  
Comparable EBITDA and comparable EBIT are non-GAAP measures. See
non-GAAP measures section for more information. 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $)             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Alberta Storage(1)                        11        19         31        34 
General, administrative and support                                         
 costs                                    (2)       (2)        (4)       (4)
----------------------------------------------------------------------------
Comparable EBITDA                          9        17         27        30 
Comparable depreciation and                                                 
 amortization                             (2)       (3)        (5)       (6)
----------------------------------------------------------------------------
Comparable EBIT                            7        14         22        24 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Includes our share of equity income from our investment in CrossAlta up 
    to December 18, 2012. On December 18, 2012, we acquired the remaining 40
    per cent interest in CrossAlta, bringing our ownership interest to 100  
    per cent.                                                               

 
Comparable EBITDA decreased by $8 million for the three months ended
June 30, 2013 and $3 million for the six months ended June 30, 2013
compared to the same periods in 2012 because of lower realized
natural gas storage spreads partially offset by incremental earnings
from CrossAlta resulting from the acquisition of the remaining 40 per
cent interest in December 2012. 
Recent developments 
NATURAL GAS PIPELINES 
NEB decision on the Canadian Restructuring Proposal  
On March 27, 2013, the NEB issued its decision on our application to
change the business structure and the terms and conditions of service
for the Canadian Mainline, including tolls for 2012 and 2013. The
decision significantly alters the regulatory framework that has
formed the basis for more than $10 billion of regulated pipeline
investment over the last sixty years.  
On May 1, 2013, we filed an application for a review and variance of
the decision and order. The NEB dismissed the review and variance
application on June 11, 2013, and released its reasons for the
dismissal on July 22, 2013. The NEB did however recognize that
changes proposed by us to the Canadian Mainline's Tariff would be
considered as a separate application through an oral hearing process
to be heard in September.  
We are effectively operating under the new decision environment as of
July 1. We have submitted the tariff change application and will
manage that process through the oral hearing and await a decision on
those changes. 
NGTL System expansion projects  
We continued to expand the NGTL System (formerly known as the Alberta
System) and have placed $700 million of new facilities in service in
2013. We have applied and received approval from the NEB for an
additional $130 million of new facilities. To date in 2013, we have
applied for an additional $145 million of facilities that remain
subject to NEB approval. We are planning regulatory applications for
further expansion into B.C. and estimate the cost of the facilities
to be between $1.0 billion and $1.5 billion to connect and transport
new gas supply that will be delivered to the Prince Rupert Gas
Transmission Project (PRGT) as well as other markets served by the
NGTL System. In third quarter 2013, we expect to begin an open season
to provide delivery service through a transportation by others
arrangement on Coastal GasLink to Vanderhoof, B.C. 
Prince Rupert Gas Transmission Project  
The British Columbia Environmental Assessment Office issued its
Section 10 Order in June 2013 indicating that the project is
reviewable and requires an environmental assessment certificate. The
Canadian Environmental Assessment Agency (CEAA) initiated the public
comment period with respect to the project in June 2013. 
Coastal GasLink Pipeline Project  
We are currently focused on community, landowner, government and
First Nations engagement as the Coastal GasLink pipeline project
advances through the regulatory process with the B.C. Environmental
Assessment Office and the CEAA.  
Portland Natural Gas Transmission System  
We concluded an open season in June 2013 with certain markets
throughout the Northeast U.S. and Atlantic Canada expressing interest
and others indicating an interest in turning back portions of our
capacity. The interest generated for incremental capacity did not
meet the threshold level required to go forward with an increase in
capacity at this time. PNGTS continues to look for market
opportunities to further develop growth of the system.  
Sale of U.S. Pipeline assets to TC PipeLines, LP  
In July 2013, we closed the sale of a 45 per cent interest in each of
Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC
(Bison LLC) to TC PipeLines, LP for an aggregate purchase price of
US$1.05 billion, which included US$146 million representing 45 per
cent of GTN's debt, plus closing adjustments for working capital of
$17 million.  
Through our subsidiaries, we continue to hold a 30 per cent direct
ownership interest in both pipelines. We also hold 28.9 per cent
interest in TC PipeLines, LP and are the General Partner. 
Mexican Pipelines  
The construction of the Tamazunchale Pipeline Extension project and
related compression facilities is proceeding. The Topolobampo and
Mazatlan projects in northwest Mexico are advancing as planned with
engineering and permitting activities. 
OIL PIPELINES 
Gulf Coast Project  
We are constructing a 36-inch pipeline from Cushing, Oklahoma to the
U.S. Gulf Coast and expect to begin delivering crude oil to Port
Arthur, Texas at the end of 2013. Construction is approximately 85
per cent complete and we estimate the cost of the Cushing to Port
Arthur facilities to be US$2.3 billion.  
Construction of the 76 km (47 mile) Houston Lateral pipeline to
transport crude oil to Houston refineries is expected to be complete
in 2014 at a cost of US$300 million.  
The Gulf Coast Project will have a capacity of up to 700,000 barrels
per day. 
Keystone XL Pipeline  
In January 2013, the Governor of Nebraska approved our proposed
re-route after the Nebraska Department of Environmental Quality
issued its final evaluation report noting that construction and
operation of Keystone XL is expected to have minimal environmental
impacts in Nebraska.  
On March 1, 2013, the U.S. DOS released its Draft Supplemental
Environmental Impact Statement for the Keystone XL Pipeline. The
impact statement reaffirmed that construction of the proposed
pipeline from the U.S./Canada border in Montana to Steele City,
Nebraska would not result in any significant impact to the
environment. The DOS continues to review comments on the impact
statement that it received during a public comment period that ended
on April 22, 2013. Once the DOS has completed its review, it is
anticipated it will issue a Final Supplemental Environmental Impact
Statement and then consult with other governmental agencies and
provide an additional opportunity for the public comment during a
National Interest Determination period of up to 90 days, before
making a decision on our Presidential Permit application.  
We now anticipate the pipeline to be in service approximately two
years following the receipt of the Presidential Permit. The US$5.3
billion cost estimate will increase depending on the timing of the
permit. As of June 30, 2013, we had invested US$1.9 billion in the
project. 
Energy East Pipeline  
On June 17, 2013, we concluded an open season to obtain firm
commitments for a pipeline to transport up to 850,000 Bbl/d of crude
oil from western receipt points to eastern Canadian markets and are
currently reviewing the results.  
The Energy East Pipeline project involves converting natural gas
pipeline capacity in approximately 3,000 km (1,870 miles) of our
existing Canadian Mainline to crude oil service and constructing up
to approximately 1,400 km (870 miles) of new pipeline.  
We have begun Aboriginal and stakeholder engagement and associated
field work as part of our initial design and planning. If we
determine that there is sufficient commercial support for the
project, we will apply for regulatory approval to build and operate
the facilities, with a potential in-service date of late 2017. 
Northern Courier Pipeline  
On April 25, 2013, we filed a permit application with the Alberta
Energy Regulator after completing the required Aboriginal and
stakeholder engagement and associated field work. We continue to work
with the Fort Hills Energy Limited Partnership on the development of
this project. 
Heartland Pipeline and TC Terminals  
On May 2, 2013, we announced we had reached binding long-term
shipping agreements to build, own and operate the proposed Heartland
Pipeline and TC Terminals projects.  
The proposed projects will include a 200 km (125 mile) crude oil
pipeline connecting the Edmonton region to facilities in Hardisty,
Alberta, and a terminal facility in the Heartland industrial area
north of Edmonton. We anticipate the pipeline could transport up to
900,000 Bbl/d, while the terminal is expected to have storage
capacity for up to 1.9 million barrels of crude oil. These projects
together have a combined cost estimated at $900 million and are
expected to come into service during the second half of 2015.  
On May 30, 2013, we filed a permit application for the terminal
facility with the Alberta Energy Regulator and expect to file an
application for the pipeline later in 2013. 
Grand Rapids Pipeline  
On May 23, 2013, we filed a permit application with the Alberta
Energy Regulator after completing the required Aboriginal and
stakeholder engagement and associated field work. 
ENERGY 
Ontario Solar  
In late 2011, we agreed to buy nine Ontario solar projects (combined
capacity of 86 MW) from Canadian Solar Solutions Inc. for
approximately $470 million. On June 28, 2013, we completed the
acquisition of the first project for $55 million. We expect to close
the acquisition of the remaining projects in 2013 and 2014, subject
to satisfactory completion of the related construction activities and
regulatory approvals. All power produced will be sold under 20-year
PPAs with the OPA. 
Sundance A  
TransAlta previously announced that it expected Sundance A Units 1
and 2 to be returned to service in the fall of 2013. They
subsequently reported an earlier return to service date for Unit 1 of
July 31, 2013. TransAlta has not announced any change in the return
to service date for Unit 2. 
Bruce Power  
Bruce Power returned Unit 4 to service on April 13, 2013 after
completing an expanded life extension outage investment program which
began in August 2012. It is anticipated that this investment will
allow Unit 4 to operate until at least 2021.  
On April 5, 2013, Bruce Power announced that it had reached an
agreement with the OPA to extend the Bruce B floor price through to
the end of the decade which is expected to coincide with the 2019 and
2020 end of life dates for the Bruce B units. 
Becancour  
In June 2013, Hydro-Quebec notified us that it would exercise its
option to extend the agreement to suspend all electricity generation
from the Becancour power plant through 2014. Under the suspension
agreement, Hydro-Quebec has the option (subject to certain
conditions) to extend the suspension every year until regional
electricity demand levels recover. We continue to receive capacity
payments while generation is suspended. 
Other income statement items 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $)             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Comparable interest expense             (252)     (239)      (509)     (481)
Comparable interest income and                                              
 other                                    (2)       19         16        44 
Comparable income taxes                 (133)      (91)      (292)     (231)
Net income attributable to non-                                             
 controlling interests                   (23)      (26)       (54)      (61)
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $)             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Comparable interest on long-term                                            
 debt(including interest on junior                                          
 subordinated notes)                                                        
Canadian dollar-denominated              123       127        245       255 
U.S. dollar-denominated (US$)            185       183        373       369 
Foreign exchange                           5         -          6         - 
----------------------------------------------------------------------------
                                         313       310        624       624 
Other interest and amortization                                             
 expense                                  (1)        5          -         7 
Capitalized interest                     (60)      (76)      (115)     (150)
----------------------------------------------------------------------------
Comparable interest expense              252       239        509       481 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Comparable interest expense was $252 million for the three months
ended June 30, 2013 and $509 million for the six months ended June
30, 2013 compared to $239 million and $481 million for the same
periods in 2012 because of the following: 


 
--  lower capitalized interest as a result of placing the refurbished units
    at Bruce Power in service, partially offset by increased capitalized
    interest for the Gulf Coast Project 
--  lower interest expense due to Canadian and U.S. dollar-denominated debt
    maturities, partially offset by debt issues of US$750 million in January
    2013, US$1 billion in August 2012 and US$500 million in March 2012. 

 
Comparable interest income and other was a loss of $2 million for the
three months ended June 30, 2013 and a gain of $16 million for the
six months ended June 30, 2013 compared to gains of $19 million and
$44 million for the same periods in 2012 because we had realized
losses in 2013 compared to realized gains in 2012 on derivatives used
to manage our net exposure to foreign exchange rate fluctuations on
U.S. dollar-denominated income.  
Comparable income taxes were $133 million for the three months ended
June 30, 2013 and $292 million for the six months ended June 30, 2013
compared to $91 million and $231 million for the same periods in
2012. The increase was mainly the result of higher pre-tax earnings
in 2013 compared to 2012 combined with changes in the proportion of
income earned between Canadian and foreign jurisdictions. 
Financial condition  
We strive to maintain financial strength and flexibility in all parts
of an economic cycle, and rely on our operating cash flows to sustain
our business, pay dividends and fund a portion of our growth.  
We access capital markets to meet our financing needs, manage our
capital structure and preserve our credit ratings.  
We believe we have the capacity to fund our existing capital program
through predictable cash flow from our operations, access to the
capital markets, cash on hand and substantial committed credit
facilities.  
CASH FROM OPERATING ACTIVITIES 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                          June 30             June 30       
                                   -------------------- --------------------
(unaudited - millions of $)             2013       2012      2013      2012 
----------------------------------------------------------------------------
                                                                            
Funds generated from operations(1)       955        729     1,871     1,600 
(Increase)/decrease in operating                                            
 working capital                        (114)        14      (324)     (155)
----------------------------------------------------------------------------
Net cash provided by operations          841        743     1,547     1,445 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) See the non-GAAP measures section in this MD&A for further discussion of
    funds generated from operations.                                        

 
Net cash provided by operations was $841 million for the three months
ended June 30, 2013 and $1,547 million for the six months ended June
30, 2013 compared to $743 million and $1,445 million for the same
periods in 2012, respectively, as a result of our increase in
earnings, partly offset by increases in operating working capital.  
At June 30, 2013, our current assets were $2.8 billion and current
liabilities were $6.7 billion, leaving us with a working capital
deficit of $3.9 billion compared to $3.1 billion at the end of 2012.
This working capital deficiency is considered to be in the normal
course of business and is managed through our ability to generate
cash flow and our ongoing access to the capital markets. 
CASH USED IN INVESTING ACTIVITIES 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                          June 30              June 30      
                                   -------------------- --------------------
(unaudited - millions of $)              2013      2012       2013      2012
----------------------------------------------------------------------------
                                                                            
