SYS-CON MEDIA Authors: Peter Silva, Kevin Jackson, Jessica Qiu, Dana Gardner, Dan Stolts

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TransCanada Reports Solid Second Quarter Results

Merrick Mainline Pipeline Project Brings Capital Program to $38 Billion

CALGARY, ALBERTA -- (Marketwired) -- 07/31/14 -- TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada) today announced net income attributable to common shares for second quarter 2014 of $416 million or $0.59 per share compared to $365 million or $0.52 per share for the same period in 2013. Comparable earnings for second quarter 2014 were $332 million or $0.47 per share compared to $357 million or $0.51 per share for the same period last year. TransCanada's Board of Directors also declared a quarterly dividend of $0.48 per common share for the quarter ending September 30, 2014, equivalent to $1.92 per common share on an annualized basis.

"The majority of our business segments performed well over the course of the second quarter and demonstrate the benefits of a diversified and growing portfolio of critical energy infrastructure assets," said Russ Girling, TransCanada's president and chief executive officer. "Although weak Alberta power prices and maintenance outages at Bruce Power weighed on second quarter results, both businesses are expected to produce stronger results in the future due to positive Alberta power market fundamentals and higher plant availability at Bruce Power."

With the recent addition of the Merrick Mainline Pipeline Project, our capital program now includes $38 billion of commercially secured projects that are backed by long-term contracts or cost of service business models. Our portfolio is comprised of $21 billion of liquids pipelines, $15 billion of natural gas pipelines, and $2 billion of power generation facilities. We continue to advance this unprecedented slate of growth initiatives, with many currently proceeding through their regulatory processes. Over the remainder of the decade, subject to required approvals, this blue-chip portfolio of contracted energy infrastructure projects is expected to generate significant long-term shareholder value from growth in 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 $416 million or $0.59
        per share 
    --  Comparable earnings of $332 million or $0.47 per share 
    --  Comparable earnings before interest, taxes, depreciation and
        amortization (EBITDA) of $1.2 billion 
    --  Funds generated from operations of $917 million 
--  Declared a quarterly dividend of $0.48 per common share for the quarter
    ending September 30, 2014 
--  Secured commercial support for the $1.9 billion Merrick Mainline
    Pipeline Project, an extension of the NGTL System 
--  Received regulatory approval for the $800 million Northern Courier
    Pipeline Project 
--  Closed the $190 million sale of Cancarb and its related power generation
    facility on April 15, 2014 
--  Filed a Project Description with the National Energy Board (NEB) for the
    Eastern Mainline Project 
--  Continue to progress regulatory applications for several of our major
    capital projects including Coastal GasLink, Prince Rupert Gas
    Transmission, Energy East, Grand Rapids, Heartland, the North Montney
    Mainline and Napanee 

Net income attributable to common shares for second quarter 2014 was $416 million or $0.59 per share compared to $365 million or $0.52 per share in second quarter 2013. Second quarter 2014 results included a net after-tax gain of $99 million from the sale of Cancarb and its related power generation facility and an after-tax $31 million termination expense for restructuring a natural gas storage contract. These amounts were excluded from comparable earnings.

Comparable earnings for second quarter 2014 were $332 million or $0.47 per share compared to $357 million or $0.51 per share for the same period in 2013. Higher earnings from Keystone and Mexican Pipelines were more than offset by lower contributions from Western Power and Bruce Power.

Notable recent developments in Liquids Pipelines, Natural Gas Pipelines, Energy and Corporate include:

Liquids Pipelines:


--  Energy East Pipeline: In March 2014, we filed a Project Description with
    the NEB. This is the first formal step in the regulatory process to
    receive the necessary approvals to build and operate the pipeline. The
    project is estimated to cost approximately $12 billion, excluding the
    transfer value of Canadian Mainline natural gas assets.
    
    Subject to regulatory approvals, the pipeline is anticipated to commence
    deliveries to Quebec in 2018, with service to New Brunswick to follow in
    late 2018. We continue to participate in Aboriginal and stakeholder
    engagement and associated field work as part of our initial design and
    planning. We intend to file the necessary regulatory applications in
    third quarter 2014 for approvals to construct and operate the pipeline
    project and terminal facilities. 


--  Keystone XL: On January 31, 2014, the Department of State (DOS) released
    its Final Supplemental Environmental Impact Statement (FSEIS) for the
    Keystone XL project. The results included in the report were consistent
    with previous environmental reviews of Keystone XL. The FSEIS concluded
    Keystone XL is "unlikely to significantly impact the rate of extraction
    in the oil sands" and that all other alternatives to Keystone XL are
    less efficient methods of transporting crude oil, and would result in
    significantly more greenhouse gas emissions, oil spills and risks to
    public safety. The report initiated the National Interest Determination
    period that was to last up to 90 days which involves consultation with
    other governmental agencies and provides an opportunity for public
    comment. The 30-day public comment period has concluded. On April 18,
    2014, the DOS announced that the National Interest Determination period
    has been extended indefinitely to allow them to consider the potential
    impact of the case discussed below on the Nebraska portion of the
    pipeline route.
    
    In February 2014, a Nebraska district court ruled that the state Public
    Service Commission, rather than Governor Heineman, has the authority to
    approve an alternative route through Nebraska for the Keystone XL
    project. Nebraska's Attorney General has filed an appeal and the
    Nebraska Supreme Court is expected to hear the appeal in September 2014.
    
    As of June 30, 2014, we have invested US$2.4 billion in the Keystone XL
    project. 


--  Northern Courier Pipeline Project: In October 2013, Suncor Energy
    announced that Fort Hills Energy LP is proceeding with the Fort Hills
    oil sands mining project. Our $800 million Northern Courier Pipeline
    Project will transport bitumen and diluent between the Fort Hills mine
    site and Suncor Energy's East Tank Farm located north of Fort McMurray,
    Alberta, and is fully contracted under a long-term agreement.
    
    On July 18, 2014, the Alberta Energy Regulator issued a permit approving
    our application to construct and operate the Northern Courier Pipeline.
    We currently expect construction on Northern Courier to begin in third
    quarter 2014, with it being ready for service in 2017. 

Natural Gas Pipelines:


--  NGTL System Expansions: The NGTL System is currently experiencing a
    significant amount of growth as a result of growing natural gas supply
    in northwestern Alberta and northeastern B.C. from unconventional gas
    plays and substantive growth in intra-basin delivery markets driven
    primarily by oil sands development and demand for gas-fired electric
    power generation. Approximately $250 million of capital projects have
    been placed into service in 2014. Another $3.8 billion of projects are
    either under construction, or have or will be filed with the NEB for
    approval. These projects include the North Montney Mainline and the
    Merrick Mainline Pipeline, along with other new supply and demand
    facilities. We continue to receive requests for new services and expect
    that this will lead to additional growth opportunities in the future.
    
    On June 4, 2014, we announced the signing of agreements for
    approximately 1.9 billion cubic feet per day (Bcf/d) of firm natural gas
    transportation services for the proposed Merrick Mainline Pipeline
    Project, a major extension of our NGTL System. The project will
    transport natural gas through the NGTL System to the inlet of the
    proposed Pacific Trail Pipeline that will terminate at the Kitimat LNG
    Terminal at Bish Cove near Kitimat, B.C. The proposed project will be an
    extension from the existing Groundbirch Mainline section of the NGTL
    System beginning near Dawson Creek, B.C. to its end point near the
    community of Summit Lake, B.C. The $1.9 billion project consists of
    approximately 260 kilometres (km) (161 miles) of 48-inch diameter pipe.
    We anticipate filing an application for approvals to build and operate
    the system with the NEB in fourth quarter 2014. Subject to the necessary
    regulatory approvals and a positive final investment decision for
    Kitimat LNG, we expect the Merrick Mainline to be in service in first
    quarter 2020.
    
    The NEB issued a Hearing Order in February 2014 for the $1.7 billion
    North Montney project, which is an extension and expansion of the NGTL
    System to receive and transport natural gas from the North Montney area
    of B.C. The proposed project consists of approximately 300 km (186
    miles) of pipeline and is expected to be placed in service in two
    sections, Aitken Creek in second quarter 2016 and Kahta in second
    quarter 2017. On June 17, 2014, the NEB revised the procedural schedule,
    which has resulted in the oral portion of the hearing being rescheduled
    to mid-October 2014 for the Calgary phase, and mid-November for the Fort
    St. John phase. We now anticipate an NEB decision on the application in
    first quarter 2015. 


--  Canadian Mainline - LDC Settlement: In March 2014, the NEB responded to
    the LDC Settlement application we filed on December 20, 2013. The NEB
    did not approve the application as a settlement but allowed us the
    option to continue with the application as a contested tolls
    application, amend the application or terminate the processing of the
    application. We amended the application with additional information. On
    May 9, 2014, the NEB released a Hearing Order that sets out the process
    and schedule for the 2015 - 2030 Mainline Tolls application that
    incorporates the LDC Settlement, with the oral portion set to begin
    September 9, 2014. 


--  Canadian Mainline - Eastern Mainline Project: On May 8, 2014, we filed a
    Project Description with the NEB for the Eastern Mainline Project. The
    proposed project will add new facilities to our existing Canadian
    Mainline natural gas transmission system in southeastern Ontario as a
    result of the proposed transfer of a portion of the Canadian Mainline
    capacity to crude oil from natural gas service as part of our proposed
    Energy East Pipeline and an open season that closed in January 2014. The
    proposed scope of the project will add 0.6 Bcf/d of new capacity and
    will ensure appropriate levels of capacity are available to meet the
    requirements of existing shippers as well as new firm service
    commitments contracted for in the Eastern Triangle segment of the
    Canadian Mainline. Subject to regulatory approvals, the project is
    expected to be in service in second quarter 2017. 


--  Tamazunchale Pipeline Extension Project: Construction of the US$600
    million extension is currently expected to be completed by the end of
    September 2014 with delays attributed to archeological findings along
    the pipeline route. Under the terms of the Transportation Service
    Agreement, these delays are recognized as a force majeure with
    provisions allowing for collection of revenue as per the original
    service commencement date of March 9, 2014. 


--  Prince Rupert Gas Transmission Project: The Environmental Assessment
    application submitted to the B.C. Environmental Assessment Office (EAO)
    in April 2014 was deemed complete. The EAO initiated a 180-day review
    period which included a 45-day public comment period that was completed
    on July 10, 2014. A facilities application was also filed with the B.C.
    Oil and Gas Commission in April 2014. Regulatory approval for the
    pipeline is expected in fourth quarter 2014 and a final investment
    decision from Pacific Northwest LNG is expected to follow at the end of
    2014. 


--  Alaska LNG Project: In April 2014, the State of Alaska passed new
    legislation that will transition from the Alaska Gasline Inducement Act
    (AGIA) and enable a new commercial arrangement to be established with
    us, the three major Alaska North Slope producers, and the Alaska Gasline
    Development Corp. It was also agreed that a Liquefied Natural Gas (LNG)
    export project, rather than a pipeline to Alberta, is currently the best
    opportunity to commercialize Alaska North Slope gas resources in current
    market conditions.
    
    On June 9, 2014, we executed an agreement with the State of Alaska to
    abandon the AGIA license and executed a Precedent Agreement, where we
    will act as the transporter of the State's portion of natural gas under
    a long-term shipping contract in the Alaska LNG Project. On June 30,
    2014, the Alaska LNG Project entered the pre-front end engineering and
    design (pre-FEED) phase following the execution of a Joint Venture
    Agreement among ourselves, the three major Alaska North Slope producers
    and Alaska Gasline Development Corp. The pre-FEED work is anticipated to
    take two years to complete with our share of the cost to be
    approximately US$100 million. The Precedent Agreement also provides us
    with full recovery of development costs in the event the project does
    not proceed. 

Energy:


--  Cancarb:  In January 2014, we reached an agreement to sell Cancarb and
    its related power generation facility for gross proceeds of $190
    million. The sale closed on April 15, 2014 and we recognized an after-
    tax gain of $99 million in second quarter 2014. 


--  Natural Gas Storage: Effective April 30, 2014, we terminated a 38
    billion cubic feet long-term natural gas storage contract in Alberta
    with Niska Gas Storage. As a result, we recorded a $31 million after-tax
    charge in second quarter 2014. We have re-contracted for new natural gas
    storage services in Alberta with Niska Gas Storage starting May 1, 2014
    for a six year period at a reduced average volume. 

Corporate:


--  Our Board of Directors declared a quarterly dividend of $0.48 per share
    for the quarter ending September 30, 2014 on TransCanada's outstanding
    common shares. The quarterly amount is equivalent to $1.92 per common
    share on an annualized basis. 

Teleconference - Audio and Slide Presentation:

We will hold a teleconference and webcast on Thursday, July 31, 2014 to discuss our second quarter 2014 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 2 p.m. (MT) / 4 p.m. (ET).

Analysts, members of the media and other interested parties are invited to participate by calling 866.223.7781 or 416.340.2216 (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 (ET) on August 7, 2014. Please call 800.408.3053 or 905.694.9451 and enter pass code 5722299.

The unaudited interim Consolidated Financial Statements and Management's Discussion and Analysis (MD&A) are available under TransCanada's profile 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 31, 2014 and 2013 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, comparable 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 31, 2014.

Quarterly report to shareholders

Second quarter 2014

Financial highlights


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                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $, except                                          
 per share amounts)                      2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Income                                                                      
Revenue                                 2,234     2,009     5,118     4,261 
Net income attributable to common                                           
 shares                                   416       365       828       811 
  per common share - basic and                                              
   diluted                              $0.59     $0.52     $1.17     $1.15 
Comparable EBITDA(1)                    1,217     1,143     2,613     2,311 
Comparable earnings(1)                    332       357       754       727 
  per common share(1)                   $0.47     $0.51     $1.07     $1.03 
                                                                            
Operating cash flow                                                         
Funds generated from operations(1)        917       955     2,019     1,871 
Decrease/(increase) in operating                                            
 working capital                          202      (114)       79      (324)
----------------------------------------------------------------------------
Net cash provided by operations         1,119       841     2,098     1,547 
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Investing activities                                                        
Capital expenditures                     (967)   (1,109)   (1,745)   (2,038)
Equity investments                        (40)      (39)     (129)      (71)
Acquisitions                                -       (55)        -       (55)
Proceeds from sale of assets, net of                                        
 transaction costs                        187         -       187         - 
Dividends paid                                                              
Per common share                        $0.48     $0.46     $0.96     $0.92 
Basic common shares outstanding                                             
 (millions)                                                                 
Average for the period                    708       707       708       706 
End of period                             708       707       708       707 
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1  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.                          

Management's discussion and analysis

July 31, 2014

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, 2014, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2014 which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2013 audited consolidated financial statements and notes and the MD&A in our 2013 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 2013 Annual Report.

All information is as of July 31, 2014 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 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 accounting changes, 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 
--  costs for labour, equipment and materials 
--  access to capital markets 
--  interest and foreign exchange rates 
--  weather 
--  cyber security 
--  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 2013 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 
--  funds generated from operations 
--  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 tax expense. 

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

EBITDA and EBIT

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

Funds generated from operations

Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period and is used to provide a consistent measure of the cash generating performance of our assets. 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.


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

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


--  certain fair value adjustments relating to risk management activities 
--  income tax refunds and adjustments 
--  gains or losses on sales of assets 
--  legal, contractual and bankruptcy settlements 
--  impact of regulatory or arbitration decisions relating to prior year
    earnings 
--  write-downs of assets and investments. 