Capital expenditures                    1,109       397      2,038       861
Equity investments                         39       197         71       413
Acquisition                                55         -         55         -
----------------------------------------------------------------------------

 
Our capital expenditures this quarter were primarily related to the
Gulf Coast Project, expansion of the NGTL System and construction of
the Mexican pipelines.  
On June 28, 2013, we completed the acquisition of the first Ontario
Solar project for $55 million. 
CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of $)             2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
Long-term debt issued, net of issue                                         
 costs                                    10         1        744       493 
Long-term debt repaid                   (695)     (222)      (709)     (770)
Notes payable issued, net              1,388       635        559       589 
Dividends and distributions paid        (386)     (359)      (736)     (702)
Equity financing activities              406         4      1,024        18 
----------------------------------------------------------------------------

 
In January 2013, we issued US$750 million of senior notes, maturing
on January 15, 2016 and bearing interest at 0.75 per cent. These
notes were issued under the US$4.0 billion debt shelf prospectus
filed in November 2011.  
In March 2013, we completed a public offering of 24 million Series 7
cumulative redeemable first preferred shares at a price of $25 per
share for aggregate gross proceeds of $600 million. Investors will be
entitled to receive fixed cumulative dividends at an annual rate of
$1.00 per share, payable quarterly. Investors will have the right to
convert their shares into cumulative redeemable first preferred
shares, Series 8, every fifth year beginning on April 30, 2019. The
holders of Series 8 shares will be entitled to receive quarterly
floating rate cumulative dividends at an annualized rate equal to the
then 90 day Government of Canada treasury bill rate plus 2.38 per
cent.  
In June 2013, we retired $350 million of 4.00 per cent senior notes.  
In July 2013, we issued US$500 million of three-year London Interbank
Offered Rate-based floating rate notes maturing on June 30, 2016,
bearing interest at an initial annual rate of 0.95 per cent.  
Also in July 2013, we issued $450 million of ten-year and $300
million of 30-year medium term notes maturing on July 19, 2023 and
November 15, 2041, bearing interest rates of 3.69 and 4.55 per cent
per annum, respectively. The net proceeds of these offerings are
intended to be used for general corporate purposes and to reduce
short-term indebtedness, which was used to fund a portion of our
capital program.  
In May 2013, TC PipeLines, LP completed a public offering of
8,855,000 common units at US$43.85 per common unit for gross proceeds
of US$388 million. We contributed an additional approximate US$8
million to maintain our general partnership interest and did not
purchase any other units. Upon completion of this offering, our
ownership interest in TC PipeLines, LP decreased from 33.3 per cent
to 28.9 per cent.  
In July 2013, TC PipeLines, LP entered into a five-year, US$500
million term loan, maturing July 2018. The proceeds from the public
offering, term loan and partner contribution were used to finance the
acquisition of the 45 per cent interest in GTN and Bison from us. 
DIVIDENDS  
On July 25, 2013 we declared quarterly dividends as follows: 


 
----------------------------------------------------------------------------
Quarterly dividend on our common shares                                     
----------------------------------------------------------------------------
                                                                            
$0.46 per share (for the quarter ending September 30, 2013)                 
Payable on October 31, 2013 to shareholders of record at the close of       
 business on September 30, 2013                                             
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
Quarterly dividends on our preferred shares                                 
----------------------------------------------------------------------------
                                                                            
Series 1 $0.2875 (for the quarter ending September 30, 2013)                
Series 3 $0.25 (for the quarter ending September 30, 2013)                  
Payable on September 30, 2013 to shareholders of record at the close of     
 business on September 3, 2013                                              
Series 5 $0.275 (for the three month period ending October 30, 2013)        
Series 7 $0.25 (for the three month period ending October 30, 2013)         
Payable on October 30, 2013 to shareholders of record at the close of       
 business on September 30, 2013                                             
----------------------------------------------------------------------------
                                                                            
SHARE INFORMATION                                                           
                                                                            
----------------------------------------------------------------------------
at July 22, 2013                                                            
----------------------------------------------------------------------------
                                                                            
Common shares                    Issued and outstanding                     
                                            707 million                     
----------------------------------------------------------------------------
Preferred shares                 Issued and outstanding       Convertible to
Series 1                                     22 million  22 million Series 2
                                                            preferred shares
Series 3                                     14 million  14 million Series 4
                                                            preferred shares
Series 5                                     14 million  14 million Series 6
                                                            preferred shares
Series 7                                     24 million  24 million Series 8
                                                            preferred shares
----------------------------------------------------------------------------
Options to buy common shares                Outstanding          Exercisable
                                              8 million            4 million
----------------------------------------------------------------------------

 
CREDIT FACILITIES  
We use committed, revolving credit facilities to support our
commercial paper programs along with additional demand facilities for
general corporate purposes including issuing letters of credit and
providing additional liquidity.  
At June 30, 2013, we had $5 billion in unsecured credit facilities,
including: 


 
----------------------------------------------------------------------------
           Unused                                                           
Amount     capacity   Subsidiary           For                  Matures     
----------------------------------------------------------------------------
                                                                            
$2.0       $2.0       TransCanada          Committed,           October 2017
billion    billion    PipeLines Limited    revolving,                       
                      (TCPL)               extendible credit                
                                           facility that                    
                                           supports TCPL's                  
                                           Canadian commercial              
                                           paper program                    
----------------------------------------------------------------------------
US$1.0     US$1.0     TransCanada PipeLine Committed,           October 2013
billion    billion    USA Ltd. (TCPL USA)  revolving,                       
                                           extendible credit                
                                           facility that                    
                                           supports a TCPL USA              
                                           U.S. dollar                      
                                           commercial paper                 
                                           program in the U.S.              
----------------------------------------------------------------------------
US$1.0     US$1.0     TransCanada Keystone Committed,           November    
billion    billion    Pipeline, LP         revolving,           2013        
                                           extendible credit                
                                           facility that                    
                                           supports a U.S.                  
                                           dollar commercial                
                                           paper program in                 
                                           Canada dedicated to              
                                           funding a portion of             
                                           Keystone                         
----------------------------------------------------------------------------
$0.9       $330       TCPL,                Demand lines for     Demand      
billion,   million    TCPL USA             issuing letters of               
US$0.1                                     credit and as a                  
billion                                    source of additional             
                                           liquidity. At June               
                                           30, 2013, we had                 
                                           outstanding $670                 
                                           million in letters               
                                           of credit under                  
                                           these lines                      
----------------------------------------------------------------------------

 
See Risks and financial instruments for more information about
liquidity, market and other risks. 
CONTRACTUAL OBLIGATIONS  
Our capital commitments have decreased by $600 million primarily due
to the completion or advancement of capital projects. Our other
purchase commitments decreased by $180 million. There were no other
material changes to our contractual obligations in second quarter
2013 or to payments due in the next five years or after. See the MD&A
in our 2012 Annual Report for more information about our contractual
obligations. 
Financial risks and financial instruments  
We are exposed to liquidity risk, counterparty credit risk and market
risk, and have strategies, policies and limits in place to mitigate
their impact on our earnings, cash flow and ultimately shareholder
value. These are designed to ensure our risks and related exposures
are in line with our business objectives and risk tolerance.  
Please see our 2012 Annual Report for more information about the
risks we face in our business. In addition to those disclosed risks,
in the NEB's March 2013 decision on our Canadian Restructuring
Proposal, the NEB found that the fundamental business risk facing the
Canadian Mainline has increased. The tolling framework created by the
NEB decision results in higher variability in cash flows and greater
uncertainty about the ultimate recovery of the Canadian Mainline's
cost of service. Otherwise, our risks have not changed substantially
since December 31, 2012. 
LIQUIDITY RISK  
We manage our liquidity risk by continuously forecasting our cash
requirements for a 12 month period and making sure we have adequate
cash balances, cash flow from operations, committed and demand credit
facilities and access to capital markets to meet our operating,
financing and capital expenditure obligations under both normal and
stressed economic conditions. 
COUNTERPARTY CREDIT RISK  
We have exposure to counterparty credit risk in the following areas: 


 
--  accounts receivable 
--  portfolio investments 
--  the fair value of derivative assets 
--  notes, loans and advances receivable. 

 
We review our accounts receivable regularly and record allowances for
doubtful accounts using the specific identification method. At June
30, 2013, we had not incurred any significant credit losses and had
no significant amounts past due or impaired. We had a credit risk
concentration of $263 million with one counterparty at June 30, 2013
(December 31, 2012 - $259 million). This amount is secured by a
guarantee from the counterparty's parent company and we anticipate
collecting the full amount.  
We have significant credit and performance exposure to financial
institutions because they hold cash deposits and provide committed
credit lines and letters of credit that help manage our exposure to
counterparties and provide liquidity in commodity, foreign exchange
and interest rate derivative markets. 
FOREIGN EXCHANGE RISK  
Certain of our businesses generate income in U.S. dollars, but since
we report in Canadian dollars, changes in the value of the U.S.
dollar against the Canadian dollar can affect our net income. As our
U.S. operations continue to grow, our exposure to changes in currency
rates increases. Some of this risk is offset by interest expense on
U.S. dollar-denominated debt and by using foreign exchange
derivatives.  
We use foreign exchange derivatives to manage other foreign exchange
transactions, including foreign exchange exposures that arise on some
of our regulated assets. We defer some of the realized gains and
losses on these derivatives as regulatory assets and liabilities
until we recover or pay them to shippers according to the terms of
the shipping agreements. 
AVERAGE EXCHANGE RATE - U.S. TO CANADIAN DOLLARS 


 
---------------------------------------------
Second quarter 2013                      1.03
Second quarter 2012                      1.01
---------------------------------------------

 
The impact of changes in the value of the U.S. dollar on our U.S.
operations is significantly offset by other U.S. dollar-denominated
items, as set out in the table below. Comparable EBIT is a non-GAAP
measure.  
SIGNIFICANT U.S. DOLLAR-DENOMINATED AMOUNTS 


 
----------------------------------------------------------------------------
                                    three months ended    six months ended  
                                         June 30              June 30       
                                   -------------------- --------------------
(unaudited - millions of US$)           2013      2012       2013      2012 
----------------------------------------------------------------------------
                                                                            
U.S. and International Natural Gas                                          
 Pipelines comparable EBIT               101       147        301       362 
U.S. Oil Pipelines comparable EBIT        95        88        189       177 
U.S. Power comparable EBIT                57         8         96        14 
Interest expense on U.S. dollar-                                            
 denominated long-term debt             (185)     (183)      (373)     (369)
Capitalized interest on U.S.                                                
 capital expenditures                     49        27         93        53 
U.S. non-controlling interests and                                          
 other                                   (39)      (45)       (87)      (96)
----------------------------------------------------------------------------
                                          78        42        219       141 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
NET INVESTMENT IN FOREIGN OPERATIONS  
We hedge our net investment in foreign operations (on an after-tax
basis) with U.S. dollar-denominated debt, cross-currency interest
rate swaps, forward foreign exchange contracts and foreign exchange
options. The fair values and notional amounts for the derivatives
designated as a net investment hedge were as follows: 


 
----------------------------------------------------------------------------
                                       June 30, 2013      December 31, 2012 
                                   -------------------- --------------------
Asset/(liability)                       Fair   Notional       Fair  Notional
(unaudited - millions of $)         value(1)     amount   value(1)    amount
----------------------------------------------------------------------------
                                                                            
U.S. dollar cross-currency swaps                                            
(maturing 2013 to 2019)(2)              (137)  US 3,900         82  US 3,800
U.S. dollar forward foreign                                                 
 exchange contracts                                                         
(maturing 2013 to 2014)                  (29)  US 1,050          -    US 250
----------------------------------------------------------------------------
                                        (166)  US 4,950         82  US 4,050
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Fair values equal carrying values.                                      
(2) Net Income in the three and six months ended June 30, 2013 included net 
    realized gains of $7 million and $14 million, respectively, (2012 -     
    gains of $7 million and $14 million, respectively) related to the       
    interest component of cross-currency swap settlements.                  

 
U.S. DOLLAR-DENOMINATED DEBT DESIGNATED AS A NET INVESTMENT HEDGE 


 
----------------------------------------------------------------------------
(unaudited - billions of $)               June 30, 2013   December 31, 2012 
----------------------------------------------------------------------------
                                                                            
Carrying value                            12.2 (US 11.7)      11.1 (US 11.2)
Fair value                                14.2 (US 13.5)      14.3 (US 14.4)
----------------------------------------------------------------------------

 
FAIR VALUE OF DERIVATIVES USED TO HEDGE OUR 
U.S. DOLLAR INVESTMENT IN FOREIGN OPERATIONS  
The classification of the fair value of derivatives to hedge our net
investments on the balance sheet. 