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

Consolidated results - second quarter 2014


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                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $, except                                          
 per share amounts)                      2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Natural gas pipelines                     496       399     1,082       947 
Liquids pipelines(1)                      195       149       387       291 
Energy                                    216       243       473       442 
Corporate                                 (27)      (22)      (70)      (59)
----------------------------------------------------------------------------
Total segmented earnings                  880       769     1,872     1,621 
Interest expense                         (297)     (252)     (571)     (510)
Interest income and other                  54       (11)       46         2 
----------------------------------------------------------------------------
Income before income taxes                637       506     1,347     1,113 
Income tax expense                       (165)      (98)     (386)     (213)
----------------------------------------------------------------------------
Net income                                472       408       961       900 
Net income attributable to non-                                             
 controlling interests                    (31)      (23)      (85)      (54)
----------------------------------------------------------------------------
Net income attributable to                                                  
 controlling interests                    441       385       876       846 
Preferred share dividends                 (25)      (20)      (48)      (35)
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Net income attributable to common                                           
 shares                                   416       365       828       811 
----------------------------------------------------------------------------
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Net income per common share - basic                                         
 and diluted                            $0.59     $0.52     $1.17     $1.15 
----------------------------------------------------------------------------
1  Previously Oil Pipelines.                                                

Net income attributable to common shares increased by $51 million for the three months ended June 30, 2014 compared to the same period in 2013. Second quarter 2014 results included:


--  a gain on sale of Cancarb Limited and its related power generation
    business of $99 million after tax 
--  a net loss resulting from the termination of a contract with Niska Gas
    Storage of $31 million after tax. 

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.

Net income attributable to common shares increased by $17 million for the six months ended June 30, 2014 compared to the same period in 2013. The 2014 results included:


--  a gain on sale of Cancarb Limited and its related power generation
    business of $99 million after tax 
--  a net loss resulting from a termination payment to Niska Gas Storage for
    contract restructuring of $31 million after tax. 

The results for the first six months of 2013 included $84 million of Canadian Mainline net income related to 2012 from the NEB decision (RH-003-2011) as well as 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.

The items discussed above are excluded from comparable earnings for the relevant periods. Certain unrealized fair value adjustments relating to risk management activities are also excluded from comparable earnings. The remainder of net income is equivalent to comparable earnings. A reconciliation of net income attributable to common shares to comparable earnings is shown in the following table.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS


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                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $, except                                          
 per share amounts)                      2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Net income attributable to common                                           
 shares                                   416       365       828       811 
Specific items (net of tax):                                                
  Energy - Cancarb gain on sale           (99)        -       (99)        - 
  Energy - Niska contract                                                   
   termination                             31         -        31         - 
  Risk management activities(1)           (16)       17        (6)       25 
  Natural gas pipelines - NEB                                               
   decision - 2012                          -         -         -       (84)
  Part VI.I income tax adjustment           -       (25)        -       (25)
----------------------------------------------------------------------------
Comparable earnings                       332       357       754       727 
----------------------------------------------------------------------------
                                                                            
Net income per common share             $0.59     $0.52     $1.17     $1.15 
Specific items (net of tax):                                                
  Energy - Cancarb gain on sale         (0.14)        -     (0.14)        - 
  Energy - Niska contract                                                   
   termination                           0.04         -      0.04         - 
  Risk management activities(1)         (0.02)     0.03         -      0.04 
  Natural gas pipeline - NEB                                                
   decision - 2012                          -         -         -     (0.12)
  Part VI.I income tax adjustment           -     (0.04)        -     (0.04)
----------------------------------------------------------------------------
Comparable earnings per share           $0.47     $0.51     $1.07     $1.03 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
1   Risk management activities       three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
    (unaudited - millions of $)          2014      2013      2014      2013 
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
                                                                            
    Canadian Power                         (2)       (4)       (2)       (6)
    U.S. Power                             (9)      (18)      (11)      (17)
    Natural gas Storage                     6         4        (3)        1 
    Foreign exchange                       25        (9)       23       (15)
    Income tax attributable to risk                                         
     management activities                 (4)       10        (1)       12 
    ------------------------------------------------------------------------
    Total gains/(losses) from risk                                          
     management activities                 16       (17)        6       (25)
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------

Comparable earnings decreased by $25 million for the three months ended June 30, 2014 compared to the same period in 2013, a decrease of $0.04 per share.

This was primarily the net effect of the following:


--  incremental earnings from the Gulf Coast extension of the Keystone
    Pipeline System 
--  lower earnings from Western Power as a result of lower realized power
    prices 
--  lower equity income from Bruce Power mainly due to increased planned and
    unplanned outage days at Bruce A, partially offset by fewer outage days
    at Bruce B 
--  higher earnings from Mexico pipelines resulting from contract revenues
    recognized from the Tamazunchale Extension. 

Comparable earnings increased by $27 million for the six months ended June 30, 2014 compared to the same period in 2013, an increase of $0.04 per share.

This was primarily the net effect of:


--  incremental earnings from the Gulf Coast extension of the Keystone
    Pipeline System 
--  lower earnings from Western Power as a result of lower realized power
    prices 
--  higher earnings from U.S. Power mainly because of higher realized
    capacity and power prices 
--  higher earnings from Mexico pipelines resulting from contract revenues
    recognized from the Tamazunchale Extension 
--  higher earnings from U.S. natural gas pipelines due to higher
    transportation revenues at Great Lakes and higher contributions from TC
    PipeLines, LP reflecting colder winter weather and increased demand. 

The stronger U.S. dollar this quarter compared to the same period in 2013 positively impacted the results in our U.S. businesses, which were mostly offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our net exposure through our hedging program.

CAPITAL PROGRAM

We are developing quality projects under our long-term capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cashflow.

Our capital program is comprised of $12 billion of small to medium-sized projects and $26 billion of large scale projects. Amounts presented exclude the impact of foreign exchange and capitalized interest.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                          Estimated         
at June 30, 2014                             Expected In-   Project  Amount 
(unaudited - billions of $)   Segment        Service Date      Cost   Spent 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Small to medium-sized                                                       
 projects                                                                   
Tamazunchale Extension(1)     Natural Gas                                   
                               Pipelines             2014    US 0.6  US 0.5 
Ontario Solar                 Energy            2014-2015       0.5     0.2 
Houston Lateral and Terminal  Liquids                                       
                               Pipelines             2015    US 0.4  US 0.3 
Heartland and TC Terminals    Liquids                                       
                               Pipelines             2016       0.9     0.1 
Keystone Hardisty Terminal    Liquids       Approximately                   
                               Pipelines     2 years from                   
                                            date Keystone                   
                                                XL permit                   
                                                 received       0.3     0.1 
Topolobampo                   Natural Gas                                   
                               Pipelines             2016    US 1.0  US 0.5 
Mazatlan                      Natural Gas                                   
                               Pipelines             2016    US 0.4  US 0.1 
Grand Rapids(2)               Liquids                                       
                               Pipelines        2015-2017       1.5     0.1 
Northern Courier              Liquids                                       
                               Pipelines             2017       0.8     0.1 
NGTL System - North Montney   Natural Gas                                   
                               Pipelines        2016-2017       1.7     0.1 
            - Merrick         Natural Gas                                   
                               Pipelines             2020       1.9       - 
            - Other           Natural Gas                                   
                               Pipelines        2014-2016       0.5     0.2 
Napanee                       Energy         2017 or 2018       1.0       - 
----------------------------------------------------------------------------
                                                               11.5     2.3 
----------------------------------------------------------------------------
Large scale projects(3)                                                     
Keystone XL(4)                Liquids       Approximately                   
                               Pipelines     2 years from                   
                                              date permit                   
                                                 received    US 5.4  US 2.4 
Energy East(5)                Liquids                                       
                               Pipelines             2018      12.0     0.3 
Prince Rupert Gas             Natural Gas                                   
 Transmission                  Pipelines             2018       5.0     0.2 
Coastal GasLink               Natural Gas                                   
                               Pipelines            2018+       4.0     0.2 
----------------------------------------------------------------------------
                                                               26.4     3.1 
----------------------------------------------------------------------------
                                                               37.9     5.4 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  A force majeure has delayed completion of construction, however, revenue 
   has been recorded in second quarter 2014 as per the terms of the         
   Transportation Service Agreement.                                        
2  Represents our 50 per cent share.                                        
3  Subject to cost adjustments due to market conditions, route refinement,  
   permitting conditions and scheduling.                                    
4  Estimated project cost will increase depending on the timing of the      
   Presidential permit.                                                     
5  Excludes transfer of Canadian Mainline natural gas assets.               

Outlook

The earnings outlook previously included in the 2013 Annual Report is expected to be impacted by:


--  the gain on sale of Cancarb Limited and its related power generation
    facility 
--  the termination payment to Niksa Gas Storage for the contract
    restructuring 
--  increased outage days at Bruce A. 

See the MD&A in our 2013 Annual Report for further information about our outlook.

Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Comparable EBITDA                         759       644     1,607     1,390 
Comparable depreciation and                                                 
 amortization(1)                         (263)     (245)     (525)     (485)
----------------------------------------------------------------------------
Comparable EBIT                           496       399     1,082       905 
----------------------------------------------------------------------------
Specific item:                                                              
  NEB decision - 2012                       -         -         -        42 
----------------------------------------------------------------------------
Segmented earnings                        496       399     1,082       947 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  In 2014, comparable depreciation and amortization is equivalent to the   
   GAAP measure, depreciation and amortization. In 2013, comparable         
   depreciation is adjusted by $13 million relating to the impact from the  
   NEB decision (RH-003-2011).                                              

Our Natural Gas Pipelines segmented earnings increased by $97 million for the three months ended June 30, 2014 and by $135 million for the six months ended June 30, 2014 compared to the same periods in 2013. Natural gas segmented earnings for the six months ended June 30, 2013 included $42 million related to the 2012 impact of the NEB decision (RH-003-2011). This amount has been excluded in our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT and comparable EBITDA and are discussed below.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Canadian Pipelines                                                          
Canadian Mainline                         312       263       627       543 
NGTL System                               205       193       424       375 
Foothills                                  27        28        54        57 
Other Canadian pipelines (TQM(1),                                           
 Ventures LP)                               5         7        10        13 
----------------------------------------------------------------------------
Canadian Pipelines - comparable                                             
 EBITDA                                   549       491     1,115       988 
Comparable depreciation and                                                 
 amortization                            (204)     (190)     (407)     (374)
----------------------------------------------------------------------------
Canadian Pipelines - comparable EBIT      345       301       708       614 
----------------------------------------------------------------------------
                                                                            
U.S. and International Pipelines                                            
 (US$)                                                                      
ANR                                        33        32       111       122 
TC PipeLines, LP(1,2)                      21        13        47        30 
Great Lakes(3)                              9         8        28        18 
Other U.S. pipelines (Bison(4),                                             
 Iroquois(1), GTN(4), Portland(5))         29        49        74       120 
Mexico (Guadalajara, Tamazunchale)         49        26        74        52 
International and other(6)                 (1)       (4)       (2)       (6)
Non-controlling interests(7)               54        31       127        74 
----------------------------------------------------------------------------
U.S. and International Pipelines -                                          
 comparable EBITDA                        194       155       459       410 
Comparable depreciation and                                                 
 amortization                             (54)      (54)     (108)     (109)
----------------------------------------------------------------------------
U.S. and International Pipelines -                                          
 comparable EBIT                          140       101       351       301 
Foreign exchange impact                    13         2        34         4 
----------------------------------------------------------------------------
U.S. and International Pipelines -                                          
 comparable EBIT(Cdn$)                    153       103       385       305 
----------------------------------------------------------------------------
Business Development comparable                                             
 EBITDA and EBIT                           (2)       (5)      (11)      (14)
----------------------------------------------------------------------------
Natural Gas Pipelines - comparable                                          
 EBIT                                     496       399     1,082       905 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Results from TQM, Northern Border, Iroquois, TransGas and Gas            
   Pacifico/INNERGY reflect our share of equity income from these           
   investments.                                                             
2  Effective May 22, 2013, our ownership interest in TC PipeLines, LP       
   decreased from 33.3 per cent to 28.9 per cent. On July 1, 2013, we sold  
   45 per cent of GTN and Bison to TC PipeLines, LP. The following shows our
   ownership interest in TC PipeLines, LP and our effective ownership of    
   GTN, Bison, and Great Lakes through our ownership interest in TC         
   PipeLines, LP for the periods presented.                                 
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
                                             Ownership percentage as of     
                                        ------------------------------------
                                        ------------------------------------
                                           July 1,    May 22,     January 1,
                                              2013       2013           2013
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
                                                                            
    TC PipeLines, LP                          28.9       28.9           33.3
    Effective ownership through TC                                          
     PipeLines, LP:                                                         
      GTN/Bison                               20.2        7.2            8.3
      Great Lakes                             13.4       13.4           15.5
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
3  Represents our 53.6 per cent direct ownership interest.                  
4  Effective July 1, 2013, represents our 30 per cent direct ownership      
   interest. Prior to July 1, 2013, our direct ownership interest was 75 per
   cent.                                                                    
5  Represents our 61.7 per cent ownership interest.                         
6  Includes our share of the equity income from Gas Pacifico/INNERGY and    
   TransGas as well as general and administration costs relating to our U.S.
   and International pipelines.                                             
7  Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do
   not own.                                                                 

CANADIAN PIPELINES

Net income and comparable EBITDA 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 comparable EBIT but do not impact net income as they are recovered in revenue on a flow-through basis.

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                      three months ended   six months ended 
                                           June 30             June 30      
                                     ------------------- -------------------
                                     ------------------- -------------------
(unaudited - millions of $)               2014      2013      2014      2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Canadian Mainline - net income              58        67       124       218
Canadian Mainline - comparable                                              
 earnings                                   58        67       124       134
NGTL System                                 58        58       121       114
Foothills                                    4         5         8         9
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Canadian Mainline's net income decreased by $9 million and $94 million for the three and six months ended June 30, 2014 compared to the same periods in 2013 as net income in first quarter 2013 included $84 million related to the 2012 impact of the NEB decision (RH-003-2011), which was excluded from comparable earnings. Comparable earnings in both years reflect an ROE of 11.50 per cent on deemed common equity of 40 per cent and have decreased by $9 million and $10 million for the three and six months ended June 30, 2014 compared to the same periods in 2013 because of a lower average investment base as well as carrying charges owed to shippers on the Tolls Stabilization Account.

Net income for the NGTL System was unchanged for the three months ended June 30, 2014 and increased by $7 million for the six months ended June 30, 2014 compared to the same periods in 2013. A higher average investment base as well as an increase in the ROE had a positive impact on earnings. These increases were partially offset by increased OM&A costs at risk under the terms of the 2013-2014 NGTL Settlement approved by the NEB in November 2013. The Settlement included an ROE of 10.10 per cent on deemed common equity of 40 per cent and included annual fixed amounts for certain OM&A costs. Results for the three and six months ended June 30, 2013 reflect the previously approved ROE of 9.70 per cent on deemed common equity of 40 per cent.