 
----------------------------------------------------------------------------
(unaudited - millions of $)                June 30, 2013   December 31, 2012
----------------------------------------------------------------------------
                                                                            
Other current assets                                  30                  71
Intangible and other assets                            2                  47
Accounts payable and other                            52                   6
Other long-term liabilities                          146                  30
----------------------------------------------------------------------------
                                                                            
NON-DERIVATIVE FINANCIAL INSTRUMENTS SUMMARY                                
                                                                            
----------------------------------------------------------------------------
                                       June 30, 2013      December 31, 2012 
                                   -------------------- --------------------
                                     Carrying      Fair   Carrying      Fair
(unaudited - millions of $)         amount(1)  value(2)  amount(1)  value(2)
----------------------------------------------------------------------------
                                                                            
Financial assets                                                            
Cash and cash equivalents                 674       674        551       551
Accounts receivable and other(3)        1,301     1,350      1,288     1,337
Available for sale assets                  47        47         44        44
----------------------------------------------------------------------------
                                        2,022     2,071      1,883     1,932
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial liabilities(4)                                                    
Notes payable                           2,900     2,900      2,275     2,275
Accounts payable and other long-                                            
 term liabilities(5)                    1,114     1,114      1,535     1,535
Accrued interest                          380       380        368       368
Long-term debt                         19,699    23,474     18,913    24,573
Junior subordinated notes               1,050     1,105        994     1,054
----------------------------------------------------------------------------
                                       25,143    28,973     24,085    29,805
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Recorded at amortized cost, except for US$200 million (December 31, 2012
    - US$350 million) of long-term debt that is attributed to hedged risk   
    and recorded at fair value. This debt, which is recorded at fair value  
    on a recurring basis, is classified in Level II of the fair value       
    hierarchy using the income approach based on interest rates from        
    external data service providers.                                        
(2) The fair value measurement of financial assets and liabilities recorded 
    at amortized cost for which 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 June 30, 2013, financial assets of $1.1 billion (December 31, 2012 - 
    $1.1 billion) are included in accounts receivable, $72 million (December
    31, 2012 - $40 million) in other current assets and $225 million        
    (December 31, 2012 - $240 million) in intangible and other assets.      
(4) Condensed consolidated statement of income in the three and six months  
    ended June 30, 2013 included gains of $3 million and losses of $7       
    million, respectively, (2012 - gains of $3 million and losses of $12    
    million, respectively) for fair value adjustments attributable to the   
    hedged interest rate risk associated with interest rate swap fair value 
    hedging relationships on US$200 million of long-term debt at June 30,   
    2013 (December 31, 2012 - US$350 million). There were no other          
    unrealized gains or losses from fair value adjustments to the non-      
    derivative financial instruments.                                       
(5) At June 30, 2013, financial liabilities of $1.1 billion (December 31,   
    2012 - $1.5 billion) are included in accounts payable and $36 million   
    (December 31, 2012 - $38 million) in other long-term liabilities.       

 
DERIVATIVE INSTRUMENTS SUMMARY  
The following summary does not include hedges of our net investment
in foreign operations. 


 
----------------------------------------------------------------------------
2013                                                                        
(unaudited - millions of $                  Natural     Foreign             
 unless noted otherwise)          Power         gas    exchange    Interest 
----------------------------------------------------------------------------
                                                                            
Derivative instruments held                                                 
 for trading(1)                                                             
Fair values(2)                                                              
  Assets                           $141         $70          $-         $11 
  Liabilities                     $(183)       $(99)       $(17)       $(11)
Notional values                                                             
  Volumes(3)                                                                
    Sales                        35,445          64           -           - 
    Purchases                    34,750         102           -           - 
  Canadian dollars                    -           -           -         620 
  U.S. dollars                        -           -    US 1,274      US 200 
Net unrealized                                                              
 gains/(losses) in the                                                      
 period(4)                                                                  
  three months ended June                                                   
   30, 2013                          $5        $(21)       $(10)         $- 
  six months ended June 30,                                                 
   2013                             $(3)       $(12)       $(16)         $- 
Net realized losses in the                                                  
 period(4)                                                                  
  three months ended June                                                   
   30, 2013                        $(29)        $(5)        $(6)         $- 
  six months ended June 30,                                                 
   2013                            $(36)        $(7)        $(7)         $- 
Maturity dates                2013-2017   2013-2016   2013-2014   2013-2016 
----------------------------------------------------------------------------
Derivative instruments in                                                   
 hedging relationships(5,6)                                                 
Fair values(2)                                                              
  Assets                            $37          $-          $-          $7 
  Liabilities                     $(103)        $(1)        $(1)         $- 
Notional values                                                             
  Volumes(3)                                                                
    Sales                         6,283           -           -           - 
    Purchases                    13,206           -           -           - 
  U.S. dollars                        -           -       US 15      US 200 
  Cross-currency                      -           -           -           - 
Net realized (losses)/gains                                                 
 in the period(4)                                                           
  three months ended June                                                   
   30, 2013                        $(84)        $(1)         $-          $2 
  six months ended June 30,                                                 
   2013                            $(11)        $(1)         $-          $4 
Maturity dates                2013-2018        2013        2014        2015 
----------------------------------------------------------------------------
                                                                            
(1) All derivative instruments held for trading have been entered into for  
    risk management purposes and are subject to our risk management         
    strategies, policies and limits. These include derivatives that have not
    been designated as hedges or do not qualify for hedge accounting        
    treatment but have been entered into as economic hedges to manage our   
    exposure to market risk.                                                
(2) Fair values equal carrying values.                                      
(3) Volumes for power and natural gas derivatives are in GWh and Bcf,       
    respectively.                                                           
(4) Realized and unrealized gains and losses on held for trading derivative 
    instruments used to purchase and sell power and natural gas are included
    net in revenues. Realized and unrealized gains and losses on interest   
    rate and foreign exchange derivative financial instruments held for     
    trading are included in interest expense and interest income and other, 
    respectively. The effective portion of the change in fair value of      
    derivative instruments in hedging relationships is initially recognized 
    in OCI and reclassified to revenues, interest expense and interest      
    income and other, as appropriate, as the original hedged item settles.  
(5) All hedging relationships are designated as cash flow hedges except for 
    interest rate derivative financial instruments designated as fair value 
    hedges with a fair value of $7 million and a notional amount of US$200  
    million. For the three and six months ended June 30, 2013, net realized 
    gains on fair value hedges were $2 million and $4 million, respectively,
    and were included in interest expense. For the three and six months     
    ended June 30, 2013, we did not record any amounts in net income related
    to ineffectiveness for fair value hedges.                               
(6) For the three and six months ended June 30, 2013, there were no gains or
    losses included in net income relating to discontinued cash flow hedges 
    where it was probable that the anticipated transaction would not occur. 

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


 
----------------------------------------------------------------------------
2012                                                                        
(unaudited - millions of $ unless             Natural     Foreign           
 noted otherwise)                     Power       gas    exchange  Interest 
----------------------------------------------------------------------------
                                                                            
Derivative instruments held for                                             
 trading(1)                                                                 
Fair values(2,3)                                                            
  Assets                               $139       $88          $1       $14 
  Liabilities                         $(176)    $(104)        $(2)     $(14)
Notional values(3)                                                          
  Volumes(4)                                                                
    Sales                            31,066        65           -         - 
    Purchases                        31,135        83           -         - 
  Canadian dollars                        -         -           -       620 
  U.S. dollars                            -         -    US 1,408    US 200 
Net unrealized (losses)/gains in                                            
 the period(5)                                                              
  three months ended June 30, 2012     $(12)       $4        $(14)       $- 
  six months ended June 30, 2012       $(19)     $(10)        $(8)       $- 
Net realized (losses)/gains in the                                          
 period(5)                                                                  
  three months ended June 30, 2012      $(6)      $(5)         $6        $- 
  six months ended June 30, 2012         $9      $(15)        $15        $- 
Maturity dates                    2013-2017 2013-2016        2013 2013-2016 
----------------------------------------------------------------------------
Derivative instruments in hedging                                           
 relationships(6,7)                                                         
Fair values(2,3)                                                            
  Assets                                $76        $-          $-       $10 
  Liabilities                          $(97)      $(2)       $(38)       $- 
Notional values(3)                                                          
  Volumes(4)                                                                
    Sales                             7,200         -           -         - 
    Purchases                        15,184         1           -         - 
  U.S. dollars                            -         -       US 12    US 350 
  Cross-currency                          -         -  136/US 100         - 
Net realized (losses)/gains in the                                          
 period(5)                                                                  
  three months ended June 30, 2012     $(26)      $(8)         $-        $2 
  six months ended June 30, 2012       $(58)     $(14)         $-        $3 
Maturity dates                    2013-2018      2013   2013-2014 2013-2015 
----------------------------------------------------------------------------
                                                                            
(1) All derivative instruments held for trading have been entered into for  
    risk management purposes and are subject to our risk management         
    strategies, policies and limits. This includes derivatives that have not
    been designated as hedges or do not qualify for hedge accounting        
    treatment but have been entered into as economic hedges to manage our   
    exposure to market risk.                                                
(2) Fair values equal carrying values.                                      
(3) As at December 31, 2012.                                                
(4) Volumes for power and natural gas derivatives are in GWh and Bcf,       
    respectively.                                                           
(5) Realized and unrealized gains and losses on held for trading derivative 
    instruments used to purchase and sell power and natural gas are included
    net in revenues. Realized and unrealized gains and losses on interest   
    rate and foreign exchange derivative financial instruments held for     
    trading are included in interest expense and interest income and other, 
    respectively. The effective portion of the change in fair value of      
    derivative instruments in hedging relationships is initially recognized 
    in OCI and reclassified to revenues, interest expense and interest      
    income and other, as appropriate, as the original hedged item settles.  
(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 $10 million and a notional amount of US$350 
    million. Net realized gains on fair value hedges for the three and six  
    months ended June 30, 2012 were $2 million and $4 million, respectively,
    and were included in Interest expense. In the three and six months ended
    June 30, 2012, we did not record any amounts in Net Income related to   
    ineffectiveness for fair value hedges.                                  
(7) For the three and six months ended June 30, 2012, there were no gains or
    losses included in net income relating to discontinued cash flow hedges 
    where it was probable that the anticipated transaction would not occur. 

 
BALANCE SHEET PRESENTATION OF DERIVATIVE INSTRUMENTS 
The fair value of the derivative instruments on the balance sheet.  


 
----------------------------------------------------------------------------
(unaudited - millions of $)              June 30, 2013    December 31, 2012 
----------------------------------------------------------------------------
                                                                            
Current                                                                     
Other current assets                               187                  259 
Accounts payable and other                        (341)                (283)
Long term                                                                   
Intangible and other assets                        111                  187 
Other long-term liabilities                       (272)                (186)
----------------------------------------------------------------------------

 
DERIVATIVES IN CASH FLOW HEDGING RELATIONSHIPS  
The components of other comprehensive income (OCI) related to
derivatives in cash flow hedging relationships.  


 
----------------------------------------------------------------------------
Cash flow hedges(1)                        Natural     Foreign              
three months ended June 30      Power        gas       exchange    Interest 
                            ------------ ----------- ----------- -----------
(unaudited - millions of $,                                                 
 pre-tax)                    2013   2012  2013 2012   2013  2012  2013  2012
----------------------------------------------------------------------------
                                                                            
Change in fair value of                                                     
 derivative instruments                                                     
 recognized in OCI                                                          
 (effective portion)          (70)    44     -   (4)     2     4     -     -
Reclassification of gains                                                   
 and losses on derivative                                                   
 instruments from AOCI to                                                   
 net income (effective                                                      
 portion)                      12     28     2   15      -     -     4     4
Gains and losses on                                                         
 derivative instruments                                                     
 recognized in earnings                                                     
 (ineffective portion)         (2)     7     -    1      -     -     -     -
----------------------------------------------------------------------------
                                                                            
(1) No amounts have been excluded from the assessment of hedge              
    effectiveness.                                                          
                                                                            
----------------------------------------------------------------------------
Cash flow hedges(1)                        Natural     Foreign              
six months ended June 30        Power        gas       exchange    Interest 
                            ------------ ----------- ----------- -----------
(unaudited - millions of $,                                                 
 pre-tax)                    2013  2012   2013 2012   2013  2012  2013  2012
----------------------------------------------------------------------------
                                                                            
Change in fair value of                                                     
 derivative instruments                                                     
 recognized in OCI                                                          
 (effective portion)          (34)  (22)     -  (14)     4     1     -     -
Reclassification of gains                                                   
 and losses on derivative                                                   
 instruments from AOCI to                                                   
 net income (effective                                                      
 portion)                       1    75      2   28      -     -     8    10
Gains and losses on                                                         
 derivative instruments                                                     
 recognized in earnings                                                     
 (ineffective portion)         (7)    1      -   (1)     -     -     -     -
----------------------------------------------------------------------------
                                                                            
(1) No amounts have been excluded from the assessment of hedge              
    effectiveness.                                                          

 
CREDIT RISK RELATED CONTINGENT FEATURES  
Derivatives contracts often contain financial assurance provisions
that may require us to provide collateral if a credit risk-related
contingent event occurs (for example, if our credit rating is
downgraded to non-investment grade).  
Based on contracts in place and market prices at June 30, 2013, the
aggregate fair value of all derivative contracts with
credit-risk-related contingent features that were in a net liability
position was $36 million (December 31, 2012 - $37 million), with
collateral provided in the normal course of business of nil (December
31, 2012 - nil). If the credit-risk-related contingent features in
these agreements had been triggered on June 30, 2013, we would have
been required to provide collateral of $36 million (December 31, 2012
- $37 million) to our counterparties. Collateral may also need to be
provided should the fair value of derivative instruments exceed
pre-defined contractual exposure limit thresholds.  
We feel we have sufficient liquidity in the form of cash and undrawn
committed revolving bank lines to meet these contingent obligations
should they arise.  
FAIR VALUE HIERARCHY  
Assets and liabilities that are recorded at fair value are required
to be categorized into three levels based on the fair value
hierarchy. 


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

 
The fair value of our assets and liabilities measured on a recurring
basis, including both current and non-current positions. 


 
----------------------------------------------------------------------------
                                 Significant                                
                                    other                                   
                Quoted prices    observable      Significant                
                  in active        inputs       unobservable                
                   markets         (Level          inputs                   
                 (Level I)(1)     II)(1,2)     (Level III)(2)      Total    
                -------------- --------------- --------------- -------------
(unaudited -      Jun     Dec     Jun     Dec     Jun     Dec    Jun    Dec 
 millions of $,   30,     31,     30,     31,     30,     31,    30,    31, 
 pre-tax)        2013    2012    2013    2012    2013    2012   2013   2012 
----------------------------------------------------------------------------
                                                                            
Derivative                                                                  
 instrument                                                                 
 assets:                                                                    
 Power                                                                      
  commodity                                                                 
  contracts         -       -     171     213       7       2    178    215 
 Natural gas                                                                
  commodity                                                                 
  contracts        65      75       5      13       -       -     70     88 
 Foreign                                                                    
  exchange                                                                  
  contracts         -       -      32     119       -       -     32    119 
 Interest rate                                                              
  contracts         -       -      18      24       -       -     18     24 
Derivative                                                                  
 instrument                                                                 
 liabilities:                                                               
 Power                                                                      
  commodity                                                                 
  contracts         -       -    (279)   (269)     (7)     (4)  (286)  (273)
 Natural gas                                                                
  commodity                                                                 
  contracts       (85)    (95)    (15)    (11)      -       -   (100)  (106)
 Foreign                                                                    
  exchange                                                                  
  contracts         -       -    (216)    (76)      -       -   (216)   (76)
 Interest rate                                                              
  contracts         -       -     (11)    (14)      -       -    (11)   (14)
Non-derivative                                                              
 financial                                                                  
 instruments:                                                               
 Available for                                                              
  sale assets     
  -       -      47      44       -       -     47     44 
----------------------------------------------------------------------------
                  (20)    (20)   (248)     43       -      (2)  (268)    21 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) There were no transfers between Level I and Level II for the six months 
    ended June 30, 2013 and 2012.                                           
(2) There were no transfers between Level II and Level III for the six      
    months ended June 30, 2013 and 2012.                                    

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


 
----------------------------------------------------------------------------
                                               Derivatives(1)               
                                 ------------------------------------------ 
                                  three months ended     six months ended   
                                        June 30               June 30       
                                 --------------------- ---------------------
(unaudited - millions of $,                                                 
 pre-tax)                             2013       2012       2013       2012 
----------------------------------------------------------------------------
                                                                            
Balance at beginning of period           1        (11)        (2)       (15)
Settlements                              1         (1)         1         (1)
Transfers out of Level III              (1)         1         (1)         1 
Total (losses)/gains included                                               
 in OCI                                 (1)        18          2         22 
----------------------------------------------------------------------------
Balance at end of period                 -          7          -          7 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) For the three and six months ended June 30, 2013, the unrealized gains  
    or losses included in net income attributed to derivatives in the level 
    III category that were still held at the reporting date was nil (2012 - 
    nil).                                                                   

 
A 10 per cent increase or decrease in commodity prices, with all
other variables held constant, would result in a $5 million decrease
or increase, respectively, in the fair value of outstanding
derivative instruments included in Level III at June 30, 2013. 
Other information  
CONTROLS AND PROCEDURES  
Management, including our President and CEO and our CFO, evaluated
the effectiveness of our disclosure controls and procedures as at
June 30, 2013, as required by the Canadian securities regulatory
authorities and by the SEC, and concluded that our disclosure
controls and procedures are effective at a reasonable assurance
level.  
There were no changes in second quarter 2013 that had or are likely
to have a material impact on our internal control over financial
reporting.  
Management is in the process of implementing an Enterprise Resource
Planning (ERP) system that will likely affect some processes
supporting internal control over financial reporting. The phased
implementation period, originally planned to begin July 1, 2013, has
been deferred to January 2014.  
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, AND ACCOUNTING CHANGES  
When we prepare financial statements that conform with U.S. GAAP, we
are required to make estimates and assumptions that affect the timing
and amount we record for our assets, liabilities, revenues and
expenses because these items may be affected by future events. We
base the estimates and assumptions on the most current information
available, using our best judgment. We also regularly assess the
assets and liabilities themselves.  
Our significant accounting policies and critical accounting estimates
have remained unchanged since December 31, 2012 other than described
below. You can find a summary of our significant accounting policies
and critical accounting estimates in our 2012 Annual Report.  
Changes in accounting policies for 2013  
Balance sheet offsetting/netting  
Effective January 1, 2013, we adopted the ASU on disclosures about
balance sheet offsetting as issued by the FASB to enable
understanding of the effects of netting arrangements on our financial
position. Adoption of the ASU has resulted in increased qualitative
and quantitative disclosures about certain derivative instruments
that are either offset in accordance with current U.S. GAAP or are
subject to a master netting arrangement or similar agreement.  
Accumulated other comprehensive income  
Effective January 1, 2013, we adopted the ASU on reporting of amounts
reclassified out of AOCI as issued by the FASB. Adoption of the ASU
has resulted in providing additional qualitative and quantitative
disclosures about significant amounts reclassified out of AOCI into
net income.  
Future accounting changes  
Obligations resulting from joint and several liability arrangements  
In February 2013, the FASB issued guidance for recognizing,
measuring, and disclosing obligations resulting from joint and
several liability arrangements when the total amount of the
obligation is fixed at the reporting date. Debt arrangements, other
contractual obligations, and settled litigation and judicial rulings
are examples of these obligations. This ASU is effective
retrospectively for fiscal years, and interim periods within those
years, beginning after December 15, 2013. We are evaluating the
impact that adopting the ASU would have on our consolidated financial
statements, but do not expect it to be material.  
Foreign currency matters - cumulative translation adjustment  
In March 2013, the FASB issued amended guidance related to the
release of the cumulative translation adjustment into net income when
a parent either sells a part or all of its investment in a foreign
entity or no longer holds a controlling financial interest in a
subsidiary or group of assets that is a business. This ASU is
effective prospectively for fiscal years, and interim reporting
periods within those years, beginning after December 15, 2013. Early
adoption is allowed as of the beginning of the entity's fiscal year.
We are evaluating the impact that adopting this ASU would have on our
consolidated financial statements, but do not expect it to be
material.  
QUARTERLY RESULTS  
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA  


 
----------------------------------------------------------------------------
                          2013                 2012                 2011    
                     ------------- --------------------------- -------------
(unaudited, millions                                                        
 of $, except per                                                           
 share amounts)      Second  First  Fourth  Third Second First  Fourth Third
----------------------------------------------------------------------------
                                                                            
Revenues              2,009  2,252   2,089  2,126  1,847 1,945   2,015 2,043
Net income                                                                  
 attributable to                                                            
 common shares          365    446     306    369    272   352     376   386
Share Statistics                                                            
  Net Income per                                                            
   common share -                                                           
   basic and diluted  $0.52  $0.63   $0.43  $0.52  $0.39 $0.50   $0.53 $0.55
  Dividend declared                                                         
   per common share   $0.46  $0.46   $0.44  $0.44  $0.44 $0.44   $0.42 $0.42
----------------------------------------------------------------------------

 
FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT 
Quarter-over-quarter revenues and net incomes sometimes fluctuate.
The causes of these fluctuations vary across our business segments.  
In Natural Gas Pipelines, quarter-over-quarter revenues and net
income generally remain relatively stable during any fiscal year.
Over the long term, however, they fluctuate because of: 


 
--  regulators' decisions 
--  negotiated settlements with shippers 
--  seasonal fluctuations in short-term throughput volumes on U.S. pipelines
--  acquisitions and divestitures 
--  developments outside of the normal course of operations 
--  newly constructed assets being placed in service. 

 
In Oil Pipelines, annual revenues and net income are based on
contracted crude oil transportation and uncommitted spot
transportation. Quarter-over-quarter revenues and net income during
any particular fiscal year remain relatively stable.  
In Energy, quarter-over-quarter revenues and net income are affected
by: 


 
--  weather 
--  customer demand 
--  market prices 
--  capacity prices and payments 
--  planned and unplanned plant outages 
--  acquisitions and divestitures 
--  certain fair value adjustments 
--  developments outside of the normal course of operations 
--  newly constructed assets being placed in service. 

 
FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER  
Second quarter 2013 


 
--  EBIT included net unrealized losses of $27 million pre-tax ($17 million
    after-tax) from certain risk management activities. 

 
First quarter 2013 


 
--  EBIT included $42 million of pre-tax income ($84 million after-tax) from
    the NEB Canadian Mainline decision relating to 2012 and net unrealized
    losses of $10 million pre-tax ($8 million after-tax) from certain risk
    management activities. 

 
Fourth quarter 2012 


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

 
Third quarter 2012 


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

 
Second quarter 2012 


 
--  EBIT included a $20 million pre-tax charge ($15 million after-tax)
    related to 2011 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) from certain risk management activities. 

 
Third quarter 2011 


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

 
Condensed consolidated statement of income 


 
----------------------------------------------------------------------------
                                  three months ended     six months ended   
                                        June 30               June 30       
                                 --------------------- ---------------------
(unaudited - millions of                                                    
 Canadian $ except per share                                                
 amounts)                             2013       2012       2013       2012 
----------------------------------------------------------------------------
                                                                            
Revenues                                                                    
Natural gas pipelines                1,031      1,034      2,188      2,119 
Oil pipelines                          278        251        549        510 
Energy                                 700        562      1,524      1,163 
----------------------------------------------------------------------------
                                     2,009      1,847      4,261      3,792 
Income from Equity Investments         153         65        246        125 
Operating and Other Expenses                                                
Plant operating costs and other        648        627      1,289      1,219 
Commodity purchases resold             283        208        659        421 
Property taxes                         106        100        215        215 
Depreciation and amortization          356        346        723        690 
----------------------------------------------------------------------------
                                     1,393      1,281      2,886      2,545 
----------------------------------------------------------------------------
Financial Charges/(Income)                                                  
Interest expense                       252        239        510        481 
Interest income and other               11         (5)        (2)       (36)
----------------------------------------------------------------------------
                                       263        234        508        445 
----------------------------------------------------------------------------
Income before Income Taxes             506        397      1,113        927 
----------------------------------------------------------------------------
Income Taxes (Recovery)/Expense                                             
Current                                (36)        39         43         95 
Deferred                               134         46        170        119 
----------------------------------------------------------------------------
                                        98         85        213        214 
----------------------------------------------------------------------------
Net Income                             408        312        900        713 
Net income attributable to non-                                             
 controlling interests                  23         26         54         61 
----------------------------------------------------------------------------
Net Income Attributable to                                                  
 Controlling Interests                 385        286        846        652 
Preferred share dividends               20         14         35         28 
----------------------------------------------------------------------------
Net Income Attributable to                                                  
 Common Shares                         365        272        811        624 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income per Common Share                                                 
Basic and diluted                    $0.52      $0.39      $1.15      $0.89 
----------------------------------------------------------------------------
Dividends Declared per Common                                               
 Share                               $0.46      $0.44      $0.92      $0.88 
----------------------------------------------------------------------------
Weighted Average Number of                                                  
 Common Shares (millions)                                                   
Basic                                  707        704        706        704 
Diluted                                708        705        707        705 
----------------------------------------------------------------------------

 
See accompanying notes to the condensed consolidated financial
statements. 
Condensed consolidated statement of comprehensive income 


 
----------------------------------------------------------------------------
                                  three months ended     six months ended   
                                        June 30               June 30       
                                 --------------------- ---------------------
(unaudited - millions of                                                    
 Canadian $)                          2013       2012       2013       2012 
----------------------------------------------------------------------------
                                                                            