U.S. AND INTERNATIONAL PIPELINES

Earnings for our U.S. natural gas pipelines operations are 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 increased by US$39 million and US$49 million for the three and six months ended June 30, 2014 compared to the same periods in 2013. This was the net effect of:


--  contract revenues recognized from the Tamazunchale Extension in the
    three months ended June 30, 2014. The Tamazunchale Extension project has
    experienced delays in completing the construction due to archeological
    findings along the pipeline route. The CFE agreed that, under the terms
    of the TSA, these delays constitute force majeure and, as a result,
    collection and recognition of revenue commenced on March 9, 2014. 
--  higher transportation revenues at Great Lakes and higher contributions
    from TC PipeLines, LP reflecting colder winter weather and increased
    demand 
--  higher OM&A costs at ANR as well as lower storage revenues in first
    quarter 2014. 

A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. operations.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $18 million and $40 million for the three and six months ended June 30, 2014 compared to the same periods in 2013, mainly because of a higher investment base and higher depreciation rates on the NGTL System.

OPERATING STATISTICS - WHOLLY OWNED PIPELINES


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                      Canadian        NGTL                  
six months ended June 30            Mainline(1)    System(2)       ANR(3)   
                                   ------------- ------------- -------------
                                   ------------- ------------- -------------
(unaudited)                          2014   2013   2014   2013   2014   2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Average investment base (millions                                           
 of $)                              5,667  5,871  6,179  5,882    n/a    n/a
Delivery volumes (Bcf)                                                      
  Total                               842    704  1,996  1,832    863    823
  Average per day                     4.7    3.9   11.0   10.1    4.8    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, 2014 were   
   599 Bcf (2013 - 397 Bcf). Average per day was 3.3 Bcf (2013 - 2.2 Bcf).  
2  Field receipt volumes for the NGTL System for the six months ended June  
   30, 2014 were 1,879 Bcf (2013 - 1,840 Bcf). Average per day was 10.4 Bcf 
   (2013 - 10.2 Bcf).                                                       
3  Under its current rates, which are approved by the FERC, changes in      
   average investment base do not affect results.                           

Liquids Pipelines(1)

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Comparable EBITDA                         249       186       490       365 
Comparable depreciation and                                                 
 amortization(2)                          (54)      (37)     (103)      (74)
----------------------------------------------------------------------------
Comparable EBIT                           195       149       387       291 
Specific items                              -         -         -         - 
----------------------------------------------------------------------------
Segmented earnings                        195       149       387       291 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Previously Oil Pipelines.                                                
2  Comparable depreciation and amortization is equivalent to the GAAP       
   measure, depreciation and amortization.                                  

Liquids Pipelines segmented earnings increased by $46 million for the three months ended June 30, 2014 and increased by $96 million for the six months ended June 30, 2014 compared to the same periods in 2013. Liquids Pipelines segmented earnings are equivalent to comparable EBIT and comparable EBITDA and are discussed below.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Keystone Pipeline System                  256       187       504       373 
Liquids Pipelines Business                                                  
 Development                               (7)       (1)      (14)       (8)
----------------------------------------------------------------------------
Liquids Pipelines - comparable                                              
 EBITDA                                   249       186       490       365 
Comparable depreciation and                                                 
 amortization                             (54)      (37)     (103)      (74)
----------------------------------------------------------------------------
Liquids Pipelines - comparable EBIT       195       149       387       291 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable EBIT denominated as                                              
 follows:                                                                   
Canadian dollars                           50        52        99        99 
U.S. dollars                              133        95       262       189 
Foreign exchange impact                    12         2        26         3 
----------------------------------------------------------------------------
                                          195       149       387       291 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Comparable EBITDA from our Keystone Pipeline System is generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and provides opportunities to generate incremental earnings.

Comparable EBITDA for the Keystone Pipeline System increased by $69 million for the three months ended June 30, 2014 and increased by $131 million for the six months ended June 30, 2014 compared to the same periods in 2013. These increases were primarily due to:


--  incremental earnings from the Gulf Coast extension which was placed in
    service in January 2014 
--  a stronger U.S. dollar had a positive impact on the Canadian dollar
    equivalent comparable earnings from our U.S. operations. 

BUSINESS DEVELOPMENT

Business development expenses for the three and six months ended June 30, 2014 were $6 million higher than the same periods in 2013 primarily due to lower capitalization of business development costs in 2014.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $17 million for the three months ended June 30, 2014 and by $29 million for the six months ended June 30, 2014 compared to the same periods in 2013 due to the Gulf Coast extension being placed in service.

Energy

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Comparable EBITDA                         231       330       576       607 
Comparable depreciation and                                                 
 amortization(1)                          (77)      (69)     (154)     (143)
----------------------------------------------------------------------------
Comparable EBIT                           154       261       422       464 
----------------------------------------------------------------------------
Specific items (pre-tax):                                                   
  Cancarb gain on sale                    108         -       108         - 
  Niska contract termination              (41)        -       (41)        - 
  Risk management activities               (5)      (18)      (16)      (22)
----------------------------------------------------------------------------
Segmented earnings                        216       243       473       442 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Comparable depreciation and amortization is equivalent to the GAAP       
   measure, depreciation and amortization.                                  

Our Energy segmented earnings decreased by $27 million for the three months ended June 30, 2014 and increased by $31 million for the six months ended June 30, 2014 compared to the same periods in 2013.

Energy segmented earnings included the following specific items for the three and six months ended June 30, 2014:


--  a gain of $108 million ($99 million after tax) on the sale of Cancarb
    Limited and its related power generation business, which closed on April
    15, 2014 
--  a net loss resulting from the contract termination payment to Niska Gas
    Storage of $41 million ($31 million after-tax) effective April 30, 2014 
--  unrealized gains and losses from changes in the fair value of certain
    derivatives used to reduce our exposure to certain commodity price risks
    as follows: 

    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
    Risk management activities       three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
    (unaudited - millions of $, pre-                                        
     tax)                                2014      2013      2014      2013 
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
                                                                            
    Canadian Power                         (2)       (4)       (2)       (6)
    U.S. Power                             (9)      (18)      (11)      (17)
    Natural Gas Storage                     6         4        (3)        1 
    ------------------------------------------------------------------------
    Total losses from risk                                                  
     management activities                 (5)      (18)      (16)      (22)
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------

The remainder of the Energy segmented earnings are equivalent to comparable EBITDA and comparable EBIT and are discussed below.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Canadian Power                                                              
Western Power                              46       117       118       191 
Eastern Power(1)                           70        69       163       159 
Bruce Power                                24        59        88        90 
----------------------------------------------------------------------------
Canadian Power - comparable                                                 
 EBITDA(2)                                140       245       369       440 
Comparable depreciation and                                                 
 amortization                             (45)      (43)      (89)      (86)
----------------------------------------------------------------------------
Canadian Power - comparable EBIT(2)        95       202       280       354 
U.S. Power (US$)                                                            
U.S. Power - comparable EBITDA             88        80       174       147 
Comparable depreciation and                                                 
 amortization                             (27)      (23)      (54)      (51)
----------------------------------------------------------------------------
U.S. Power - comparable EBIT               61        57       120        96 
Foreign exchange impact                     6         1        11         2 
----------------------------------------------------------------------------
U.S. Power - comparable EBIT (Cdn$)        67        58       131        98 
----------------------------------------------------------------------------
Natural Gas Storage and other                                               
Natural Gas Storage and other -                                             
 comparable EBITDA                          2         9        29        27 
Comparable depreciation and                                                 
 amortization                              (3)       (2)       (6)       (5)
----------------------------------------------------------------------------
Natural Gas Storage and other -                                             
 comparable EBIT                           (1)        7        23        22 
Business Development comparable                                             
 EBITDA and EBIT                           (7)       (6)      (12)      (10)
----------------------------------------------------------------------------
Energy - comparable EBIT(2)               154       261       422       464 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Includes four Ontario solar facilities acquired between June and December
   2013.                                                                    
2  Includes our share of equity income from our investments in ASTC Power   
   Partnership, Portlands Energy and Bruce Power.                           

Comparable EBITDA for Energy decreased by $99 million for the three months ended June 30, 2014 compared to the same period in 2013. The decrease was the net effect of:


--  lower earnings from Western Power as a result of lower realized power
    prices 
--  lower equity income from Bruce Power mainly due to increased planned and
    unplanned outage days at Bruce A, partially offset by fewer outage days
    at Bruce B 
--  higher earnings from U.S. Power mainly because of higher realized
    capacity prices 
--  lower earnings from Natural Gas Storage due to lower realized natural
    gas storage spreads. 

Comparable EBITDA for Energy decreased by $31 million for the six months ended June 30, 2014 compared to the same period in 2013. The decrease was the net effect of:


--  lower earnings from Western Power as a result of lower realized power
    prices 
--  higher earnings from U.S. Power mainly because of higher realized
    capacity and power prices 
--  higher earnings from Eastern Power due to the incremental earnings from
    the Ontario solar facilities acquired in 2013. 

A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. operations.

CANADIAN POWER

Western and Eastern Power


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Revenue                                                                     
Western Power                             160       157       341       297 
Eastern Power(1)                           88        91       230       200 
Other(2)                                    6        22        57        53 
----------------------------------------------------------------------------
                                          254       270       628       550 
Income from equity investments(3)           8        66        28        88 
Commodity purchases resold                (90)      (83)     (191)     (150)
Plant operating costs and other           (58)      (71)     (186)     (144)
Exclude risk management activities          2         4         2         6 
----------------------------------------------------------------------------
Comparable EBITDA                         116       186       281       350 
Comparable depreciation and                                                 
 amortization                             (45)      (43)      (89)      (86)
----------------------------------------------------------------------------
Comparable EBIT                            71       143       192       264 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Breakdown of comparable EBITDA                                              
Western Power                              46       117       118       191 
Eastern Power                              70        69       163       159 
----------------------------------------------------------------------------
Comparable EBITDA                         116       186       281       350 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
1  Includes four Ontario solar facilities acquired between June and December
   2013.                                                                    
2  Includes sale of excess natural gas purchased for generation and Cancarb 
   sales of thermal carbon black. Sale of Cancarb closed April 15, 2014.    
3  Includes our share of equity income from our investments in ASTC Power   
   Partnership, which holds the Sundance B PPA, and Portlands Energy.       

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)                              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Sales volumes (GWh)                                                         
Supply                                                                      
  Generation                                                                
    Western Power                         611       687     1,220     1,357 
    Eastern Power(1)                      596       750     1,873     2,096 
  Purchased                                                                 
    Sundance A & B and Sheerness                                            
     PPAs(2)                            2,598     1,788     5,398     3,495 
    Other purchases                         2         -         7         - 
----------------------------------------------------------------------------
                                        3,807     3,225     8,498     6,948 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales                                                                       
  Contracted                                                                
    Western Power                       2,434     1,939     4,895     3,646 
    Eastern Power(1)                      596       750     1,873     2,096 
  Spot                                                                      
    Western Power                         777       536     1,730     1,206 
----------------------------------------------------------------------------
                                        3,807     3,225     8,498     6,948 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Plant availability(3)                                                       
Western Power(4)                           94%       92%       95%       94%
Eastern Power(1,5)                         73%       80%       86%       88%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Includes four Ontario solar facilities acquired between June and December
   2013.                                                                    
2  Sundance A Unit 1 returned to service in September 2013 and Unit 2       
   returned to service in October 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

Western Power's comparable EBITDA decreased by $71 million and $73 million for the three and six months ended June 30, 2014 compared to the same periods in 2013 due to the net effect of:


--  lower realized power prices 
--  incremental earnings from the return to service of the Sundance A PPA
    Unit 1 in September 2013 and Unit 2 in October 2013 which also resulted
    in increased volume purchases and sales. 

Average spot market power prices in Alberta decreased by 66 per cent from $123/MWh to $42/MWh for the three months ended June 30, 2014 and 45 per cent from $94/MWh to $52/MWh for the six months ended June 30, 2014, compared to the same periods in 2013. Strong coal fleet availability and new wind capacity have resulted in significantly lower prices in spite of strong growth in Alberta power demand. Realized power prices on power sales can be higher or lower than spot market power prices in any given period as a result of contracting activities.

Seventy-six per cent of Western Power sales volumes were sold under contract in second quarter 2014 and 78 per cent in second quarter 2013.

Eastern Power

Eastern Power's comparable EBITDA increased by $1 million and $4 million for the three and six months ended June 30, 2014 compared to the same period in 2013 mainly due to the incremental earnings from the four Ontario solar facilities acquired in 2013.

Lower plant availability in Eastern Power in second quarter 2014 was the result of lower availability at Halton Hills because of a maintenance outage.

BRUCE POWER

Our proportionate share


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                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $, unless                                          
 noted otherwise)                        2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Income/(loss) from equity                                                   
 investments(1)                                                             
Bruce A                                    (2)       51        47        87 
Bruce B                                    26         8        41         3 
----------------------------------------------------------------------------
                                           24        59        88        90 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comprised of:                                                               
  Revenues                                265       306       565       593 
  Operating expenses                     (164)     (172)     (321)     (344)
  Depreciation and other                  (77)      (75)     (156)     (159)
----------------------------------------------------------------------------
                                           24        59        88        90 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bruce Power - Other information                                             
Plant availability(2)                                                       
  Bruce A                                  64%       88%       72%       77%
  Bruce B                                  93%       80%       89%       79%
  Combined Bruce Power                     79%       84%       82%       78%
Planned outage days                                                         
  Bruce A                                  84        33        84       123 
  Bruce B                                  25        70        74       140 
Unplanned outage days                                                       
  Bruce A                                  45         -       105         8 
  Bruce B                                   -         3         -        12 
Sales volumes (GWh)(1)                                                      
  Bruce A                               2,037     2,464     4,564     4,561 
  Bruce B                               2,048     1,726     3,972     3,460 
----------------------------------------------------------------------------
                                        4,085     4,190     8,536     8,021 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized sales price per MWh (3)                                            
  Bruce A                                 $72       $71       $71       $70 
  Bruce B                                 $55       $54       $55       $53 
  Combined Bruce Power                    $62       $63       $62       $61 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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  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 decreased by $53 million and $40 million for the three and six months ended June 30, 2014 compared to the same periods in 2013. The decrease was mainly due to:


--  lower earnings from Unit 3 due to a planned outage which began in April
    2014 
--  lower volumes due to increased unplanned outage days, primarily on Units
    1 and 2. 

These decreases were partially offset by higher earnings from Unit 4 following the completion of the planned life extension outage which began in third quarter 2012 and was completed in April 2013.

Equity income from Bruce B increased by $18 million for the three months ended June 30, 2014 and $38 million for the six months ended June 30, 2014 compared to the same periods in 2013. These increases were mainly due to higher volumes and lower operating costs resulting from fewer planned and unplanned outage days.

Under the contract with the OPA, all of the output from Bruce A Units 1 to 4 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, 2014 - March 31, 2015                                        $71.70
April 1, 2013 - March 31, 2014                                        $70.99
April 1, 2012 - March 31, 2013                                        $68.23

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bruce B floor price                                                  per MWh
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
April 1, 2014 - March 31, 2015                                        $52.86
April 1, 2013 - March 31, 2014                                        $52.34
April 1, 2012 - March 31, 2013                                        $51.62

Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the average spot price in a month exceeds the floor price. While the first quarter 2014 average spot price exceeded the floor price, spot prices have since fallen below the floor price and are expected to remain there for the remainder of 2014. As a result, Bruce B is expected to recognize annual revenues at the floor price and amounts equivalent to that received above it in first quarter 2014 are expected to be repaid to the OPA.