Net Income                             408        312        900        713 
----------------------------------------------------------------------------
Other Comprehensive Income, Net                                             
 of Income Taxes                                                            
Foreign currency translation                                                
 gains on investments in foreign                                            
 operations                            225        114        336          7 
Change in fair value of net                                                 
 investment hedges                    (135)       (61)      (184)       (23)
Change in fair value of cash                                                
 flow hedges                           (44)        28        (23)       (17)
Reclassification to net income                                              
 of gains on cash flow hedges           11         27          7         72 
Reclassification to net income                                              
 of actuarial gains and losses                                              
 and prior service costs on                                                 
 pension and other post-                                                    
 retirement benefit plans                6          4         12         14 
Other comprehensive                                                         
 (loss)/income on equity                                                    
 investments                            (2)        (3)        (3)         2 
----------------------------------------------------------------------------
Other comprehensive income (Note                                            
 7)                                     61        109        145         55 
----------------------------------------------------------------------------
Comprehensive Income                   469        421      1,045        768 
Comprehensive income                                                        
 attributable to non-controlling                                            
 interests                              60         46        111         64 
----------------------------------------------------------------------------
Comprehensive Income                                                        
 Attributable to Controlling                                                
 Interests                             409        375        934        704 
Preferred share dividends               20         14         35         28 
----------------------------------------------------------------------------
Comprehensive Income                                                        
 Attributable to Common Shares         389        361        899        676 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
See accompanying notes to the condensed consolidated financial
statements.  
Condensed consolidated statement of cash flows 


 
----------------------------------------------------------------------------
                                  three months ended     six months ended   
                                        June 30               June 30       
                                 --------------------- ---------------------
(unaudited - millions of                                                    
 Canadian $)                          2013       2012       2013       2012 
----------------------------------------------------------------------------
                                                                            
Cash Generated from Operations                                              
Net income                             408        312        900        713 
Depreciation and amortization          356        346        723        690 
Deferred income taxes                  134         46        170        119 
Income from equity investments        (153)       (65)      (246)      (125)
Distributed earnings received                                               
 from equity investments               180         74        264        157 
Employee post-retirement                                                    
 benefits funding lower than                                                
 expense                                11          5         26         12 
Other                                   19         11         34         34 
(Increase)/decrease in operating                                            
 working capital                      (114)        14       (324)      (155)
----------------------------------------------------------------------------
Net cash provided by operations        841        743      1,547      1,445 
----------------------------------------------------------------------------
Investing Activities                                                        
Capital expenditures                (1,109)      (397)    (2,038)      (861)
Equity investments                     (39)      (197)       (71)      (413)
Acquisition                            (55)         -        (55)         - 
Deferred amounts and other            (144)        79       (164)        42 
----------------------------------------------------------------------------
Net cash used in investing                                                  
 activities                         (1,347)      (515)    (2,328)    (1,232)
----------------------------------------------------------------------------
Financing Activities                                                        
Dividends on common and                                                     
 preferred shares                     (351)      (324)      (666)      (634)
Distributions paid to non-                                                  
 controlling interests                 (35)       (35)       (70)       (68)
Notes payable issued, net            1,388        635        559        589 
Long-term debt issued, net of                                               
 issue costs                            10          1        744        493 
Repayment of long-term debt           (695)      (222)      (709)      (770)
Common shares issued, net of                                                
 issue costs                            23          4         55         18 
Partnership units of subsidiary                                             
 issued, net of issue costs            384          -        384          - 
Preferred shares issued, net of                                             
 issue costs                            (1)         -        585          - 
----------------------------------------------------------------------------
Net cash provided by/(used in)                                              
 financing activities                  723         59        882       (372)
----------------------------------------------------------------------------
Effect of Foreign Exchange Rate                                             
 Changes on Cash and Cash
                                                   
 Equivalents                            14          7         22         (5)
----------------------------------------------------------------------------
Increase/(decrease) in Cash and                                             
 Cash Equivalents                      231        294        123       (164)
----------------------------------------------------------------------------
Cash and Cash Equivalents                                                   
Beginning of period                    443        196        551        654 
----------------------------------------------------------------------------
Cash and Cash Equivalents                                                   
End of period                          674        490        674        490 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
See accompanying notes to the condensed consolidated financial
statements. 
Condensed consolidated balance sheet 


 
----------------------------------------------------------------------------
                                                    June 30     December 31 
(unaudited - millions of Canadian $)                   2013            2012 
----------------------------------------------------------------------------
                                                                            
ASSETS                                                                      
Current Assets                                                              
Cash and cash equivalents                               674             551 
Accounts receivable                                   1,051           1,052 
Inventories                                             224             224 
Other                                                   816             997 
----------------------------------------------------------------------------
                                                      2,765           2,824 
Plant, Property and Equipment, net of                                       
 accumulated depreciation of $17,327 and                                    
 $16,540, respectively                               35,699          33,713 
Equity Investments                                    5,412           5,366 
Goodwill                                              3,653           3,458 
Regulatory Assets                                     1,921           1,629 
Intangible and Other Assets                           1,433           1,343 
----------------------------------------------------------------------------
                                                     50,883          48,333 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES                                                                 
Current Liabilities                                                         
Notes payable                                         2,900           2,275 
Accounts payable and other                            1,968           2,344 
Accrued interest                                        380             368 
Current portion of long-term debt                     1,477             894 
----------------------------------------------------------------------------
                                                      6,725           5,881 
Regulatory Liabilities                                  226             268 
Other Long-Term Liabilities                             926             882 
Deferred Income Tax Liabilities                       4,088           3,953 
Long-Term Debt                                       18,222          18,019 
Junior Subordinated Notes                             1,050             994 
----------------------------------------------------------------------------
                                                     31,237          29,997 
EQUITY                                                                      
Common shares, no par value                          12,131          12,069 
  Issued and outstanding:                                                   
    June 30, 2013 - 707 million shares                                      
    December 31, 2012 - 705 million shares                                  
Preferred shares                                      1,813           1,224 
Additional paid-in capital                              404             379 
Retained earnings                                     4,846           4,687 
Accumulated other comprehensive loss (Note                                  
 7)                                                  (1,360)         (1,448)
----------------------------------------------------------------------------
Controlling Interests                                17,834          16,911 
Non-controlling interests                             1,812           1,425 
----------------------------------------------------------------------------
                                                     19,646          18,336 
----------------------------------------------------------------------------
                                                     50,883          48,333 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contingencies and Guarantees (Note 11)                                      
Subsequent Events (Note 12)                                                 

 
See accompanying notes to the condensed consolidated financial
statements.  
Condensed consolidated statement of equity 


 
----------------------------------------------------------------------------
                                                    six months ended        
                                                         June 30            
                                             -------------------------------
(unaudited - millions of Canadian $)                   2013            2012 
----------------------------------------------------------------------------
                                                                            
Common Shares                                                               
Balance at beginning of period                       12,069          12,011 
Shares issued on exercise of stock options               62              19 
----------------------------------------------------------------------------
Balance at end of period                             12,131          12,030 
----------------------------------------------------------------------------
Preferred Shares                                                            
Balance at beginning of period                        1,224           1,224 
Shares issued, net of issue costs                       589               - 
----------------------------------------------------------------------------
Balance at end of period                              1,813           1,224 
----------------------------------------------------------------------------
Additional Paid-In Capital                                                  
Balance at beginning of period                          379             380 
Exercise of stock options, net of issuances              (4)              - 
Dilution impact from TC PipeLines, LP units                                 
 issued                                                  29               - 
----------------------------------------------------------------------------
Balance at end of period                                404             380 
----------------------------------------------------------------------------
Retained Earnings                                                           
Balance at beginning of period                        4,687       
    4,628 
Net income attributable to controlling                                      
 interests                                              846             652 
Common share dividends                                 (650)           (620)
Preferred share dividends                               (37)            (28)
----------------------------------------------------------------------------
Balance at end of period                              4,846           4,632 
----------------------------------------------------------------------------
Accumulated Other Comprehensive Loss                                        
Balance at beginning of period                       (1,448)         (1,449)
Other comprehensive income                               88              52 
----------------------------------------------------------------------------
Balance at end of period                             (1,360)         (1,397)
----------------------------------------------------------------------------
Equity Attributable to Controlling Interests         17,834          16,869 
----------------------------------------------------------------------------
Equity Attributable to Non-Controlling                                      
 Interests                                                                  
Balance at beginning of period                        1,425           1,465 
Net income attributable to non-controlling                                  
 interests                                                                  
  TC PipeLines, LP                                       36              47 
  Preferred share dividends of TCPL                      11              11 
  Portland                                                7               3 
Other comprehensive income attributable to                                  
 non-controlling interests                               57               3 
Sale of TC PipeLines, LP units                                              
  Proceeds, net of issue costs                          384               - 
  Decrease in TransCanada's ownership                   (47)              - 
Distributions to non-controlling interests              (70)            (68)
Foreign exchange and other                                9               - 
----------------------------------------------------------------------------
Balance at end of period                              1,812           1,461 
----------------------------------------------------------------------------
Total Equity                                         19,646          18,330 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 U.S. GAAP. The accounting policies
applied are consistent with those outlined in TransCanada's annual
audited consolidated financial statements for the year ended December
31, 2012. Capitalized and abbreviated terms that are used but not
otherwise defined herein are identified in TransCanada's 2012 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 2012 audited consolidated financial
statements included in TransCanada's 2012 Annual Report. Certain
comparative figures have been reclassified to conform with the
current period's presentation.   
Earnings for interim periods may not be indicative of results for the
fiscal year in the Company's Natural Gas Pipelines segment due to the
timing of regulatory decisions and 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 significant
accounting policies included in the consolidated financial statements
for the year ended December 31, 2012, except as described in Note 2,
Changes in accounting policies. 


 
2.  Changes in Accounting Policies 

 
CHANGES IN ACCOUNTING POLICIES FOR 2013  
Balance Sheet Offsetting/Netting  
Effective January 1, 2013, the Company adopted the ASU on disclosures
about balance sheet offsetting as issued by the FASB to enable
understanding of the effects of netting arrangements on the Company's
financial position. Adoption of the ASU has resulted in increased
qualitative and quantitative disclosures regarding certain derivative
instruments that are either offset in accordance with current U.S.
GAAP or are subject to a master netting arrangement or similar
agreement.  
Accumulated Other Comprehensive Income  
Effective January 1, 2013, the Company adopted the ASU on reporting
of amounts reclassified out of AOCI as issued by the FASB. Adoption
of the ASU has resulted in providing additional qualitative and
quantitative disclosures regarding significant amounts reclassified
out of accumulated other comprehensive income into net income.  
FUTURE ACCOUNTING CHANGES  
Obligations Resulting from Joint and Several Liability Arrangements  
In February 2013, the FASB issued guidance for the recognition,
measurement and disclosure of obligations resulting from joint and
several liability arrangements for which the total amount of the
obligation is fixed at the reporting date. Examples of obligations
within the scope of this ASU include debt arrangements, other
contractual obligations, and settled litigation and judicial rulings.
This ASU is effective retrospectively for fiscal years, and interim
periods within those years, beginning after December 15, 2013. The
Company is currently evaluating the impact of the adoption of this
ASU on its consolidated financial statements, but does not expect it
to have a material impact.  
Foreign Currency Matters - Cumulative Translation Adjustment  
In March 2013, the FASB issued amended guidance related to the
release of the cumulative translation adjustment into net income when
a parent either sells a part or all of its investment in a foreign
entity or no longer holds a controlling financial interest in a
subsidiary or group of assets that is a business. This ASU is
effective prospectively for fiscal years, and interim reporting
periods within those years, beginning after December 15, 2013. Early
adoption is permitted as of the beginning of the entity's fiscal
year. The Company is currently evaluating the impact of the adoption
of this ASU on its consolidated financial statements, but does not
expect it to have a material impact. 