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 2014 is expected to be in the low 80s for Bruce A and high 80s for Bruce B. Planned maintenance on one of the Bruce B units is scheduled to occur in fourth quarter 2014.

U.S. POWER


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                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of US$)            2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Revenue                                                                     
Power(1)                                  311       316     1,054       779 
Capacity                                   96        77       166       124 
----------------------------------------------------------------------------
                                          407       393     1,220       903 
Commodity purchases resold               (218)     (197)     (767)     (503)
Plant operating costs and other(2)       (109)     (134)     (289)     (270)
Exclude risk management activities          8        18        10        17 
----------------------------------------------------------------------------
Comparable EBITDA                          88        80       174       147 
Comparable depreciation and                                                 
 amortization                             (27)      (23)      (54)      (51)
----------------------------------------------------------------------------
Comparable EBIT                            61        57       120        96 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  The realized and unrealized 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 the cost of fuel consumed in generation.                        

Sales volumes and plant availability


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                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited)                              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Physical sales volumes (GWh)                                                
Supply                                                                      
  Generation                            2,006     1,761     3,244     2,812 
  Purchased                             1,865     1,878     4,694     4,357 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                        3,871     3,639     7,938     7,169 
                                                                            
Plant availability(1)                      89%       91%       87%       85%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  The percentage of time the plant was available to generate power,        
   regardless of whether it was running.                                    

U.S. Power's comparable EBITDA increased US$8 million for the three months ended June 30, 2014 compared to the same period in 2013. The increase was the net effect of:


--  higher realized capacity prices in New York 
--  higher generation at our hydro facilities 
--  higher prices and related costs on volumes purchased to fulfill power
    sales commitments to wholesale, commercial and industrial customers. 

U.S. Power's comparable EBITDA increased US$27 million for the six months ended June 30, 2014 compared to the same period in 2013. The increase was the net effect of:


--  higher realized capacity prices in New York 
--  higher realized power prices and higher generation in New England 
--  higher realized power prices and higher generation in New York offset by
    higher plant operating costs due to higher fuel prices 
--  higher prices and related costs on volumes purchased to fulfill power
    sales commitments to wholesale, commercial and industrial customers. 

Wholesale electricity prices in New York and New England were higher for the six months ended June 30, 2014 compared to the same period in 2013 primarily due to significantly higher spot power prices in first quarter 2014. Colder winter temperatures and gas transmission constraints resulted in higher natural gas prices in the predominantly gas-fired New England and New York power markets in first quarter 2014 compared to the same period in 2013.

Average spot power prices for the three months ended June 30, 2014 in New England of $40/MWh were unchanged and in New York City spot power prices decreased 12 per cent to an average of $38/MWh compared to the same period in 2013. Average spot power prices for the six months ended June 30, 2014 in New England increased 45 per cent to $93/MWh and in New York City spot power prices increased 44 per cent to an average of $82/MWh compared to the same period in 2013.

Spot capacity prices in New York City were on average 26 and 46 per cent higher for the three and six months ended June 30, 2014 compared to the same periods in 2013. This, and the impact of hedging activities, resulted in higher realized capacity prices in New York.

Physical sales volumes for the three and six months ended June 30, 2014 were higher than the same period in 2013. For the three months ended June 30, 2014, generation volumes at our Ravenswood and hydro facilities were higher than the same period in 2013. For the six months ended June 30, 2014, generation at our Ravenswood facility and purchased volumes sold to wholesale, commercial and industrial customers in our PJM markets were also higher than in the same period in 2013.

As at June 30, 2014, approximately 3,500 GWh or 60 per cent of U.S. Power's planned generation is contracted for the remainder of 2014, and 3,100 GWh or 35 per cent for 2015. 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 AND OTHER

Comparable EBITDA decreased $7 million for the three months ended June 30, 2014 and increased $2 million for six months ended June 30, 2014 compared to the same periods in 2013. The decrease in the three months ended June 30, 2014 was primarily due to decreased proprietary and third party storage revenues as a result of lower realized natural gas storage spreads. The increase in the six months ended June 30, 2014 was primarily due to increased proprietary storage revenues recognized in the first quarter as a result of higher realized natural gas storage spreads, partially offset by decreased third party storage revenues. The seasonal nature of natural gas storage generally results in higher revenues in the winter season.

Recent developments

NATURAL GAS PIPELINES

Canadian Regulated Pipelines

NGTL System

We continued to expand the NGTL System in second quarter 2014. Of the $400 million of facilities that received NEB approval, approximately $250 million have been placed in service as of June 30, 2014. In addition, we have approximately $1.9 billion in projects that have been applied for but are not yet approved by the NEB, mainly comprised of the $1.7 billion North Montney project further described below.

In March 2014, we received an NEB Safety Order in response to recent pipeline releases on the NGTL System. The order required us to reduce the maximum operating pressure on three per cent of NGTL's pipeline segments. On March 28, 2014, we filed a request for a review and variance of the Order that would minimize gas disruptions while still maintaining a high level of safety. In April 2014, the NEB granted the review and variance request with certain conditions. We are accelerating components of our integrity management program to address the NEB order.

Merrick Mainline Pipeline Project

On June 4, 2014, we announced the signing of agreements for approximately 1.9 Bcf/d of firm natural gas transportation services to underpin the development of a major extension of our NGTL System.

The proposed Merrick Mainline Pipeline Project will transport natural gas sourced through the NGTL System to the inlet of a proposed Pacific Trail Pipeline that will terminate at the Kitimat LNG Terminal at Bish Cove near Kitimat, B.C. The proposed project will be an extension from the existing Groundbirch Mainline section of the NGTL System beginning near Dawson Creek, B.C. to its end point near the community of Summit Lake, B.C. The $1.9 billion project consists of approximately 260 km (161 miles) of 48-inch diameter pipe.

We anticipate filing an application for approvals to build and operate the system with the NEB in fourth quarter 2014. Subject to the necessary approvals, including a positive final investment decision for the Kitimat LNG project, we expect the Merrick Mainline to be in service in first quarter 2020.

North Montney Mainline Project

The NEB issued a Hearing Order in February 2014 for the $1.7 billion North Montney Pipeline Project, which is an extension and expansion of the NGTL System to receive and transport natural gas from the North Montney area of B.C. The proposed project consists of approximately 300 km (186 miles) of pipeline and is expected to be placed in service in two sections, Aitken Creek in second quarter 2016 and Kahta in second quarter 2017.

On June 17, 2014, the NEB revised the procedural schedule which has resulted in the oral portion of the hearing being rescheduled to mid-October 2014 for the Calgary phase, and mid-November for the Fort St. John phase. We now anticipate an NEB decision on the application in first quarter 2015.

Canadian Mainline

LDC Settlement

In March 2014, the NEB responded to the LDC Settlement application we filed in December 2013. The NEB did not approve the application as a settlement but allowed us the option to continue with the application as a contested tolls application, amend the application or terminate the processing of the application. We amended the application with additional information. On May 9, 2014, the NEB released a Hearing Order that sets out a hearing process and schedule for the 2015 - 2030 Mainline Tolls application that incorporates the LDC Settlement, with the oral portion set to begin September 9, 2014.

Eastern Mainline Project

On May 8, 2014, we filed a project description with the NEB for the Eastern Mainline Project. The proposed project will add new facilities to our existing Canadian Mainline natural gas transmission system in southeastern Ontario as a result of the proposed transfer of a portion of the Canadian Mainline capacity to crude oil from natural gas service as part of our Energy East Pipeline and an open season that closed in January 2014. The proposed scope of the project will add 0.6 Bcf/day of new capacity and will ensure appropriate levels of capacity are available to meet the requirements of existing shippers as well as new firm service commitments contracted services in the Eastern Triangle segment of the Canadian Mainline. Subject to regulatory approvals, the project is expected to be in service in second quarter 2017.

U.S. Pipelines

ANR Pipeline

We have secured almost 2.0 Bcf/d of firm natural gas transportation commitments on the ANR Pipeline's Southeast Main Line at maximum rates for an average term of 23 years. Approximately 1.25 Bcf/d of new contracts will commence in late 2014 including volume commitments from the ANR Lebanon Lateral Reversal project, with the remaining volume commencing in 2015. These contracts will enable growing Utica and Marcellus shale gas supply to move to both northern delivery points and southbound to the U.S. Gulf Coast. As a result, approximately US$100 million of capital investment will be required to bring this additional supply to market. We are also assessing further demand which could result in incremental opportunities to enhance and expand the ANR Pipeline system.

Mexican Pipelines

Tamazunchale Pipeline Extension Project

Construction of the US$600 million extension is currently expected to be completed by the end of September 2014 with delays attributed to archeological findings along the pipeline route. Under the terms of the Transportation Service Agreement, these delays are recognized as a force majeure with provisions allowing for collection of revenue as per the original service commencement of March 9, 2014.

LNG Pipeline Projects

Coastal GasLink

In first quarter 2014, we filed the Environmental Assessment Certificate application with the B.C. Environmental Assessment Office (EAO) and the B.C. Oil and Gas Commission application. We are currently updating field work along the pipeline route to support the regulatory applications and refine the capital cost estimates.

Prince Rupert Gas Transmission

The Environmental Assessment application submitted to the EAO in April 2014 was deemed complete by the EAO. The EAO initiated a 180-day review period which included a 45-day public comment period that was completed on July 10, 2014. A facilities application was also filed with the B.C. Oil and Gas Commission in April 2014. Regulatory approval for the pipeline is expected in fourth quarter 2014 and a final investment decision from Pacific Northwest LNG is expected to follow at the end of 2014.

Alaska

In April 2014, the State of Alaska passed new legislation that will transition from the Alaska Gasline Inducement Act (AGIA) and enable a new commercial arrangement to be established with us, the three major Alaska North Slope producers, and the Alaska Gasline Development Corp. It was also agreed that an LNG export project, rather than a pipeline to Alberta, is currently the best opportunity to commercialize Alaska North Slope gas resources in current market conditions.

On June 9, 2014, we executed an agreement with the State of Alaska to abandon the AGIA license and executed a Precedent Agreement where we will act as the transporter of the State's portion of natural gas under a long-term shipping contract in the Alaska LNG Project. On June 30, 2014, the Alaska LNG Project entered the pre-front end engineering and design (pre-FEED) phase following the execution of a Joint Venture Agreement among ourselves, the three major Alaska North Slope producers and Alaska Gasline Development Corp. The pre-FEED work is anticipated to take two years to complete with our share of the cost to be approximately US$100 million. The Precedent Agreement provides us with full recovery of development costs in the event the project does not proceed.

LIQUIDS PIPELINES

Keystone Pipeline System

We finished constructing the 780 km (485 mile) 36-inch pipeline of the Gulf Coast extension of the Keystone Pipeline System, from Cushing, Oklahoma to the U.S. Gulf Coast. Crude oil transportation service on the project began January 22, 2014.

Keystone XL

On January 31, 2014, the DOS released its Final Supplemental Environmental Impact Statement (FSEIS) for the Keystone XL project. The results included in the report were consistent with previous environmental reviews of Keystone XL. The FSEIS concluded Keystone XL is "unlikely to significantly impact the rate of extraction in the oil sands" and that all other alternatives to Keystone XL are less efficient methods of transporting crude oil, and would result in significantly more greenhouse gas emissions, oil spills and risks to public safety. The report initiated the National Interest Determination period that was to last up to 90 days which involves consultation with other governmental agencies and provides an opportunity for public comment. The 30 day public comment period has concluded. On April 18, 2014, the DOS announced that the National Interest Determination period has been extended indefinitely to allow them to consider the potential impact of the case discussed below on the Nebraska portion of the pipeline route.

In February 2014, a Nebraska district court ruled that the state Public Service Commission, rather than Governor Dave Heineman, has the authority to approve an alternative route through Nebraska for the Keystone XL project. Nebraska's Attorney General has filed an appeal and the Nebraska Supreme Court is expected to hear the appeal in September 2014. As of June 30, 2014, we have invested US$2.4 billion in the Keystone XL project.

Cushing Marketlink

Construction continues on the Cushing Marketlink receipt facilities at Cushing, Oklahoma. Cushing Marketlink will facilitate the transportation of crude oil from the market hub at Cushing to the U.S. Gulf Coast refining market on facilities that form part of the Keystone Pipeline System. Construction is expected to be completed in third quarter 2014.

Energy East Pipeline

In March 2014, we filed the project description with the NEB. This is the first formal step in the regulatory process to receive the necessary approvals to build and operate the pipeline. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets.

Subject to regulatory approvals, the pipeline is anticipated to commence deliveries to Quebec in 2018, with service to New Brunswick to follow in late 2018. We continue to participate in Aboriginal and stakeholder engagement and associated field work as part of our initial design and planning. We intend to file the necessary regulatory applications in third quarter 2014 for approvals to construct and operate the pipeline project and terminal facilities.

Heartland Pipeline and TC Terminals

The Heartland Pipeline and TC Terminals will include a 200 km (125 miles) crude oil pipeline connecting the Edmonton/Heartland, Alberta market region to facilities in Hardisty, Alberta, and a terminal facility in the Heartland industrial area north of Edmonton, Alberta. In February 2014, the application for the terminal facility was approved by the Alberta Energy Regulator.

Northern Courier Pipeline

In October 2013, Suncor Energy announced that the Fort Hills Energy LP is proceeding with the Fort Hills oil sands mining project and expects to begin producing crude oil in 2017. Our Northern Courier Pipeline project will transport bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal located north of Fort McMurray, Alberta.

On July 18, 2014, the Alberta Energy Regulator issued a permit approving our application to construct and operate the Northern Courier Pipeline. We currently expect construction to begin in third quarter 2014 and to be in service in 2017.

ENERGY

Cancarb Limited and Cancarb Waste Heat Facility

The sale of Cancarb Limited and its related power generation facility closed on April 15, 2014 for gross proceeds of $190 million. We recognized a gain of $99 million, net of tax, in second quarter 2014.

Natural Gas Storage

Effective April 30, 2014, we terminated a 38 Bcf long-term natural gas storage contract in Alberta with Niska Gas Storage. The contract contained provisions allowing for possible early termination. As a result, we recorded an after tax charge of $31 million in second quarter 2014. We have re-contracted for new natural gas storage services in Alberta with Niska Gas Storage starting May 1, 2014 for a six-year period and a reduced average volume.

Ontario Solar

We expect the acquisition of four additional Ontario solar generation facilities to close in late 2014, with the acquisition of the ninth and final facility now expected to close in mid-2015, subject to satisfactory completion of the related construction activities, regulatory approvals, and purchase agreement conditions for each facility. All power produced by the solar facilities is currently or will be sold under 20-year PPAs with the OPA.

Becancour

In May 2014, we received final approval from the Regie de l'energie for the December 2013 amendment to the original suspension agreement with Hydro-Quebec. In addition, Hydro-Quebec exercised its option in the amendment to extend the suspension past 2017, and requested further suspension of generation to the end of 2018 which was also approved by the Regie de l'energie.

Other income statement items

The following are reconciliations and related analyses of our non-GAAP measures to the equivalent GAAP measures.


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                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Comparable interest on long-term                                            
 debt (including interest on junior                                         
 subordinated notes)                                                        
Canadian-dollar denominated              (113)     (123)     (227)     (245)
U.S. dollar-denominated (US$)            (216)     (185)     (423)     (373)
Foreign exchange impact                   (19)       (5)      (41)       (6)
----------------------------------------------------------------------------
                                         (348)     (313)     (691)     (624)
Other interest and amortization                                             
 expense                                  (12)        1       (22)        - 
Capitalized interest                       63        60       142       115 
----------------------------------------------------------------------------
Comparable interest expense              (297)     (252)     (571)     (509)
----------------------------------------------------------------------------
Specific item:                                                              
  NEB decision - 2012                       -         -         -        (1)
----------------------------------------------------------------------------
Interest expense                         (297)     (252)     (571)     (510)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Comparable interest expense increased by $45 million and $62 million for the three and six months ended June 30, 2014 compared to the same periods in 2013 because of the following:


--  higher interest expense due to debt issues of: 
    --  US$1.25 billion in February 2014 
    --  US$1.25 billion in October 2013 
    --  US$500 million in July 2013 
    --  $750 million in July 2013 
    --  US$500 million in July 2013 by TC PipeLines, LP 
--  higher foreign exchange on interest expense related to U.S. denominated
    debt, partially offset by Canadian and U.S. dollar-denominated debt
    maturities. 

These increases were partially offset by higher capitalized interest primarily for Keystone XL, Mexican, and other liquids and LNG pipeline projects partially offset by the completion of the Gulf Coast extension of the Keystone Pipeline System in first quarter 2014.


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                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Comparable interest income and other       29        (2)       23        16 
Specific items (pre-tax):                                                   
  NEB decision - 2012                       -         -         -         1 
  Risk management activities               25        (9)       23       (15)
----------------------------------------------------------------------------
Interest income and other                  54       (11)       46         2 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Comparable interest income and other increased by $31 million for the three months ended June 30, 2014 compared to the same period in 2013 reflecting lower realized losses in 2014 compared to 2013 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income, the impact of a fluctuating U.S. dollar on the translation of foreign currency denominated working capital balances and AFUDC related to our rate-regulated projects, including the Energy East project.

Comparable interest income and other increased $7 million for the six months ended June 30, 2014 compared to the same period in 2013 reflecting increased AFUDC related to our rate-regulated projects, including the Energy East project, offset by higher realized losses in 2014 compared to 2013 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income.


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----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Comparable income tax expense            (162)     (133)     (386)     (292)
Specific items:                                                             
  Cancarb gain on sale                     (9)        -        (9)        - 
  Niska contract termination               10         -        10         - 
  NEB decision - 2012                       -         -         -        42 
  Part VI.I income tax adjustment           -        25         -        25 
  Risk management activities               (4)       10        (1)       12 
----------------------------------------------------------------------------
Income tax expense                       (165)      (98)     (386)     (213)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Comparable income tax expense increased by $29 million and $94 million for the three and six months ended June 30, 2014 compared to the same periods in 2013. The increase was mainly the result of higher pre-tax earnings in 2014 compared to 2013, changes in the proportion of income earned between Canadian and foreign jurisdictions as well as higher flow-through taxes in 2014 on Canadian regulated pipelines.


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----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Net income attributable to non-                                             
 controlling interests                    (31)      (23)      (85)      (54)
Preferred share dividends                 (25)      (20)      (48)      (35)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income attributable to non-controlling interests increased by $8 million and $31 million for the three and six months ended June 30, 2014 compared to the same periods in 2013 primarily due to the sale of a 45 per cent interest in each of GTN and Bison to TC PipeLines, LP in July 2013.

Preferred share dividends increased by $5 million and $13 million for the three and six months ended June 30, 2014 compared to the same periods in 2013 following the issuances of Series 7 preferred shares in March 2013 and Series 9 preferred shares in January 2014.

Financial condition

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

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

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

CASH PROVIDED BY OPERATING ACTIVITIES


--------------------------------------------------------------------------
--------------------------------------------------------------------------
                                    three months ended   six months ended 
                                         June 30             June 30      
                                    ------------------ -------------------
                                    ------------------ -------------------
(unaudited - millions of $)              2014     2013      2014     2013 
--------------------------------------------------------------------------
--------------------------------------------------------------------------
                                                                          
Funds generated from operations(1)        917      955     2,019    1,871 
Decrease/(increase) in operating                                          
 working capital                          202     (114)       79     (324)
--------------------------------------------------------------------------
Net cash provided by operations         1,119      841     2,098    1,547 
--------------------------------------------------------------------------
--------------------------------------------------------------------------
1  See the non-GAAP measures section in this MD&A for further discussion of 
   funds generated from operations.                                         

Net cash provided by operations increased by $278 million and $551 million for the three and six months ended June 30, 2014 compared to the same periods in 2013 primarily due to changes in our operating working capital.

At June 30, 2014, our current assets were $3.0 billion and current liabilities were $5.6 billion, leaving us with a working capital deficit of $2.6 billion compared to $2.2 billion at December 31, 2013. This working capital deficiency is considered to be in the normal course of business and is managed through our ability to generate cash flow from operations and our ongoing access to the capital markets.

CASH (USED IN)/PROVIDED BY INVESTING ACTIVITIES


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                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Capital expenditures                     (967)   (1,109)   (1,745)   (2,038)
Equity investments                        (40)      (39)     (129)      (71)
Acquisitions                                -       (55)        -       (55)
Proceeds from sale of assets, net of                                        
 transaction costs                        187         -       187         - 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Our capital expenditures in 2014 were primarily related to the construction of the Mexican pipelines, expansion of the NGTL System, and construction of the Houston Lateral and Tank Terminals.

In April 2014, we closed the sale of Cancarb Limited for $187 million, net of transaction costs.

CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                          June 30              June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $)              2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Long-term debt issued, net of issue                                         
 costs                                     16        10     1,380       744 
Long-term debt repaid                    (205)     (695)     (982)     (709)
Notes payable issued/(repaid), net        225     1,388      (522)      559 
Dividends and distributions paid         (412)     (386)     (802)     (736)
Partnership units of subsidiary                                             
 issued, net of issue costs                 -       384         -       384 
Preferred shares issued, net of                                             
 issue costs                                -        (1)      440       585 
Preferred shares of subsidiary                                              
 redeemed                                   -         -      (200)        - 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LONG-TERM DEBT ISSUED                                                       
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount                                                                      
(unaudited -                                         Interest               
 millions of $)  Type             Maturity date          rate    Date issued
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
US$1,250         Senior           March 1, 2034        4.625%  February 2014
                  unsecured                                                 
                  notes                                                     
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LONG-TERM DEBT RETIRED                                                      
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount                                                                      
(unaudited - millions                             Retirement                
 of $)                 Type                             date   Interest rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
$450                   Medium term notes        January 2014           5.65%
$300                   Medium term notes       February 2014           5.05%
$125                   Debenture                   June 2014          11.10%
$53                    Debenture                   June 2014          11.20%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

PREFERRED SHARE ISSUANCE AND REDEMPTION

In January, 2014, we completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $450 million. Investors are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly. The preferred shares are redeemable by us on or after October 30, 2019 and on October 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends. Investors will have the right to convert their shares into Series 10 cumulative redeemable first preferred shares on October 30, 2019 and on October 30 of every fifth year thereafter. The holders of Series 10 preferred 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 and 2.35 per cent.

In March, 2014, we redeemed all four million Series Y preferred shares of TCPL at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends. The total face value of the outstanding Series Y Shares was $200 million and carried an aggregate of $11 million in annualized dividends.

The net proceeds of the above debt and equity offerings were used for general corporate purposes and to reduce short-term indebtedness.

DIVIDENDS

On July 31, 2014, we declared quarterly dividends as follows:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarterly dividend on our common shares                                     
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
$0.48 per share                                                             
Payable on October 31, 2014 to shareholders of record at the close of       
 business on September 30, 2014                                             
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarterly dividends on our preferred shares                                 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Series 1       $0.2875                                                      
Series 3       $0.25                                                        
Payable on September 30, 2014 to shareholders of record at the close of     
 business on September 2, 2014                                              
Series 5       $0.275                                                       
Series 7       $0.25                                                        
Series 9       $0.265625                                                    
Payable on October 30, 2014 to shareholders of record at the close of       
 business on September 30, 2014                                             
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SHARE INFORMATION                                                           
----------------------------------------------------------------------------
----------------------------------------------------------------------------
July 28, 2014                                                               
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Common shares               Issued and outstanding                          
                                       708 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
Series 9                                18 million      18 million Series 10
                                                            preferred shares
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Options to buy common                  Outstanding               Exercisable
 shares                                                                     
                                         9 million                 5 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, 2014, we had $6.5 billion in unsecured credit facilities, including:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                Unused                         Description                  
Amount          capacity        Subsidiary     and Use        Matures       
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
$3.0 billion    $3.0 billion    TCPL           Committed,     December 2018 
                                               syndicated,                  
                                               revolving,                   
                                               extendible                   
                                               credit                       
                                               facility that                
                                               supports                     
                                               TCPL's                       
                                               Canadian                     
                                               commercial                   
                                               paper program                
----------------------------------------------------------------------------
US$1.0 billion  US$1.0 billion  TCPL USA       Committed,     November 2014 
                                               syndicated,                  
                                               revolving,                   
                                               extendible                   
                                               credit                       
                                               facility that                
                                               is used for                  
                                               TCPL USA                     
                                               general                      
                                               corporate                    
                                               purposes                     
----------------------------------------------------------------------------
US$1.0 billion  US$1.0 billion  TransCanada    Committed,     November 2014 
                                American       syndicated,                  
                                Investments    revolving,                   
                                Ltd. (TAIL)    extendible                   
                                               credit                       
                                               facility that                
                                               supports the                 
                                               TAIL U.S.                    
                                               commercial                   
                                               paper program                
----------------------------------------------------------------------------
$1.3 billion    $0.3 billion    TCPL,          Demand lines   Demand        
                                TCPL USA       for issuing                  
                                               letters of                   
                                               credit and as                
                                               a source of                  
                                               additional                   
                                               liquidity. At                
                                               June 30, 2014,               
                                               we had $1.0                  
                                               billion                      
                                               outstanding in               
                                               letters of                   
                                               credit under                 
                                               these lines                  
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See Financial risks and financial instruments for more information about    
liquidity, market and other risks.                                          

CONTRACTUAL OBLIGATIONS

Our capital commitments have decreased by approximately $1 billion since December 31, 2013 primarily due to the completion or advancement of capital projects. Our other purchase obligations have decreased by approximately $400 million since December 31, 2013 primarily due to re-contracting for natural gas storage services in Alberta for a shorter period and a reduced average volume. There were no other material changes to our contractual obligations in second quarter 2014 or to payments due in the next five years or after. See the MD&A in our 2013 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.

See our 2013 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2013.

LIQUIDITY RISK

We manage our liquidity risk by continuously forecasting our cash requirements for a rolling twelve 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 
--  the fair value of derivative assets 
--  notes receivable. 

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At June 30, 2014 we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration of $211 million with one counterparty at June 30, 2014 (December 31, 2013 - $240 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 AND INTEREST RATE RISK

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

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

Average exchange rate - U.S. to Canadian dollars


----------------------------------------------------------------------------
----------------------------------------------------------------------------
second quarter 2014                                                    1.09 
second quarter 2013                                                    1.03 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The impact of changes in the value of the U.S. dollar on our U.S. dollar-denominated operations is significantly offset by other U.S. dollar-denominated items, as set out in the table below.

Significant U.S. dollar-denominated amounts


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of US$)            2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
U.S. and International Natural Gas                                          
 Pipelines comparable EBIT                140       101       351       301 
U.S. Liquids Pipelines comparable                                           
 EBIT                                     133        95       262       189 
U.S. Power comparable EBIT                 61        57       120        96 
Interest expense on U.S. dollar-                                            
 denominated long-term debt              (216)     (185)     (423)     (373)
Capitalized interest on U.S. capital                                        
 expenditures                              43        49        95        93 
U.S. non-controlling interests and                                          
 other                                    (53)      (39)     (132)      (87)
----------------------------------------------------------------------------
                                          108        78       273       219 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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, foreign exchange forward 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, 2014      December 31, 2013 
                                   -------------------- --------------------
                                   -------------------- --------------------
                                               Notional             Notional
                                                     or                   or
                                        Fair  principal      Fair  principal
(unaudited - millions of $)         value(1)     amount  value(1)     amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Asset/(liability)                                                           
U.S. dollar cross-currency swaps                                            
(maturing 2014 to 2019)(2)              (186)  US 3,250      (201)  US 3,800
U.S. dollar foreign exchange                                                
 forward contracts                                                          
(maturing 2014)                          (14)    US 300       (11)    US 850
----------------------------------------------------------------------------
                                        (200)  US 3,550      (212)  US 4,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Fair values equal carrying values.                                       
2  Net income in the three and six months ended June 30, 2014 included net  
   realized gains of $5 million and $11 million, respectively, (2013 - gains
   of $7 million and $14 million, respectively) related to the interest     
   component of cross-currency swaps.                                       

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of $)               June 30, 2014   December 31, 2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Carrying value                        15,600 (US 14,600)  14,200 (US 13,400)
Fair value                            18,200 (US 17,100)  16,000 (US 15,000)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The balance sheet classification of the fair value of derivatives used to hedge our net investment in foreign operations is as follows:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of $)               June 30, 2014   December 31, 2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Other current assets                                  5                   5 
Intangible and other assets                           1                   - 
Accounts payable and other                          (57)                (50)
Other long-term liabilities                        (149)               (167)
----------------------------------------------------------------------------
                                                   (200)               (212)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

FINANCIAL INSTRUMENTS

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

Non-derivative financial instruments

Fair value of non-derivative financial instruments

The fair value of our notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt has been estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data providers. The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments.

Certain non-derivative financial instruments including cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that equal their fair value due to the nature of the item or the short time to maturity.

Derivative instruments

We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify. The effective portion of the change in the fair value of hedging derivatives for cash flow hedges and hedges of our net investment in foreign operations are recorded in OCI in the period of change. Any ineffective portion is recognized in net income in the same financial category as the underlying transaction. The change in the fair value of derivative instruments that have been designated as fair value hedges are recorded in net income in interest income and other and interest expense.

Derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk (held for trading). Changes in the fair value of held for trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held for trading derivative instruments can fluctuate significantly from period to period.