 
3.  Segmented Information 
 
----------------------------------------------------------------------------
three months                                                                
 ended June    Natural gas      Oil                                         
 30             pipelines    pipelines    Energy     Corporate     Total    
              ------------- ----------- ----------- ----------- ------------
(unaudited -                                                                
 millions of                                                                
 Canadian $)   2013   2012  2013  2012  2013  2012  2013  2012   2013  2012 
----------------------------------------------------------------------------
                                                                            
Revenues      1,031  1,034   278   251   700   562     -     -  2,009 1,847 
Income from                                                                 
 equity                                                                     
 investments     29     37     -     -   124    28     -     -    153    65 
Plant                                                                       
 operating                                                                  
 costs and                                                                  
 other         (339)  (330)  (82)  (68) (210) (214)  (17)  (15)  (648) (627)
Commodity                                                                   
 purchases                                                                  
 resold           -      -     -     -  (283) (208)    -     -   (283) (208)
Property                                                                    
 taxes          (77)   (75)  (10)   (7)  (19)  (18)    -     -   (106) (100)
Depreciation                                                                
 and                                                                        
 amortization  (245)  (234)  (37)  (36)  (69)  (72)   (5)   (4)  (356) (346)
----------------------------------------------------------------------------
                399    432   149   140   243    78   (22)  (19)   769   631 
----------------------------------------------------------------            
----------------------------------------------------------------            
Interest expense                                                 (252) (239)
Interest income and other                                         (11)    5 
----------------------------------------------------------------------------
Income before Income Taxes                                        506   397 
Income taxes expense                                              (98)  (85)
----------------------------------------------------------------------------
Net Income                                                        408   312 
Net Income Attributable to Non-Controlling Interests              (23)  (26)
----------------------------------------------------------------------------
Net Income Attributable to Controlling Interests                  385   286 
Preferred Share Dividends                                         (20)  (14)
----------------------------------------------------------------------------
Net Income Attributable to Common Shares                          365   272 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
six months ended  Natural gas    Oil                                        
 June 30           pipelines  pipelines    Energy   Corporate     Total     
                  ----------- --------- ----------- --------- --------------
(unaudited -                                                                
 millions of                                                                
 Canadian $)       2013  2012 2013 2012  2013  2012 2013 2012   2013   2012 
----------------------------------------------------------------------------
                                                                            
Revenues          2,188 2,119  549  510 1,524 1,163    -    -  4,261  3,792 
Income from                                                                 
 equity                                                                     
 investments         69    83    -    -   177    42    -    -    246    125 
Plant operating                                                             
 costs and other   (657) (657)(161)(137) (420) (381) (51) (44)(1,289)(1,219)
Commodity                                                                   
 purchases resold     -     -    -    -  (659) (421)   -    -   (659)  (421)
Property taxes     (155) (154) (23) (24)  (37)  (37)   -    -   (215)  (215)
Depreciation and                                                            
 amortization      (498) (466) (74) (72) (143) (145)  (8)  (7)  (723)  (690)
----------------------------------------------------------------------------
                    947   925  291  277   442   221  (59) (51) 1,621  1,372 
--------------------------------------------------------------              
--------------------------------------------------------------              
Interest expense                                                (510)  (481)
Interest income and other                                          2     36 
----------------------------------------------------------------------------
Income before Income Taxes                                     1,113    927 
Income taxes expense                                            (213)  (214)
----------------------------------------------------------------------------
Net Income                                                       900    713 
Net Income Attributable to Non-Controlling Interests             (54)   (61)
----------------------------------------------------------------------------
Net Income Attributable to Controlling Interests                 846    652 
Preferred Share Dividends                                        (35)   (28)
----------------------------------------------------------------------------
Net Income Attributable to Common Shares                         811    624 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
TOTAL ASSETS 


 
----------------------------------------------------------------------------
(unaudited - millions of Canadian $)        June 30, 2013  December 31, 2012
----------------------------------------------------------------------------
                                                                            
Natural Gas Pipelines                              24,322             23,210
Oil Pipelines                                      11,667             10,485
Energy                                             13,400             13,157
Corporate                                           1,494              1,481
----------------------------------------------------------------------------
                                                   50,883             48,333
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
4.  Income Taxes 

 
At June 30, 2013, the total unrecognized tax benefit of uncertain tax
positions was approximately $25 million (December 31, 2012 - $49
million). TransCanada recognizes interest and penalties related to
income tax uncertainties in income tax expense. Included in net tax
expense for the three and six months ended June 30, 2013 is nil and
$1 million, respectively, of interest expense and nil for penalties
(June 30, 2012 - nil and $1 million, respectively, of interest
expense and nil for penalties). At June 30, 2013, the Company had $6
million accrued for interest expense and 
nil accrued for penalties
(December 31, 2012 - $5 million accrued for interest expense and nil
for penalties).  
The effective tax rates for the six-month periods ended June 30, 2013
and 2012 were 19 per cent and 23 per cent, respectively. The lower
effective tax rate in 2013 was a result of the impact of the NEB's
decision on the Canadian Restructuring Proposal and the enactment of
certain Canadian Federal tax legislation.  
TransCanada recognized a favourable income tax adjustment of
approximately $25 million due to the enactment of certain Canadian
Federal tax legislation in June 2013. Subject to the results of audit
examinations by taxing 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 six months ended June 30, 2013, TransCanada
capitalized interest related to capital projects of $60 million and
$115 million, respectively (June 30, 2012 - $76 million and $150
million, respectively).  
In January 2013, TransCanada PipeLines Limited issued US$750 million
of 0.75 per cent senior notes due in 2016.  
In June 2013, TransCanada PipeLines Limited retired US$350 million of
4.00 per cent senior notes. 


 
6.  Equity and Share Capital 

 
On May 22, 2013, TC PipeLines, LP completed a public offering of
8,855,000 common units at a price of $43.85 per unit, resulting in
gross proceeds of approximately US$388 million. TransCanada
contributed an additional approximate US$8 million to maintain its
general partnership interest and did not purchase any other units.
Upon completion of this offering, TransCanada's ownership interest in
TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent and an
after-tax dilution impact of $29 million ($47 million pre-tax) was
recorded in Additional Paid-In Capital.  
PREFERRED SHARE ISSUE  
In March 2013, TransCanada completed a public offering of 24 million
Series 7 cumulative redeemable first preferred shares under its
November 2011 equity base shelf prospectus. The Series 7 preferred
shares were issued at $25 per share resulting in gross proceeds of
$600 million. The holders of the Series 7 preferred shares are
entitled to receive fixed cumulative dividends at an annual rate of
$1.00 per share, payable quarterly. The dividend rate will reset on
April 30, 2019 and every five years thereafter to a yield per annum
equal to the sum of the then five year Government of Canada bond
yield and 2.38 per cent. The preferred shares are redeemable by
TransCanada on or after April 30, 2019 and on April 30 of every fifth
year thereafter at a price of $25 per share plus accrued and unpaid
dividends.   
The Series 7 preferred shareholders will have the right to convert
their shares into Series 8 cumulative redeemable first preferred
shares on April 30, 2019 and on April 30 of every fifth year
thereafter. The holders of Series 8 preferred shares will be entitled
to receive quarterly floating rate cumulative dividends at a yield
per annum equal to the sum of the then 90 day Government of Canada
treasury bill rate and 2.38 per cent.  


 
7.  Other Comprehensive Income And Accumulated Other Comprehensive Loss 

 
Components of other comprehensive income including non-controlling
interests and the related tax effects are as follows: 


 
----------------------------------------------------------------------------
                                                    Income tax              
three months ended June 30, 2013       Before tax    recovery/   Net of tax 
(unaudited - millions of Canadian $)       amount    (expense)       amount 
----------------------------------------------------------------------------
                                                                            
Foreign currency translation gains                                          
 and losses on investments in foreign                                       
 operations                                   170           55          225 
Change in fair value of net                                                 
 investment hedges                           (182)          47         (135)
Change in fair value of cash flow                                           
 hedges                                       (68)          24          (44)
Reclassification to net income of                                           
 gains and losses on cash flow hedges          18           (7)          11 
Reclassification to net income of                                           
 actuarial gains and losses and prior                                       
 service costs on pension and other                                         
 post-retirement benefit plans                  7           (1)           6 
Other comprehensive loss on equity                                          
 investments                                   (3)           1           (2)
----------------------------------------------------------------------------
Other comprehensive income                    (58)         119           61 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
----------------------------------------------------------------------------
                                                    Income tax              
three months ended June 30, 2012       Before tax    recovery/   Net of tax 
(unaudited - millions of Canadian $)       amount    (expense)       amount 
----------------------------------------------------------------------------
                                                                            
Foreign currency translation gains                                          
 and losses on investments in foreign                                       
 operations                                    84           30          114 
Change in fair value of net                                                 
 investment hedges                            (80)          19          (61)
Change in fair value of cash flow                                           
 hedges                                        43          (15)          28 
Reclassification to net income of                                           
 gains and losses on cash flow hedges          47          (20)          27 
Reclassification to net income of                                           
 actuarial gains and losses and prior                                       
 service costs on pension and other                                         
 post-retirement benefit plans                  5           (1)           4 
Other comprehensive loss on equity                                          
 investments                                   (3)           -           (3)
----------------------------------------------------------------------------
Other comprehensive income                     96           13          109 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
----------------------------------------------------------------------------
                                                    Income tax              
six months ended June 30, 2013         Before tax    recovery/   Net of tax 
(unaudited - millions of Canadian $)       amount    (expense)       amount 
----------------------------------------------------------------------------
                                                                    
        
Foreign currency translation gains                                          
 and losses on investments in foreign                                       
 operations                                   247           89          336 
Change in fair value of net                                                 
 investment hedges                           (248)          64         (184)
Change in fair value of cash flow                                           
 hedges                                       (30)           7          (23)
Reclassification to net income of                                           
 gains and losses on cash flow hedges          11           (4)           7 
Reclassification to net income of                                           
 actuarial gains and losses and prior                                       
 service costs on pension and other                                         
 post-retirement benefit plans                 17           (5)          12 
Other comprehensive loss on equity                                          
 investments                                   (4)           1           (3)
----------------------------------------------------------------------------
Other comprehensive income                     (7)         152          145 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
----------------------------------------------------------------------------
                                                    Income tax              
six months ended June 30, 2012         Before tax    recovery/   Net of tax 
(unaudited - millions of Canadian $)       amount    (expense)       amount 
----------------------------------------------------------------------------
                                                                            
Foreign currency translation gains                                          
 and losses on investments in foreign                                       
 operations                                    (1)           8            7 
Change in fair value of net                                                 
 investment hedges                            (31)           8          (23)
Change in fair value of cash flow                                           
 hedges                                       (36)          19          (17)
Reclassification to net income of                                           
 gains and losses on cash flow hedges         113          (41)          72 
Reclassification to net income of                                           
 actuarial gains and losses and prior                                       
 service costs on pension and other                                         
 post-retirement benefit plans                 11            3           14 
Other comprehensive income on equity                                        
 investments                                    3           (1)           2 
----------------------------------------------------------------------------
Other comprehensive income                     59           (4)          55 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The changes in accumulated other comprehensive loss by component are
as follows: 


 
----------------------------------------------------------------------------
three months ended June                                                     
 30, 2013                     Currency                Pension and           
(unaudited - millions of   translation  Cash flow       OPEB plan           
 Canadian $)               adjustments     hedges     adjustments  Total(1) 
----------------------------------------------------------------------------
                                                                            
AOCI Balance at April 1,                                                    
 2013                             (665)       (95)           (624)   (1,384)
Other comprehensive                                                         
 income before                                                              
 reclassifications(2)               53        (45)             (1)        7 
Amounts reclassified from                                                   
 accumulated other                                                          
 comprehensive loss(3)               -         11               6        17 
----------------------------------------------------------------------------
Net current period other                                                    
 comprehensive                                                              
 income/(loss)                      53        (34)              5        24 
----------------------------------------------------------------------------
AOCI Balance at June 30,                                                    
 2013                             (612)      (129)           (619)   (1,360)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) All amounts are net of tax. Amounts in parentheses indicate losses.     
(2) Other comprehensive income before reclassifications on currency         
    translation adjustments is net of non-controlling interest of $37       
    million.                                                                
(3) 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 $77
    million ($50 million, net of tax) at June 30, 2013. 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.            
                                                                            
----------------------------------------------------------------------------
six months ended June 30,                                                   
 2013                         Currency                Pension and           
(unaudited - millions of   translation  Cash flow       OPEB plan           
 Canadian $)               adjustments     hedges     adjustments  Total(1) 
----------------------------------------------------------------------------
                                                                            
AOCI Balance at January                                                     
 1, 2013                          (707)      (110)           (631)   (1,448)
Other comprehensive                                                         
 income before                                                              
 reclassifications(2)               95        (26)              -        69 
Amounts reclassified from                                                   
 accumulated other                                                          
 comprehensive loss(3)               -          7              12        19 
----------------------------------------------------------------------------
Net current period other                                                    
 comprehensive                                                              
 income/(loss)                      95        (19)             12        88 
----------------------------------------------------------------------------
AOCI Balance at June 30,                                                    
 2013                             (612)      (129
)           (619)   (1,360)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) All amounts are net of tax. Amounts in parentheses indicate losses.     
(2) Other comprehensive income before reclassifications on currency         
    translation adjustments is net of non-controlling interest of $57       
    million.                                                                
(3) 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 $77
    million ($50 million, net of tax) at June 30, 2013. 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.            