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

Fair value of derivative instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses current market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives have been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

Balance sheet presentation of derivative instruments

The balance sheet classification of the fair value of the derivative instruments is as follows:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of $)               June 30, 2014   December 31, 2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Other current assets                                354                 395 
Intangible and other assets                         127                 112 
Accounts payable and other                         (404)               (357)
Other long-term liabilities                        (236)               (255)
----------------------------------------------------------------------------
                                                   (159)               (105)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The effect of derivative instruments on the consolidated statement of income

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $, pre-tax)     2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Derivative instruments held for                                             
 trading(1)                                                                 
Amount of unrealized gains/(losses)                                         
 in the period                                                              
  Power                                     6         5        15        (3)
  Natural gas                             (14)      (21)      (21)      (12)
  Foreign exchange                         25       (10)       23       (16)
Amount of realized (losses)/gains in                                        
 the period                                                                 
  Power                                    (3)      (29)      (31)      (36)
  Natural gas                              (4)       (5)       46        (7)
  Foreign exchange                         (1)       (6)      (18)       (7)
Derivative instruments in hedging                                           
 relationships(2,3)                                                         
Amount of realized gains/(losses) in                                        
 the period                                                                 
  Power                                    (4)      (84)      188       (11)
  Natural gas                               -        (1)        -        (1)
  Interest                                  1         2         2         4 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  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 energy revenues. Realized and unrealized gains and losses on      
   interest rate and foreign exchange held for trading derivative           
   instruments are included net in interest expense and interest income and 
   other, respectively.                                                     
2  At June 30, 2014, all hedging relationships were designated as cash flow 
   hedges except for interest rate derivative financial instruments         
   designated as fair value hedges with a fair value of $5 million (2013 -  
   $7 million) and a notional amount of US$300 million (2013 - US$200       
   million). For the three and six months ended June 30, 2014, net realized 
   gains on fair value hedges were $2 million and $3 million, respectively  
   (2013 - $2 million and $4 million, respectively) and were included in    
   interest expense. For the three and six months ended June 30, 2014 and   
   2013, we did not record any amounts in net income related to             
   ineffectiveness for fair value hedges.                                   
3  The effective portion of the change in fair value of derivative          
   instruments in hedging relationships is initially recognized in OCI and  
   reclassified to energy revenues, interest expense and interest income and
   other, as appropriate, as the original hedged item settles. For the three
   and six months ended June 30, 2014 and 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.  

Derivatives in cash flow hedging relationships

The components of the Condensed consolidated statement of OCI related to derivatives in cash flow hedging relationships is as follows:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $, pre-tax)     2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Change in fair value of derivative                                          
 instruments recognized in OCI                                              
 (effective portion)                                                        
  Power                                    (7)      (70)       34       (34)
  Natural gas                              (1)        -        (1)        - 
  Foreign exchange                          -         2        10         4 
  Interest                                 (1)        -        (1)        - 
----------------------------------------------------------------------------
                                           (9)      (68)       42       (30)
----------------------------------------------------------------------------
Reclassification of (losses)/gains                                          
 on derivative instruments from AOCI                                        
 to net income (effective                                                   
 portion)(1)                                                                
  Power(2)                                 (1)       12      (109)        1 
  Natural gas                               2         2         2         2 
  Interest                                  3         4         8         8 
----------------------------------------------------------------------------
                                            4        18       (99)       11 
----------------------------------------------------------------------------
Gains/(losses) on derivative                                                
 instruments recognized in earnings                                         
 (ineffective portion)                                                      
  Power                                     3        (2)      (10)       (7)
----------------------------------------------------------------------------
                                            3        (2)      (10)       (7)
----------------------------------------------------------------------------
1  No amounts have been excluded from the assessment of hedge effectiveness.
   Amounts in parentheses indicate losses recorded to OCI.                  
2  Reported within Energy revenues on the condensed consolidated statement  
   of income.                                                               

Credit risk related contingent features of derivative instruments

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, 2014, the aggregate fair value of all derivative contracts with credit risk related contingent features that were in a net liability position was $17 million (December 31, 2013 - $16 million), with collateral provided in the normal course of business of nil (December 31, 2013 - nil). If the credit risk related contingent features in these agreements had been triggered on June 30, 2014, we would have been required to provide collateral of $17 million (December 31, 2013 - $16 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.

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, 2014, 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 2014 that had or are likely to have a material impact on our internal control over financial reporting, other than noted below.

Effective January 1, 2014, management implemented an ERP system. As a result of the ERP system, certain processes supporting our internal control over financial reporting have changed. Management will continue to monitor the effectiveness of these processes going forward.

CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY 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 judgement. We also regularly assess the assets and liabilities themselves. You can find a summary of our critical accounting estimates in our 2013 Annual Report.

Our significant accounting policies have remained unchanged since December 31, 2013 other than described below. You can find a summary of our significant accounting policies in our 2013 Annual Report.

Changes in accounting policies for 2014

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 new guidance was effective January 1, 2014. There was no material impact on our consolidated financial statements as a result of applying this new standard.

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 new guidance was effective prospectively from January 1, 2014 and will be applied for all applicable transactions after that date.

Unrecognized tax benefit

In July 2013, the FASB issued amended guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This new guidance was effective January 1, 2014. There was no material impact on our consolidated financial statements as a result of applying this new standard.

Future accounting changes

Reporting discontinued operations

In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance is effective from January 1, 2015 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.

Revenue from contracts with customers

In May 2014, the FASB issued new guidance on Revenue from Contracts with Customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This new guidance is effective from January 1, 2017 with two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. Early application is not permitted. We are currently evaluating the impact of the adoption of this ASU and have not yet determined the effect on our consolidated financial statements.

Reconciliation of non-GAAP measures


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                          June 30              June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $, except                                          
 per share amounts)                      2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
EBITDA                                  1,279     1,125     2,664     2,344 
Cancarb gain on sale                     (108)        -      (108)        - 
Niska contract termination                 41         -        41         - 
NEB decision - 2012                         -         -         -       (55)
Non-comparable risk management                                              
 activities affecting EBITDA                5        18        16        22 
----------------------------------------------------------------------------
Comparable EBITDA                       1,217     1,143     2,613     2,311 
Comparable depreciation and                                                 
 amortization                            (399)     (356)     (792)     (710)
----------------------------------------------------------------------------
Comparable EBIT                           818       787     1,821     1,601 
----------------------------------------------------------------------------
Other income statement items                                                
Comparable interest expense              (297)     (252)     (571)     (509)
Comparable interest income and other       29        (2)       23        16 
Comparable income tax expense            (162)     (133)     (386)     (292)
Net income attributable to non-                                             
 controlling interests                    (31)      (23)      (85)      (54)
Preferred share dividends                 (25)      (20)      (48)      (35)
----------------------------------------------------------------------------
Comparable earnings                       332       357       754       727 
Specific items (net of tax):                                                
  Cancarb gain on sale                     99         -        99         - 
  Niska contract termination              (31)        -       (31)        - 
  NEB decision - 2012                       -         -         -        84 
  Part VI.I income tax adjustment           -        25         -        25 
  Risk management activities(1)            16       (17)        6       (25)
----------------------------------------------------------------------------
Net income attributable to common                                           
 shares                                   416       365       828       811 
----------------------------------------------------------------------------
                                                                            
Comparable depreciation and                                                 
 amortization                            (399)     (356)     (792)     (710)
Specific item:                                                              
  NEB decision - 2012                       -         -         -       (13)
----------------------------------------------------------------------------
Depreciation and amortization            (399)     (356)     (792)     (723)
----------------------------------------------------------------------------
                                                                            
Comparable interest expense              (297)     (252)     (571)     (509)
Specific item:                                                              
  NEB decision - 2012                       -         -         -        (1)
----------------------------------------------------------------------------
Interest expense                         (297)     (252)     (571)     (510)
----------------------------------------------------------------------------
                                                                            
Comparable interest income and other       29        (2)       23        16 
Specific items:                                                             
  NEB decision - 2012                       -         -         -         1 
  Risk management activities(1)            25        (9)       23       (15)
----------------------------------------------------------------------------
Interest income and other                  54       (11)       46         2 
----------------------------------------------------------------------------
                                                                            
Comparable income tax expense            (162)     (133)     (386)     (292)
Specific items:                                                             
  Cancarb gain on sale                     (9)        -        (9)        - 
  Niska contract termination               10         -        10         - 
  Canadian restructuring proposal -                                         
   2012                                     -         -         -        42 
  Part VI.I income tax adjustment           -        25         -        25 
  NEB decision - 2012                       -         -         -         - 
  Risk management activities(1)            (4)       10        (1)       12 
----------------------------------------------------------------------------
Income tax expense                       (165)      (98)     (386)     (213)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                          June 30              June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of $, except                                          
 per share amounts)                      2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Comparable earnings per common share    $0.47     $0.51     $1.07     $1.03 
Specific items (net of tax):                                                
  Cancarb gain on sale                   0.14         -      0.14         - 
  Niska contract termination            (0.04)        -     (0.04)        - 
  NEB decision - 2012                       -         -         -      0.12 
  Part VI.I income tax adjustment           -      0.04                0.04 
  Risk management activities(1)          0.02     (0.03)        -     (0.04)
----------------------------------------------------------------------------
Net income per common share             $0.59     $0.52     $1.17     $1.15 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1   Risk management activities       three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
    (unaudited - millions of $)          2014      2013      2014      2013 
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
                                                                            
    Canadian Power                         (2)       (4)       (2)       (6)
    U.S. Power                             (9)      (18)      (11)      (17)
    Natural Gas Storage                     6         4        (3)        1 
    Foreign exchange                       25        (9)       23       (15)
    Income tax attributable to risk                                         
     management activities                 (4)       10        (1)       12 
    ------------------------------------------------------------------------
    Total gains/(losses) from risk                                          
     management activities                 16       (17)        6       (25)
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
Comparable EBITDA and EBIT by business segment                              
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended June                                                     
 2014                    Natural                                            
(unaudited - millions        Gas      Liquids                               
 of $)                 Pipelines Pipelines(1)    Energy Corporate     Total 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
EBITDA                       759          249       293       (22)    1,279 
Cancarb gain on sale           -            -      (108)        -      (108)
Niska contract                                                              
 termination                   -            -        41         -        41 
Non-comparable risk                                                         
 management activities                                                      
 affecting EBITDA              -            -         5         -         5 
----------------------------------------------------------------------------
Comparable EBITDA            759          249       231       (22)    1,217 
Comparable depreciation                                                     
 and amortization           (263)         (54)      (77)       (5)     (399)
----------------------------------------------------------------------------
Comparable EBIT              496          195       154       (27)      818 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended June                                                     
 30, 2013                Natural                                            
(unaudited - millions        Gas      Liquids                               
 of $)                 Pipelines Pipelines(1)    Energy Corporate     Total 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
EBITDA                       644          186       312       (17)    1,125 
Non-comparable risk                                                         
 management activities                                                      
 affecting EBITDA              -            -        18         -        18 
----------------------------------------------------------------------------
Comparable EBITDA            644          186       330       (17)    1,143 
Comparable depreciation                                                     
 and amortization           (245)         (37)      (69)       (5)     (356)
----------------------------------------------------------------------------
Comparable EBIT              399          149       261       (22)      787 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
six months ended June                                                       
 30, 2014                Natural                                            
(unaudited - millions        Gas      Liquids                               
 of $)                 Pipelines Pipelines(1)    Energy Corporate     Total 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
EBITDA                     1,607          490       627       (60)    2,664 
Cancarb gain on sale           -            -      (108)        -      (108)
Niska contract                                                              
 termination                   -            -        41         -        41 
Non-comparable risk                                                         
 management activities                                                      
 affecting EBITDA              -            -        16         -        16 
----------------------------------------------------------------------------
Comparable EBITDA          1,607          490       576       (60)    2,613 
Comparable depreciation                                                     
 and amortization           (525)        (103)     (154)      (10)     (792)
----------------------------------------------------------------------------
Comparable EBIT            1,082          387       422       (70)    1,821 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
six months ended June                                                       
 30, 2013                Natural                                            
(unaudited - millions        Gas      Liquids                               
 of $)                 Pipelines Pipelines(1)    Energy Corporate     Total 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
EBITDA                     1,445          365       585       (51)    2,344 
NEB decision - 2012          (55)           -         -         -       (55)
Non-comparable risk                                                         
 management activities                                                      
 affecting EBITDA              -            -        22         -        22 
----------------------------------------------------------------------------
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 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1   Previously Oil Pipelines.                                               

QUARTERLY RESULTS

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                             2014                2013               2012    
                         ------------ ------------------------- ------------
                         ------------ ------------------------- ------------
(unaudited - millions of                                                    
 $, except per share                                                        
 amounts)                Second First Fourth Third Second First Fourth Third
------------------------------------- ------------------------- ------------
------------------------------------- ------------------------- ------------
                                                                            
Revenues                  2,234 2,884  2,332 2,204  2,009 2,252  2,089 2,126
Net income attributable                                                     
 to common shares           416   412    420   481    365   446    306   369
Comparable earnings         332   422    410   447    357   370    318   349
Share statistics                                                            
  Net income per common                                                     
   share - basic and                                                        
   diluted                $0.59 $0.58  $0.59 $0.68  $0.52 $0.63  $0.43 $0.52
  Comparable earnings per                                                   
   share                  $0.47 $0.60  $0.58 $0.63  $0.51 $0.52  $0.45 $0.50
  Dividends declared per                                                    
   common share           $0.48 $0.48  $0.46 $0.46  $0.46 $0.46  $0.44 $0.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT

Quarter-over-quarter revenues and net income sometimes fluctuate. The causes of these fluctuations vary across our business segments.

In Natural Gas Pipelines, quarter-over-quarter revenues and net income from the Canadian regulated pipelines generally remain relatively stable during any fiscal year. Our U.S. natural gas pipelines are generally seasonal in nature with higher earnings in the winter months as a result of increased customer demands. Over the long term, however, results from both our Canadian and U.S. natural gas pipelines fluctuate because of:


--  regulatory decisions 
--  negotiated settlements with shippers 
--  acquisitions and divestitures 
--  developments outside of the normal course of operations 
--  newly constructed assets being placed in service. 

In Liquids 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 
--  regulatory decisions. 

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER

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

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

In second quarter 2014, comparable earnings excluded a $99 million after-tax gain on the sale of Cancarb Limited and a $31 million after-tax loss related to the termination of the Niska Gas Storage contract.

In second quarter 2013, comparable earnings excluded 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.

In first quarter 2013, comparable earnings excluded $84 million of net income in 2013 related to 2012 from the NEB decision (RH-003-2011).

Condensed consolidated statement of income


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of Canadian $,                                        
 except per share amounts)               2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Revenues                                                                    
Natural gas pipelines                   1,154     1,031     2,369     2,188 
Liquids pipelines                         366       278       725       549 
Energy                                    714       700     2,024     1,524 
----------------------------------------------------------------------------
                                        2,234     2,009     5,118     4,261 
Income from Equity Investments             68       153       203       246 
Operating and Other Expenses                                                
Plant operating costs and other           684       648     1,489     1,289 
Commodity purchases resold                328       283     1,034       659 
Property taxes                            119       106       242       215 
Depreciation and amortization             399       356       792       723 
Gain on sale of assets                   (108)        -      (108)        - 
----------------------------------------------------------------------------
                                        1,422     1,393     3,449     2,886 
----------------------------------------------------------------------------
Financial Charges/(Income)                                                  
Interest expense                          297       252       571       510 
Interest income and other                 (54)       11       (46)       (2)
----------------------------------------------------------------------------
                                          243       263       525       508 
----------------------------------------------------------------------------
Income before Income Taxes                637       506     1,347     1,113 
----------------------------------------------------------------------------
Income Tax Expense                                                          
Current                                    23       (36)       82        43 
Deferred                                  142       134       304       170 
----------------------------------------------------------------------------
                                          165        98       386       213 
----------------------------------------------------------------------------
Net Income                                472       408       961       900 
Net income attributable to non-                                             
 controlling interests                     31        23        85        54 
----------------------------------------------------------------------------
Net Income Attributable to                                                  
 Controlling Interests                    441       385       876       846 
Preferred share dividends                  25        20        48        35 
----------------------------------------------------------------------------
Net Income Attributable to Common                                           
 Shares                                   416       365       828       811 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Net Income per Common Share                                                 
Basic and diluted                       $0.59     $0.52     $1.17     $1.15 
----------------------------------------------------------------------------
Dividends Declared per Common Share     $0.48     $0.46     $0.96     $0.92 
----------------------------------------------------------------------------
Weighted Average Number of Common                                           
 Shares (millions)                                                          
Basic                                     708       707       708       706 
Diluted                                   709       708       709       707 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $)     2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Net Income                                472       408       961       900 
----------------------------------------------------------------------------
Other Comprehensive Income, Net of                                          
 Income Taxes                                                               
Foreign currency translation gains                                          
 and losses on net investment in                                            
 foreign operations                      (190)      225        50       336 
Change in fair value of net                                                 
 investment hedges                         79      (135)      (48)     (184)
Change in fair value of cash flow                                           
 hedges                                    (4)      (44)       27       (23)
Reclassification to Net Income of                                           
 gains and losses on cash flow                                              
 hedges                                     2        11       (60)        7 
Reclassification to Net Income of                                           
 actuarial gains and losses and                                             
 prior service costs on pension and                                         
 other post-retirement benefit plans        5         6         9        12 
Other comprehensive income/(losses)                                         
 on equity investments                      2        (2)        2        (3)
----------------------------------------------------------------------------
Other comprehensive (loss)/income                                           
 (Note 8)                                (106)       61       (20)      145 
----------------------------------------------------------------------------
Comprehensive Income                      366       469       941     1,045 
Comprehensive (loss)/income                                                 
 attributable to non-controlling                                            
 interests                                 (8)       60        90       111 
----------------------------------------------------------------------------
Comprehensive Income Attributable to                                        
 Controlling Interests                    374       409       851       934 
Preferred share dividends                  25        20        50        35 
----------------------------------------------------------------------------
Comprehensive Income Attributable to                                        
 Common Shares                            349       389       801       899 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $)     2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Cash Generated from Operations                                              
Net income                                472       408       961       900 
Depreciation and amortization             399       356       792       723 
Deferred income taxes                     142       134       304       170 
Income from equity investments            (68)     (153)     (203)     (246)
Distributed earnings received from                                          
 equity investments                        84       180       254       264 
Employee post-retirement benefits                                           
 funding lower than expense                 2        11        12        26 
Gain on sale of assets                   (108)        -      (108)        - 
Other                                      (6)       19         7        34 
Decrease/(increase) in operating                                            
 working capital                          202      (114)       79      (324)
----------------------------------------------------------------------------
Net cash provided by operations         1,119       841     2,098     1,547 
----------------------------------------------------------------------------
Investing Activities                                                        
Capital expenditures                     (967)   (1,109)   (1,745)   (2,038)
Equity investments                        (40)      (39)     (129)      (71)
Acquisitions                                -       (55)        -       (55)
Proceeds from sale of assets, net of                                        
 transactions costs                       187         -       187         - 
Deferred amounts and other                (94)     (144)     (117)     (164)
----------------------------------------------------------------------------
Net cash used in investing                                                  
 activities                              (914)   (1,347)   (1,804)   (2,328)
----------------------------------------------------------------------------
Financing Activities                                                        
Dividends on common and preferred                                           
 shares                                  (365)     (351)     (710)     (666)
Distributions paid to non-                                                  
 controlling interests                    (47)      (35)      (92)      (70)
Notes payable issued/(repaid), net        225     1,388      (522)      559 
Long-term debt issued, net of issue                                         
 costs                                     16        10     1,380       744 
Repayment of long-term debt              (205)     (695)     (982)     (709)
Common shares issued, net of issue                                          
 costs                                      6        23        16        55 
Partnership units of subsidiary                                             
 issued, net of issue costs                 -       384         -       384 
Preferred shares issued, net of                                             
 issue costs                                -        (1)      440       585 
Preferred shares of subsidiary                                              
 redeemed                                   -         -      (200)        - 
----------------------------------------------------------------------------
Net cash (used in)/provided by                                              
 financing activities                    (370)      723      (670)      882 
----------------------------------------------------------------------------
Effect of Foreign Exchange Rate                                             
 Changes on Cash and Cash                                                   
 Equivalents                              (17)       14        16        22 
----------------------------------------------------------------------------
(Decrease)/increase in Cash and Cash                                        
 Equivalents                             (182)      231      (360)      123 
----------------------------------------------------------------------------
Cash and Cash Equivalents                                                   
Beginning of period                       749       443       927       551 
----------------------------------------------------------------------------
Cash and Cash Equivalents                                                   
End of period                             567       674       567       674 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the condensed consolidated financial statements.  
                    Condensed consolidated balance sheet                    
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                    June 30,   December 31, 
(unaudited - millions of Canadian $)                    2014           2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
ASSETS                                                                      
Current Assets                                                              
Cash and cash equivalents                                567            927 
Accounts receivable                                    1,124          1,122 
Inventories                                              252            251 
Other                                                  1,050            847 
----------------------------------------------------------------------------
                                                       2,993          3,147 
Plant, Property and Equipment, net of                                       
 accumulated depreciation of $18,551 and                                    
 $17,851, respectively                                38,456         37,606 
Equity Investments                                     5,719          5,759 
Regulatory Assets                                      1,610          1,735 
Goodwill                                               3,712          3,696 
Intangible and Other Assets                            2,220          1,955 
----------------------------------------------------------------------------
                                                      54,710         53,898 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES                                                                 
Current Liabilities                                                         
Notes payable                                          1,343          1,842 
Accounts payable and other                             2,353          2,155 
Accrued interest                                         383            388 
Current portion of long-term debt                      1,518            973 
----------------------------------------------------------------------------
                                                       5,597          5,358 
Regulatory Liabilities                                   233            229 
Other Long-Term Liabilities                              632            656 
Deferred Income Tax Liabilities                        4,890          4,564 
Long-Term Debt                                        21,774         21,892 
Junior Subordinated Notes                              1,067          1,063 
----------------------------------------------------------------------------
                                                      34,193         33,762 
EQUITY                                                                      
Common shares, no par value                           12,166         12,149 
  Issued and outstanding: June 30, 2014 -                                   
                          708 million shares                                
                          December 31, 2013 -                               
                          707 million shares                                
Preferred shares                                       2,255          1,813 
Additional paid-in capital                               398            401 
Retained earnings                                      5,244          5,096 
Accumulated other comprehensive loss (Note 8)           (959)          (934)
----------------------------------------------------------------------------
Controlling Interests                                 19,104         18,525 
Non-controlling interests                              1,413          1,611 
----------------------------------------------------------------------------
                                                      20,517         20,136 
----------------------------------------------------------------------------
                                                      54,710         53,898 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contingencies and Guarantees (Note 11)                                      
                                                                            
See accompanying notes to the condensed consolidated financial statements.  
                 Condensed consolidated statement of equity                 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                 six months ended June 30   
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of Canadian $)                    2014           2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Common Shares                                                               
Balance at beginning of period                        12,149         12,069 
Shares issued on exercise of stock options                17             62 
----------------------------------------------------------------------------
Balance at end of period                              12,166         12,131 
----------------------------------------------------------------------------
Preferred Shares                                                            
Balance at beginning of period                         1,813          1,224 
Shares issued under public offering, net of                                 
 issue costs                                             442            589 
----------------------------------------------------------------------------
Balance at end of period                               2,255          1,813 
----------------------------------------------------------------------------
Additional Paid-In Capital                                                  
Balance at beginning of period                           401            379 
Issuance of stock options, net of exercises                3             (4)
Dilution impact from TC PipeLines, LP units                                 
 issued                                                    -             29 
Redemption of subsidiary's preferred shares               (6)             - 
----------------------------------------------------------------------------
Balance at end of period                                 398            404 
----------------------------------------------------------------------------
Retained Earnings                                                           
Balance at beginning of period                         5,096          4,687 
Net income attributable to controlling                                      
 interests                                               876            846 
Common share dividends                                  (680)          (650)
Preferred share dividends                                (48)           (37)
----------------------------------------------------------------------------
Balance at end of period                               5,244          4,846 
----------------------------------------------------------------------------
Accumulated Other Comprehensive Loss                                        
Balance at beginning of period                          (934)        (1,448)
Other comprehensive (loss)/income                        (25)            88 
----------------------------------------------------------------------------
Balance at end of period                                (959)        (1,360)
----------------------------------------------------------------------------
Equity Attributable to Controlling Interests          19,104         17,834 
----------------------------------------------------------------------------
Equity Attributable to Non-Controlling                                      
 Interests                                                                  
Balance at beginning of period                         1,611          1,425 
Net income attributable to non-controlling                                  
 interests                                                                  
  TC PipeLines, LP                                        74             36 
  Preferred share dividends of TCPL                        2             11 
  Portland                                                 9              7 
Other comprehensive income attributable to                                  
 non-controlling interests                                 5             57 
Issuance of TC PipeLines, LP units                                          
  Proceeds, net of issue costs                             -            384 
  Decrease in TransCanada's ownership                      -            (47)
Distributions to non-controlling interests               (92)           (70)
Redemption of subsidiary's preferred shares             (194)             - 
Foreign exchange and other                                (2)             9 
----------------------------------------------------------------------------
Balance at end of period                               1,413          1,812 
----------------------------------------------------------------------------
Total Equity                                          20,517         19,646 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 2013. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada's 2013 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 2013 audited consolidated financial statements included in TransCanada's 2013 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, 2013, except as described in Note 2, Changes in accounting policies.

2. Changes in accounting policies

CHANGES IN ACCOUNTING POLICIES FOR 2014

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 new guidance was effective January 1, 2014. There was no material impact on the Company's consolidated financial statements as a result of applying this new standard.

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 new guidance was effective prospectively from January 1, 2014 and will be applied for all applicable transactions after that date.

Unrecognized tax benefit

In July 2013, the FASB issued amended guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This new guidance was effective January 1, 2014. There was no material impact on the Company's consolidated financial statements as a result of applying this new standard.

FUTURE ACCOUNTING CHANGES

Reporting discontinued operations

In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance is effective from January 1, 2015 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

Revenue from contracts with customers

In May 2014, the FASB issued new guidance on Revenue from Contracts with Customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This new guidance is effective from January 1, 2017 with two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. Early application is not permitted. The Company is currently evaluating the impact of the adoption of this ASU and has not yet determined the effect on its consolidated financial statements.

3. Segmented information


----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months                                                                
 ended        Natural Gas     Liquids                                       
 June 30      Pipelines    Pipelines(1)   Energy    Corporate       Total   
             ------------- ------------ ----------- ----------- ------------
             ------------- ------------ ----------- ----------- ------------
(unaudited -                                                                
 millions of                                                                
 Canadian $)    2014  2013   2014  2013  2014  2013  2014  2013  2014  2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Revenues       1,154 1,031    366   278   714   700     -     - 2,234 2,009 
Income from                                                                 
 equity                                                                     
 investments      37    29      -     -    31   124     -     -    68   153 
Plant                                                                       
 operating                                                                  
 costs and                                                                  
 other          (348) (339)  (100)  (82) (214) (210)  (22)  (17) (684) (648)
Commodity                                                                   
 purchases                                                                  
 resold            -     -      -     -  (328) (283)    -     -  (328) (283)
Property                                                                    
 taxes           (84)  (77)   (17)  (10)  (18)  (19)    -     -  (119) (106)
Depreciation                                                                
 and                                                                        
 amortization   (263) (245)   (54)  (37)  (77)  (69)   (5)   (5) (399) (356)
Gain on sale                                                                
 of assets         -     -      -     -   108     -     -     -   108     - 
----------------------------------------------------------------------------
Segmented                                                                   
 earnings        496   399    195   149   216   243   (27)  (22)  880   769 
----------------------------------------------------------------            
----------------------------------------------------------------            
Interest                                                                    
 expense                                                         (297) (252)
Interest income and other                                          54   (11)
----------------------------------------------------------------------------
Income before income taxes                                        637   506 
Income tax expense                                               (165)  (98)
----------------------------------------------------------------------------
Net income                                                        472   408 
Net income attributable to non-controlling interests              (31)  (23)
----------------------------------------------------------------------------
Net income attributable to controlling interests                  441   385 
Preferred share dividends                                         (25)  (20)
----------------------------------------------------------------------------
Net income attributable to common shares                          416   365 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Previously Oil Pipelines.                                                
----------------------------------------------------------------------------
----------------------------------------------------------------------------
six months                                                                  
 ended        Natural Gas    Liquids                                        
 June 30      Pipelines   Pipelines(1)   Energy     Corporate      Total    
              ----------- ------------ ------------ --------- --------------
              ----------- ------------ ------------ --------- --------------
(unaudited -                                                                
 millions of                                                                
 Canadian $)   2014  2013   2014  2013   2014  2013 2014 2013   2014   2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Revenues      2,369 2,188    725   549  2,024 1,524    -    -  5,118  4,261 
Income from                                                                 
 equity                                                                     
 investments     89    69      -     -    114   177    -    -    203    246 
Plant                                                                       
 operating                                                                  
 costs and                                                                  
 other         (681) (657)  (201) (161)  (547) (420) (60) (51)(1,489)(1,289)
Commodity                                                                   
 purchases                                                                  
 resold           -     -      -     - (1,034) (659)   -    - (1,034)  (659)
Property taxes (170) (155)   (34)  (23)   (38)  (37)   -    -   (242)  (215)
Depreciation                                                                
 and                                                                        
 amortization  (525) (498)  (103)  (74)  (154) (143) (10)  (8)  (792)  (723)
Gain on sale                                                                
 of assets        -     -      -     -    108     -    -    -    108      - 
----------------------------------------------------------------------------
Segmented                                                                   
 earnings     1,082   947    387   291    473   442  (70) (59) 1,872  1,621 
--------------------------------------------------------------              
--------------------------------------------------------------              
Interest                                                                    
 expense                                                        (571)  (510)
Interest income and other                                         46      2 
----------------------------------------------------------------------------
Income before income taxes                                     1,347  1,113 
Income tax expense                                              (386)  (213)
----------------------------------------------------------------------------
Net income                                                       961    900 
Net income attributable to non-controlling interests             (85)   (54)
----------------------------------------------------------------------------
Net income attributable to controlling interests                 876    846 
Preferred share dividends                                        (48)   (35)
----------------------------------------------------------------------------
Net income attributable to common shares                         828    811 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Previously Oil Pipelines.                                                
TOTAL ASSETS                                                                
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of Canadian $)       June 30, 2014   December 31, 2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Natural Gas Pipelines                             25,406              25,165
Liquids Pipelines(1)                              14,189              13,253
Energy                                            13,580              13,747
Corporate                                          1,535               1,733
----------------------------------------------------------------------------
                                                  54,710              53,898
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Previously Oil Pipelines.                                                

4. Asset disposition

The sale of Cancarb Limited and its related power generation facility was completed on April 15, 2014 for aggregate gross proceeds of $190 million. TransCanada recognized a gain on the sale of $108 million ($99 million after tax) for the three and six months ended June 30, 2014. This gain has been presented separately on the consolidated statement of income.

5. Income taxes

At June 30, 2014, the total unrecognized tax benefit of uncertain tax positions was approximately $20 million (December 31, 2013 - $23 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, 2014 is $1 million and nil, respectively, of income for the reversal of interest expense and nil for penalties (June 30, 2013 - nil and $1 million, respectively, of interest expense and nil for penalties). At June 30, 2014, the Company had $6 million accrued for interest expense and nil accrued for penalties (December 31, 2013 - $6 million accrued for interest expense and nil for penalties).