 
Details about reclassifications out of accumulated other
comprehensive loss are as follows: 


 
----------------------------------------------------------------------------
                         Amounts reclassified from                          
                             accumulated other                              
                           comprehensive loss(1)                            
                      -------------------------------                       
                                                      Affected line item in 
                        three months      six months  the condensed         
(unaudited - millions          ended           ended  consolidated statement
 of Canadian $)        June 30, 2013   June 30, 2013  of income             
----------------------------------------------------------------------------
                                                                            
Cash flow hedges                                                            
 Power                           (14)             (3) Revenue (Energy)      
 Interest                         (4)             (8) Interest expense      
----------------------------------------------------------------------------
                                 (18)            (11) Total before tax      
                                   7               4  Income tax expense    
----------------------------------------------------------------------------
                                 (11)             (7) Net of tax            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Pension and other                                                           
 post-retirement plan                                                       
 adjustments                                                                
 Amortization of net                                                        
  loss(2)                         (7)            (17) Total before tax      
                                   1               5  Income tax expense    
----------------------------------------------------------------------------
                                  (6)            (12) Net of tax            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) All amounts in parentheses indicate expenses to the condensed           
    consolidated statement of income.                                       
(2) These accumulated other comprehensive loss components are included in   
    the computation of net benefit cost. Refer to Note 8 for additional     
    detail.                                                                 
 
8.  Employee Post-Retirement Benefits 

 
The net benefit cost recognized for the Company's defined benefit
pension plans and other post-retirement benefit plans is as follows:  


 
----------------------------------------------------------------------------
                     three months ended June 30   six months ended June 30  
                     --------------------------- ---------------------------
                                    Other post-                 Other post- 
                        Pension     retirement      Pension     retirement  
                        benefit       benefit       benefit       benefit   
                         plans         plans         plans         plans    
                     ------------- ------------- ------------- -------------
(unaudited, millions                                                        
 of Canadian $)       2013   2012   2013   2012   2013   2012   2013   2012 
----------------------------------------------------------------------------
                                                                            
Service cost            22     17      -      -     41     33      1      1 
Interest cost           23     24      2      2     47     47      4      4 
Expected return on                                                          
 plan assets           (29)   (29)    (1)    (1)   (58)   (57)    (1)    (1)
Amortization of                                                             
 actuarial loss          6      4      -      1     15      9      1      1 
Amortization of past                                                        
 service cost            1      1      -      -      1      1      -      - 
Amortization of                                                             
 regulatory asset        8      5      1      -     15     10      1      - 
Amortization of                                                             
 transitional                                                               
 obligation related                                                         
 to regulated                                                               
 business                -      -      1      1      -      -      1      1 
----------------------------------------------------------------------------
Net benefit cost                                                            
 recognized             31     22      3      3     61     43      7      6 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
9.  Risk Management and Financial Instruments 

 
COUNTERPARTY CREDIT 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, portfolio
investments recorded at fair value, the fair value of derivative
assets and notes, and loans and advances receivable. The carrying
amounts and fair values of these financial assets, except amounts for
derivative assets, are included in accounts receivable and other, and
available for sale assets in the Non-Derivative Financial Instruments
Summary table below. The majority of counterparty credit exposure is
with counterparties that are investment grade or the exposure is
supported by financial assurances provided by investment grade
parties. The Company regularly reviews its accounts receivable and
records an allowance for doubtful accounts as necessary using the
specific identification method. At June 30, 2013, there were no
significant amounts past due or impaired, and there were no
significant credit losses during the year.  
At June 30, 2013, the Company had a credit risk concentration of $263
million (December 31, 2012 - $259 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.  
NET INVESTMENT IN FOREIGN OPERATIONS  
The Compan
y hedges its net investment in foreign operations (on an
after-tax basis) with U.S. dollar-denominated debt, cross-currency
interest rate swaps, forward foreign exchange contracts and foreign
exchange options.  
U.S. DOLLAR-DENOMINATED DEBT DESIGNATED AS A NET INVESTMENT HEDGE 


 
----------------------------------------------------------------------------
(unaudited - billions of Canadian $)     June 30, 2013    December 31, 2012 
----------------------------------------------------------------------------
                                                                            
Carrying value                           12.2 (US 11.7)       11.1 (US 11.2)
Fair value                               14.2 (US 13.5)       14.3 (US 14.4)
----------------------------------------------------------------------------

 
FAIR VALUE OF DERIVATIVES USED TO HEDGE OUR 
U.S. DOLLAR INVESTMENT IN FOREIGN OPERATIONS 


 
----------------------------------------------------------------------------
(unaudited - millions of Canadian $)      June 30, 2013    December 31, 2012
----------------------------------------------------------------------------
                                                                            
Other current assets                                 30                   71
Intangible and other assets                           2                   47
Accounts payable and other                           52                    6
Other long-term liabilities                         146                   30
----------------------------------------------------------------------------

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


 
----------------------------------------------------------------------------
                                 June 30, 2013          December 31, 2012   
                           ------------------------ ------------------------
Asset/(liability)                       Notional or              Notional or
(unaudited - millions of        Fair      principal       Fair     principal
 Canadian $)                Value(1)         amount   value(1)        amount
----------------------------------------------------------------------------
                                                                            
U.S. dollar cross-currency                                                  
 swaps                                                                      
  (maturing 2013 to                                                         
   2019)(2)                     (137)      US 3,900         82      US 3,800
U.S. dollar forward                                                         
 foreign exchange                                                           
 contracts                                                                  
  (maturing 2013 to 2014)        (29)      US 1,050          -        US 250
----------------------------------------------------------------------------
                                (166)      US 4,950         82      US 4,050
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Fair values equal carrying values.                                      
(2) Net Income in the three and six months ended June 30, 2013 included net 
    realized gains of $7 million and $14 million, respectively, (2012 -     
    gains of $7 million and $14 million, respectively) related to the       
    interest component of cross-currency swap settlements.                  

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


 
----------------------------------------------------------------------------
                                     June 30, 2013       December 31, 2012  
                                 --------------------- ---------------------
(unaudited - millions of           Carrying       Fair   Carrying       Fair
 Canadian $)                      amount(1)   value(2)  amount(1)   value(2)
----------------------------------------------------------------------------
                                                                            
Financial assets                                                            
Cash and cash equivalents               674        674        551        551
Accounts receivable and other(3)      1,301      1,350      1,288      1,337
Available for sale assets                47         47         44         44
----------------------------------------------------------------------------
                                      2,022      2,071      1,883      1,932
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial liabilities(4)                                                    
Notes payable                         2,900      2,900      2,275      2,275
Accounts payable and other long-                                            
 term liabilities(5)                  1,114      1,114      1,535      1,535
Accrued interest                        380        380        368        368
Long-term debt                       19,699     23,474     18,913     24,573
Junior subordinated notes             1,050      1,105        994      1,054
----------------------------------------------------------------------------
                                     25,143     28,973     24,085     29,805
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Recorded at amortized cost, except for US$200 million (December 31, 2012
    - US$350 million) of long-term debt that is attributed to hedged risk   
    and recorded at fair value. This debt, which is recorded at fair value  
    on a recurring basis, is classified in Level II of the fair value       
    hierarchy using the income approach based on interest rates from        
    external data service providers.                                        
(2) The fair value measurement of financial assets and liabilities recorded 
    at amortized cost for which 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 June 30, 2013, financial assets of $1.1 billion (December 31, 2012 - 
    $1.1 billion) are included in accounts receivable, $72 million (December
    31, 2012 - $40 million) in other current assets and $225 million        
    (December 31, 2012 - $240 million) in intangible and other assets.      
(4) Condensed consolidated statement of income in the three and six months  
    ended June 30, 2013 included gains of $3 million and losses of $7       
    million, respectively, (2012 - gains of $3 million and losses of $12    
    million, respectively) for fair value adjustments attributable to the   
    hedged interest rate risk associated with interest rate swap fair value 
    hedging relationships on US$200 million of long-term debt at June 30,   
    2013 (December 31, 2012 - US$350 million). There were no other          
    unrealized gains or losses from fair value adjustments to the non-      
    derivative financial instruments.                                       
(5) At June 30, 2013, financial liabilities of $1.1 billion (December 31,   
    2012 - $1.5 billion) are included in accounts payable and $36 million   
    (December 31, 2012 - $38 million) in other long-term liabilit
ies.       

 
Derivative Instruments Summary  
Information for the Company's derivative instruments for 2013,
excluding hedges of the Company's net investment in foreign
operations, is as follows: 


 
----------------------------------------------------------------------------
(unaudited - millions of                                                    
 Canadian $ unless noted                   Natural      Foreign             
 otherwise)                      Power         gas     exchange    Interest 
----------------------------------------------------------------------------
                                                                            
Derivative instruments held                                                 
 for trading(1)                                                             
Fair values(2)                                                              
  Assets                          $141         $70           $-         $11 
  Liabilities                    $(183)       $(99)        $(17)       $(11)
Notional values                                                             
  Volumes(3)                                                                
    Sales                       35,445          64            -           - 
    Purchases                   34,750         102            -           - 
  Canadian dollars                   -           -            -         620 
  U.S. dollars                       -           -     US 1,274      US 200 
Net unrealized                                                              
 gains/(losses) in the                                                      
 period(4)                                                                  
  three months ended June                                                   
   30, 2013                         $5        $(21)        $(10)         $- 
  six months ended June 30,                                                 
   2013                            $(3)       $(12)        $(16)         $- 
Net realized losses in the                                                  
 period(4)                                                                  
  three months ended June                                                   
   30, 2013                       $(29)        $(5)         $(6)         $- 
  six months ended June 30,                                                 
   2013                           $(36)        $(7)         $(7)         $- 
Maturity dates               2013-2017   2013-2016    2013-2014   2013-2016 
----------------------------------------------------------------------------
Derivative instruments in                                                   
 hedging relationships(5,6)                                                 
Fair values(2)                                                              
  Assets                           $37          $-           $-          $7 
  Liabilities                    $(103)        $(1)         $(1)         $- 
Notional values                                                             
  Volumes(3)                                                                
    Sales                        6,283           -            -           - 
    Purchases                   13,206           -            -           - 
  U.S. dollars                       -           -        US 15      US 200 
  Cross-currency                     -           -            -           - 
Net realized (losses)/gains                                                 
 in the period(4)                                                           
  three months ended June                                                   
   30, 2013                       $(84)        $(1)          $-          $2 
  six months ended June 30,                                                 
   2013                           $(11)        $(1)          $-          $4 
Maturity dates               2013-2018        2013         2014        2015 
----------------------------------------------------------------------------
                                                                            
(1) All derivative 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 held for trading derivative 
    instruments used to purchase and sell power and natural gas are included
    net in revenues. Realized and unrealized gains and losses on interest   
    rate and foreign exchange derivative financial instruments held for     
    trading are included in interest expense and interest income and other, 
    respectively. The effective portion of the change in fair value of      
    derivative instruments in hedging relationships is initially recognized 
    in OCI and reclassified to revenues, interest expense and interest      
    income and other, as appropriate, as the original hedged item settles.  
(5) All hedging relationships are designated as cash flow hedges except for 
    interest rate derivative financial instruments designated as fair value 
    hedges with a fair value of $7 million and a notional amount of US$200  
    million. For the three and six months ended June 30, 2013, net realized 
    gains on fair value hedges were $2 million and $4 million, respectively 
    and were included in interest expense. For the three and six months     
    ended June 30, 2013, the Company did not record any amounts in net      
    income related to ineffectiveness for fair value hedges.                
(6) For the three and six months ended June 30, 2013 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.          

 
Derivative Instruments Summary  
Information for the Company's derivative instruments for 2012,
excluding hedges of the Company's net investment in foreign
operations, is as follows: 


 
----------------------------------------------------------------------------
(unaudited - millions of                                                    
 Canadian $ unless noted                   Natural      Foreign             
 otherwise)                      Power         gas     exchange    Interest 
----------------------------------------------------------------------------
Derivative instruments                                                      
 held for trading(1)                                                        
Fair values(2,3)                                                            
  Assets                          $139         $88           $1         $14 
  Liabilities                    $(176)      $(104)         $(2)       $(14)
Notional values(3)                                                          
  Volumes(4)                                                                
    Sales                       31,066          65            -           - 
    Purchases                   31,135          83            -           - 
  Canadian dollars                   -           -            -         620 
  U.S. dollars                       -           -     US 1,408      US 200 
Net unrealized                                                              
 (losses)/gains in the                                                      
 period(5)                                       
                           
  three months ended June                                                   
   30, 2012                       $(12)         $4         $(14)         $- 
  six months ended June                                                     
   30, 2012                       $(19)       $(10)         $(8)         $- 
Net realized                                                                
 (losses)/gains in the                                                      
 period(5)                                                                  
  three months ended June                                                   
   30, 2012                        $(6)        $(5)          $6          $- 
  six months ended June                                                     
   30, 2012                         $9        $(15)         $15          $- 
Maturity dates               2013-2017   2013-2016         2013   2013-2016 
----------------------------------------------------------------------------
Derivative instruments in                                                   
 hedging                                                                    
 relationships(6,7)                                                         
Fair values(2,3)                                                            
  Assets                           $76          $-           $-         $10 
  Liabilities                     $(97)        $(2)        $(38)         $- 
Notional values(3)                                                          
  Volumes(4)                                                                
    Sales                        7,200           -            -           - 
    Purchases                   15,184           1            -           - 
  U.S. dollars                       -           -        US 12      US 350 
  Cross-currency                     -           -   136/US 100           - 
Net realized                                                                
 (losses)/gains in the                                                      
 period(5)                                                                  
  three months ended June                                                   
   30, 2012                       $(26)        $(8)          $-          $2 
  six months ended June                                                     
   30, 2012                       $(58)       $(14)          $-          $3 
Maturity dates               2013-2018        2013    2013-2014   2013-2015 
----------------------------------------------------------------------------
                                                                            
(1) All derivative instruments held for trading have been entered into for  
    risk management purposes and are subject to 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, 2012.                                                
(4) Volumes for power and natural gas derivatives are in GWh and Bcf,       
    respectively.                                                           
(5) Realized and unrealized gains and losses on held for trading derivative 
    instruments used to purchase and sell power and natural gas are included
    net in revenues. Realized and unrealized gains and losses on interest   
    rate and foreign exchange derivative financial instruments held for     
    trading are included in interest expense and interest income and other, 
    respectively. The effective portion of change in fair value of          
    derivative instruments in hedging relationships is initially recognized 
    in OCI and reclassified to revenues, interest expense and interest      
    income and other, as appropriate, as the original hedged item settles.  
(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 $10 million and a notional amount of US$350 
    million. Net realized gains on fair value hedges for the three and six  
    months ended June 30, 2012 were $2 million and $4 million, respectively,
    and were included in Interest expense. In the three and six months ended
    June 30, 2012, the Company did not record any amounts in Net Income     
    related to ineffectiveness for fair value hedges.                       
(7) For the three and six months ended June 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.          

 
BALANCE SHEET PRESENTATION OF DERIVATIVE INSTRUMENTS  
The fair value of the derivative instruments in the Company's balance
sheet is as follows:  


 
----------------------------------------------------------------------------
(unaudited - millions of Canadian $)     June 30, 2013    December 31, 2012 
----------------------------------------------------------------------------
                                                                            
Current                                                                     
Other current assets                               187                  259 
Accounts payable and other                        (341)                (283)
Long term                                                                   
Intangible and other assets                        111                  187 
Other long-term liabilities                       (272)                (186)
----------------------------------------------------------------------------

 
DERIVATIVES IN CASH FLOW HEDGING RELATIONSHIPS  
The components of other comprehensive income (OCI) related to
derivatives in cash flow hedging relationships are as follows:  


 
----------------------------------------------------------------------------
Cash flow hedges(1)                                                         
three months ended June 30                 Natural     Foreign              
(unaudited - millions of        Power        gas       exchange    Interest 
                             ----------- ----------- ----------- -----------
Canadian $, pre-tax)         2013   2012  2013 2012   2013  2012  2013  2012
----------------------------------------------------------------------------
                                                                            
Change in fair value of                                                     
 derivative instruments                                                     
 recognized in OCI                                                          
 (effective portion)          (70)    44     -   (4)     2     4     -     -
Reclassification of gains                                                   
 and losses on derivative                                                   
 instruments from AOCI to                                                   
 net income (effective                                                      
 portion)                      12     28     2   15      -     -     4     4
Gains and losses on                                                         
 derivative instruments                                                     
 recognized in earnings                                                     
 (ineffective portion)         (2)     7     -    1      -     -     -     -
----------------------------------------------------------------------------
                                                                            
(1) No amounts have been excluded from the assessment of hedge              
    effectiveness.                                                          
                                                                            
----------------------------------------------------------------------------
Cash flow hedges(1)                                                         
six months ended June 30                   Natural     Foreign              
(unaudited - millions of        Power        gas       exchange    Interest 
                             ----------- ----------- ----------- -----------
Canadian $, pre-tax)         2013  2012   2013 2012   2013  2012  2013  2012
----------------------------------------------------------------------------
                                                                            
Change in fair value of                                                     
 derivative instruments                                                     
 recognized in OCI                                                          
 (effective portion)          (34)  (22)     -  (14)     4     1     -     -
Reclassification of gains                                                   
 and losses on derivative                                                   
 instruments from AOCI to                                                   
 net income (effective                                                      
 portion)                       1    75      2   28      -     -     8    10
Gains and losses on                                                         
 derivative instruments                                                     
 recognized in earnings                                                     
 (ineffective portion)         (7)    1      -   (1)     -     -     -     -
----------------------------------------------------------------------------
                                                                            
(1) No amounts have been excluded from the assessment of hedge              
    effectiveness.                                                          

 
OFFSETTING OF DERIVATIVE INSTRUMENTS  
The Company enters into derivative contracts with the right to offset
in the normal course of business as well as in the event of default.
TransCanada has no master netting agreements, however, similar
contracts are entered into containing rights of offset. The Company
has elected to present the fair value of derivative instruments with
the right to offset on a gross basis in the balance sheet. The
following table shows the impact on the presentation of the fair
value of derivative instrument assets and liabilities had the Company
elected to present these contracts on a net basis: 


 
----------------------------------------------------------------------------
                             Gross derivative                               
at June 30, 2013                  instruments        Amounts                
(unaudited - millions of     presented in the      available                
 Canadian $)                    balance sheet   for offset(1)   Net amounts 
----------------------------------------------------------------------------
                                                                            
Derivative - Asset                                                          
  Power                                   178            (142)           36 
  Natural gas                              70             (67)            3 
  Foreign exchange                         32             (32)            - 
  Interest                                 18              (3)           15 
----------------------------------------------------------------------------
Total                                     298            (244)           54 
----------------------------------------------------------------------------
Derivative - Liability                                                      
  Power                                  (286)            142          (144)
  Natural gas                            (100)             67           (33)
  Foreign exchange                       (216)             32          (184)
  Interest                                (11)              3            (8)
----------------------------------------------------------------------------
Total                                    (613)            244          (369)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Amounts available for offset do not include cash collateral pledged or  
    received.                                                               

 
With respect to all financial arrangements, including the derivative
instruments presented above, as at June 30, 2013, the Company had
provided cash collateral of $201 million and letters of credit of $65
million to its counterparties. The Company held $1 million in cash
collateral and $2 million in letters of credit on asset exposures at
June 30, 2013.  
The following table shows the impact on the presentation of the fair
value of derivative instrument assets and liabilities had the Company
elected to present these contracts on a net basis as at December 31,
2012: 


 
----------------------------------------------------------------------------
                             Gross derivative                               
at December 31, 2012              instruments        Amounts                
(unaudited - millions of     presented in the      available                
 Canadian $)                    balance sheet   for offset(1)   Net amounts 
----------------------------------------------------------------------------
                                                                            
Derivative - Asset                                                          
  Power                                   215            (132)           83 
  Natural gas                              88             (83)            5 
  Foreign exchange                        119             (37)           82 
  Interest                                 24              (6)           18 
----------------------------------------------------------------------------
Total                                     446            (258)          188 
----------------------------------------------------------------------------
Derivative - Liability                                                      
  Power                                  (273)            132          (141)
  Natural gas                            (106)             83           (23)
  Foreign exchange                        (76)             37           (39)
  Interest                                (14)              6            (8)
----------------------------------------------------------------------------
Total                                    (469)            258          (211)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Amounts available for offset do not include cash collateral pledged or  
    received.                                                               

 
With respect to all financial arrangements, including the derivative
instruments presented above as at December 31, 2012, the Company had
provided cash collateral of $189 million and letters of credit of $45
million to its counterparties. The Company held $2 million in cash
collateral and $5 million in letters of credit on asset exposures at
December 31, 2012.  
CREDIT RISK RELATED CONTINGENT FEATURES  
Derivative contracts entered into to manage market risk often contain
financial assurance provisions that allow parties to the contracts to
manage credit risk. These provisions may require collate
ral 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 June 30, 2013, the
aggregate fair value of all derivative instruments with
credit-risk-related contingent features that were in a net liability
position was $36 million (December 31, 2012 - $37 million), for which
the Company had provided collateral in the normal course of business
of nil (December 31, 2012 - nil). If the credit-risk-related
contingent features in these agreements were triggered on June 30,
2013, the Company would have been required to provide collateral of
$36 million (December 31, 2012 - $37 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 feels it 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.  


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

 
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 (Level  inputs (Level       inputs                   
                   I)(1)          II)(1,2)     (Level III)(2)     Total     
              --------------- --------------- --------------- --------------
(unaudited -                                                                
 millions of                                                                
 Canadian $,   Jun 30  Dec 31  Jun 30  Dec 31  Jun 30  Dec 31 Jun 30 Dec 31 
 pre-tax)        2013    2012    2013    2012    2013    2012   2013   2012 
----------------------------------------------------------------------------
                                                                            
Derivative                                                                  
 instrument                                                                 
 assets:                                                                    
 Power                                                                      
  commodity                                                                 
  contracts         -       -     171     213       7       2    178    215 
 Natural gas                                                                
  commodity                                                                 
  contracts        65      75       5      13       -       -     70     88 
 Foreign                                                                    
  exchange                                                                  
  contracts         -       -      32     119       -       -     32    119 
 Interest rate                                                              
  contracts         -       -      18      24       -       -     18     24 
Derivative                                                                  
 Instrument                                                                 
 Liabilities:                                                               
 Power                                                                      
  commodity                                                                 
  contracts         -       -    (279)   (269)     (7)     (4)  (286)  (273)
 Natural gas                                                                
  commodity                                     
                            
  contracts       (85)    (95)    (15)    (11)      -       -   (100)  (106)
 Foreign                                                                    
  exchange                                                                  
  contracts         -       -    (216)    (76)      -       -   (216)   (76)
 Interest rate                                                              
  contracts         -       -     (11)    (14)      -       -    (11)   (14)
Non-derivative                                                              
 financial                                                                  
 instruments:                                                               
 Available for                                                              
  sale assets       -       -      47      44       -       -     47     44 
----------------------------------------------------------------------------
                  (20)    (20)   (248)     43       -      (2)  (268)    21 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) There were no transfers between Level I and Level II for the six months 
    ended June 30, 2013 and 2012.                                           
(2) There were no transfers between Level II and Level III for the six      
    months ended June 30, 2013 and 2012.                                    

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


 
----------------------------------------------------------------------------
                                           Derivatives(1)                   
                         -------------------------------------------------- 
                            three months ended         six months ended     
                                  June 30                   June 30         
                         ------------------------- -------------------------
(unaudited - millions of                                                    
 Canadian $, pre-tax)           2013         2012         2013         2012 
----------------------------------------------------------------------------
                                                                            
Balance at beginning of                                                     
 period                            1          (11)          (2)         (15)
Settlements                        1           (1)           1           (1)
Transfers out of Level                                                      
 III                              (1)           1           (1)           1 
Total (losses)/gains                                                        
 included in OCI                  (1)          18            2           22 
----------------------------------------------------------------------------
Balance at end of period           -            7            -            7 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) For the three and six months ended June 30, 2013 the unrealized gains or
    losses included in net income attributed to derivatives in the level III
    category that were still held at the reporting date was nil (2012 -     
    nil).                                                                   

 
A 10 per cent increase or decrease in commodity prices, with all
other variables held constant, would result in a $5 million decrease
or increase, respectively, in the fair value of outstanding
derivative instruments included in Level III as at June 30, 2013. 


 
10. Acquisition 

 
On June 28, 2013, TransCanada acquired the first of nine Ontario
solar power facilities from Canadian Solar Solutions Inc. for $55
million. TransCanada measured the assets and liabilities acquired at
fair value with substantially all of the purchase price allocated to
Plant, Property and Equipment. The combined capacity of the nine
projects is 86 MW and the cost of the portfolio will be approximately
$470 million.  
TransCanada anticipates the remaining eight projects will come into
service and be acquired by the end of 2014. The renewable energy
produced from these projects will be sold to the Ontario Power
Authority under a series of 20-year PPAs. 


 
11. 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 2013, TransCanada
currently expects spot prices to be less than the floor price for the
year, therefore no amounts received under the floor price mechanism
in the first six months of 2013 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. In addition, TransCanada and BPC
have each severally guaranteed one-half of certain contingent
financial obligations of Bruce A related to a sublease agreement and
certain other financial obligations. The Company's exposure under
certain of these guarantees is unlimited.  
In addition to the guarantees for Bruce Power, the Company and its
partners in certain other jointly owned entities have either (i)
jointly and severally, (ii) jointly or (iii) severally guaranteed the
financial performance of these entities related primarily to
redelivery of natural gas, PPA payments and the payment of
liabilities. 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.  
The carrying value of these guarantees has been included in other
long term liabilities. Information regarding the Company's guarantees
is as follows: 


 
----------------------------------------------------------------------------
at June 30, 2013                                                            
(unaudited - millions of                             Potential      Carrying
 Canadian $)                                Term   Exposure(1)         Value
----------------------------------------------------------------------------
                                                                            
Bruce Power                           ranging to                            
                                         2019(2)           713             9
Other jointly owned entities     ranging to 2040            41             9
----------------------------------------------------------------------------
                                                           754            18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) TransCanada's share of the potential estimated current or contingent    
    exposure.                                                               
(2) Except for one guarantee with no termination date that has no exposure  
    associated with it.                                                     
 
12. Subsequent Events 

 
On July 2, 2013, TransCanada completed the sale of a 45 per cent
interest in each of Gas Transmission Northwest LLC (GTN LLC) and
Bison Pipeline LLC (Bison LLC) to TC PipeLines, LP for an aggregate
purchase price of US$1.05 billion, which included US$146 million of
long-term debt for 45 per cent of GTN LLC debt outstanding plus
closing adjustments for working capital of $17 million. GTN LLC and
Bison LLC own the GTN and Bison natural gas pipelines, respectively.  
In July 2013, TransCanada issued US$500 million of three-year London
Interbank Offered Rate-based floating rate notes maturing on June 30,
2016, bearing interest at an initial annual rate of 0.95 per cent.  
Also in July 2013, TransCanada issued $450 million of ten-year and
$300 million of 30-year senior notes maturing on July 19, 2023 and
November 15, 2041, bearing interest rates of 3.69 and 4.55 per cent,
respectively.   
In July 2013, TC PipeLines, LP entered into a five-year, US$500
million term loan, maturing July 2018. 
Contacts:
TransCanada Media Enquiries:
Shawn Howard/Grady Semmens
403.920.7859 or 800.608.7859 
TransCanada Investor & Analyst Enquiries:
David Moneta/Lee Evans
403.920.7911 or 800.361.6522
www.transcanada.com