The effective tax rates for the six-month periods ended June 30, 2014 and 2013 were 29 per cent and 19 per cent, respectively. The higher effective tax rate in 2014 compared to 2013 was primarily the result of the impact of the 2013 NEB decision (RH-003-2011), changes in the proportion of income earned between Canadian and foreign jurisdictions as well as higher flow-through taxes in 2014 on Canadian regulated pipelines, partially offset by the disposition of Cancarb Limited in 2014.

6. Long-term debt

In the three and six months ended June 30, 2014, TransCanada capitalized interest related to capital projects of $63 million and $142 million, respectively (2013 - $60 million and $115 million, respectively).

LONG-TERM DEBT ISSUED


----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount                                                                      
(unaudited -                                                                
 millions                                                                   
 of $)        Type               Maturity date   Interest rate   Date issued
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
US$1,250      Senior unsecured   March 1, 2034          4.625% February 2014
               notes                                                        
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LONG-TERM DEBT RETIRED                                                      
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount                                                                      
(unaudited - millions of                                                    
 Canadian $)                   Type          Retirement date   Interest rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
$450                           Medium term                                  
                                notes           January 2014           5.65%
$300                           Medium term                                  
                                notes          February 2014           5.05%
$125                           Debenture           June 2014          11.10%
$53                            Debenture           June 2014          11.20%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

7. Equity and share capital

PREFERRED SHARE ISSUANCE

In January 2014, TransCanada completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $450 million. The holders of the Series 9 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly. The dividend rate will reset on October 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 2.35 per cent. The preferred shares are redeemable by TransCanada on or after October 30, 2019 and on October 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends.

The Series 9 preferred shareholders will have the right to convert their shares into Series 10 cumulative redeemable first preferred shares on October 30, 2019 and on October 30 of every fifth year thereafter. The holders of Series 10 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 2.35 per cent.

PREFERRED SHARE REDEMPTION

On March 5, 2014, TCPL redeemed all of the four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series Y at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends to the redemption date.

8. Other comprehensive income/(loss) and accumulated other comprehensive loss

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended June 30, 2014                  Income tax                
(unaudited - millions of           Before tax      recovery/     Net of tax 
 Canadian $)                           amount      (expense)         amount 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Foreign currency translation                                                
 gains and losses on net                                                    
 investment in foreign operations        (140)           (50)          (190)
Change in fair value of net                                                 
 investment hedges                        107            (28)            79 
Change in fair value of cash flow                                           
 hedges                                    (9)             5             (4)
Reclassification to net income of                                           
 gains and losses on cash flow                                              
 hedges                                     4             (2)             2 
Reclassification to net income of                                           
 actuarial gains and losses and                                             
 prior service costs on pension                                             
 and other post-retirement                                                  
 benefit plans                              7             (2)             5 
Other comprehensive income on                                               
 equity investments                         1              1              2 
----------------------------------------------------------------------------
Other comprehensive loss                  (30)           (76)          (106)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended June 30, 2013                  Income tax                
(unaudited - millions of           Before tax      recovery/     Net of tax 
 Canadian $)                           amount      (expense)         amount 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Foreign currency translation                                                
 gains and losses on net                                                    
 investment 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 (loss)/income         (58)           119             61 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
six months ended June 30, 2014                    Income tax                
(unaudited - millions of           Before tax      recovery/     Net of tax 
 Canadian $)                           amount      (expense)         amount 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Foreign currency translation                                                
 gains and losses on net                                                    
 investment in foreign operations          51             (1)            50 
Change in fair value of net                                                 
 investment hedges                        (64)            16            (48)
Change in fair value of cash flow                                           
 hedges                                    42            (15)            27 
Reclassification to net income of                                           
 gains and losses on cash flow                                              
 hedges                                   (99)            39            (60)
Reclassification to net income of                                           
 actuarial gains and losses and                                             
 prior service costs on pension                                             
 and other post-retirement                                                  
 benefit plans                             13             (4)             9 
Other comprehensive income on                                               
 equity investments                         1              1              2 
----------------------------------------------------------------------------
Other comprehensive (loss)/income         (56)            36            (20)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
six months ended June 30, 2013                    Income tax                
(unaudited - millions of Canadian  Before tax      recovery/     Net of tax 
 $)                                    amount      (expense)         amount 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Foreign currency translation                                                
 gains and losses on net                                                    
 investment 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 (loss)/income          (7)           152            145 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended                                                          
 June 30, 2014           Currency    Cash Pension and                       
(unaudited - millions translation    flow   OPEB plan      Equity           
 of Canadian $)       adjustments  hedges adjustments Investments  Total(1) 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
AOCI balance at April                                                       
 1, 2014                     (560)    (35)       (193)       (104)     (892)
Other comprehensive                                                         
 loss before                                                                
 reclassifications(2)         (72)     (4)          -           -       (76)
Amounts reclassified                                                        
 from accumulated                                                           
 other comprehensive                                                        
 loss(3)                        -       2           5           2         9 
----------------------------------------------------------------------------
Net current period                                                          
 other comprehensive                                                        
 (loss)/income                (72)     (2)          5           2       (67)
----------------------------------------------------------------------------
AOCI balance at June                                                        
 30, 2014                    (632)    (37)       (188)       (102)     (959)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  All amounts are net of tax. Amounts in parentheses indicate losses       
   recorded to OCI.                                                         
2  Other comprehensive income before reclassifications on currency          
   translation adjustments is net of non-controlling interest losses of $39 
   million.                                                                 
3  Gains 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 $9  
   million ($4 million, net of tax) at June 30, 2014. 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, 2014                Currency    Cash Pension and                       
(unaudited - millions translation    flow   OPEB plan      Equity           
 of Canadian $)       adjustments  hedges adjustments Investments  Total(1) 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
AOCI balance at                                                             
 January 1, 2014             (629)     (4)       (197)       (104)     (934)
Other comprehensive                                                         
 (loss)/income before                                                       
 reclassifications(2)          (3)     27           -           -        24 
Amounts reclassified                                                        
 from accumulated                                                           
 other comprehensive                                                        
 loss(3)                        -     (60)          9           2       (49)
----------------------------------------------------------------------------
Net current period                                                          
 other comprehensive                                                        
 (loss)/income                 (3)    (33)          9           2       (25)
----------------------------------------------------------------------------
AOCI balance at June                                                        
 30, 2014                    (632)    (37)       (188)       (102)     (959)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  All amounts are net of tax. Amounts in parentheses indicate losses       
   recorded to OCI.                                                         
2  Other comprehensive (loss)/income before reclassifications on currency   
   translation adjustments is net of non-controlling interest gains of $5   
   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 $9  
   million ($4 million, net of tax) at June 30, 2014. 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 the
                                                                   condensed
                                   three months     six months  consolidated
(unaudited - millions of Canadian         ended          ended  statement of
 $)                               June 30, 2014  June 30, 2014        income
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Cash flow hedges                                                            
Power and natural gas                        (1)           107       Revenue
                                                                    (Energy)
Interest                                     (3)            (8)     Interest
                                                                     expense
----------------------------------------------------------------------------
                                             (4)            99  Total before
                                                                         tax
                                              2            (39)   Income tax
                                                                     expense
----------------------------------------------------------------------------
                                             (2)            60    Net of tax
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Pension and other post-retirement                                           
 plan adjustments                                                           
Amortization of actuarial loss               (7)           (13) Total before
 and past service cost (2)                                               tax
                                              2              4    Income tax
                                                                     expense
----------------------------------------------------------------------------
                                             (5)            (9)   Net of tax
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Equity Investments                                                          
Equity income                                (1)            (1)  Income from
                                                                      Equity
                                                                 Investments
                                             (1)            (1)   Income tax
                                                                     expense
----------------------------------------------------------------------------
                                             (2)            (2)   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 9 for additional detail.  

9. 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 plans benefit plans    plans        plans   
                        ------------- ------------- ----------- ------------
                        ------------- ------------- ----------- ------------
(unaudited - millions of                                                    
 Canadian $)              2014   2013   2014   2013  2014  2013  2014  2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Service cost                21     22      -      -    43    41     1     1 
Interest cost               28     23      3      2    56    47     5     4 
Expected return on plan                                                     
 assets                    (34)   (29)    (1)    (1)  (69)  (58)   (1)   (1)
Amortization of                                                             
 actuarial loss              6      6      -      -    11    15     1     1 
Amortization of past                                                        
 service cost                1      1      -      -     1     1     -     - 
Amortization of                                                             
 regulatory asset            4      8      -      1     9    15     -     1 
Amortization of                                                             
 transitional obligation                                                    
 related to regulated                                                       
 business                    -      -      1      1     -     -     1     1 
----------------------------------------------------------------------------
Net benefit cost                                                            
 recognized                 26     31      3      3    51    61     7     7 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

10. Risk management and financial instruments

RISK MANAGEMENT OVERVIEW

TransCanada has exposure to counterparty credit risk and market risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and, ultimately, shareholder value.

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 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, 2014, there were no significant amounts past due or impaired, and there were no significant credit losses during the period.

At June 30, 2014, the Company had a credit risk concentration of $211 million (December 31, 2013 - $240 million) due from one counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.

NET INVESTMENT IN FOREIGN OPERATIONS

The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forward contracts and foreign exchange options.

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of Canadian $)      June 30, 2014   December 31, 2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Carrying value                        15,600 (US 14,600)  14,200 (US 13,400)
Fair value                            18,200 (US 17,100)  16,000 (US 15,000)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Derivatives designated as a net investment hedge


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     June 30, 2014       December 31, 2013  
                                 --------------------- ---------------------
                                 --------------------- ---------------------
                                           Notional or           Notional or
(unaudited - millions of Canadian     Fair   principal      Fair   principal
 $)                               Value(1)      amount  value(1)      amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Asset/(liability)                                                           
U.S. dollar cross-currency                                                  
 interest rate swaps                                                        
(maturing 2014 to 2019)(2)            (186)   US 3,250      (201)   US 3,800
U.S. dollar foreign exchange                                                
 forward contracts                                                          
(maturing 2014)                        (14)     US 300       (11)     US 850
----------------------------------------------------------------------------
                                      (200)   US 3,550      (212)   US 4,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
1  Fair values equal carrying values.                                       
   Net income in the three and six months ended June 30, 2014 included net  
   realized gains of $5 million and $11 million, respectively, (2013 - gains
2  of $7 million and $14 million, respectively) related to the interest     
   component of cross-currency swaps which is included in interest expense. 

Balance sheet presentation of net investment hedges

The balance sheet classification of the fair value of derivatives used to hedge the Company's net investment in foreign operations is as follows:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of Canadian $)      June 30, 2014   December 31, 2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Other current assets                                  5                   5 
Intangible and other assets                           1                   - 
Accounts payable and other                          (57)                (50)
Other long-term liabilities                        (149)               (167)
----------------------------------------------------------------------------
                                                   (200)               (212)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

FINANCIAL INSTRUMENTS

Non-derivative financial instruments

Fair value of non-derivative financial instruments

The fair value of the Company's notes receivables is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers. The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that equal their fair value due to the nature of the item or the short time to maturity and would be classified in Level II of the fair value hierarchy.

Balance sheet presentation of non-derivative financial instruments

The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts equal fair value, and would be classified in Level II of the fair value hierarchy:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                   June 30, 2014         December 31, 2013  
                                --------------------- ----------------------
                                --------------------- ----------------------
(unaudited - millions of           Carrying      Fair    Carrying      Fair 
 Canadian $)                      amount(1)     value   amount(1)     value 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Notes receivable and other(1)           196       235         226       269 
Available for sale assets(2)             46        46          47        47 
Current and long-term debt(3,4)     (23,292)  (27,819)    (22,865)  (26,134)
Junior subordinated notes            (1,067)   (1,111)     (1,063)   (1,093)
----------------------------------------------------------------------------
                                    (24,117)  (28,649)    (23,655)  (26,911)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  Notes receivable are included in other current assets and intangible and 
   other assets on the condensed consolidated balance sheet.                
2  Available for sale assets are included in intangible and other assets on 
   the condensed consolidated balance sheet.                                
3  Long-term debt is recorded at amortized cost, except for US$300 million  
   (December 31, 2013 - US$200 million) that is attributed to hedged risk   
   and recorded at fair value.                                              
4  Consolidated net income for the three and six months ended June 30, 2014 
   included gains of $1 million and losses of $5 million, respectively,     
   (2013 - gains of $3 million and losses of $7 million, respectively) for  
   fair value adjustments attributable to the hedged interest rate risk     
   associated with interest rate swap fair value hedging relationships on   
   US$300 million of long-term debt at June 30, 2014 (December 31, 2013 -   
   US$200 million). There were no other unrealized gains or losses from fair
   value adjustments to the non-derivative financial instruments.           

Derivative instruments

Fair value of derivative instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses current market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives and available for sale assets has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

Where possible, derivative instruments are designated as hedges, but in some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period.

Balance sheet presentation of derivative instruments

The balance sheet classification of the fair value of the derivative instruments is as follows:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of Canadian $)      June 30, 2014   December 31, 2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Other current assets                                354                 395 
Intangible and other assets                         127                 112 
Accounts payable and other                         (404)               (357)
Other long-term liabilities                        (236)               (255)
----------------------------------------------------------------------------
                                                   (159)               (105)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

2014 derivative instruments summary

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of Canadian $,            Natural   Foreign           
 unless noted otherwise)                Power       gas  exchange  Interest 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Derivative instruments held for                                             
 trading(1)                                                                 
Fair values(2,3)                                                            
  Assets                                 $314       $51       $14        $5 
  Liabilities                           ($320)     ($70)      ($2)      ($5)
Notional values(3)                                                          
  Volumes(4)                                                                
    Purchases                          41,098        99         -         - 
    Sales                              39,010        50         -         - 
  U.S. dollars                              -         -  US 1,516    US 100 
Net unrealized gains/(losses) in the                                        
 period(5)                                                                  
  three months ended June 30, 2014         $6      ($14)      $25        $- 
  six months ended June 30, 2014          $15      ($21)      $23        $- 
Net realized (losses)/gains in the                                          
 period(5)                                                                  
  three months ended June 30, 2014        ($3)      ($4)      ($1)       $- 
  six months ended June 30, 2014         ($31)      $46      ($18)       $- 
Maturity dates(3)                   2014-2017 2014-2020      2014      2016 
----------------------------------------------------------------------------
Derivative instruments in hedging                                           
 relationships(6,7)                                                         
Fair values(2,3)                                                            
  Assets                                  $86        $-        $-        $5 
  Liabilities                            ($35)       $-        $-       ($2)
Notional values(3)                                                          
  Volumes(4)                                                                
    Purchases                          10,102         -         -         - 
    Sales                               6,034         -         -         - 
  U.S. dollars                              -         -         -    US 450 
Net realized (losses)/gains in the                                          
 period(5)                                                                  
  three months ended June 30, 2014        ($4)       $-        $-        $1 
  six months ended June 30, 2014         $188        $-        $-        $2 
Maturity dates(3)                   2014-2018         -         - 2015-2018 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 June 30, 2014.                                                     
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 $5 million and a notional amount of US$300   
   million as at June 30, 2014. For the three and six months ended June 30, 
   2014, net realized gains on fair value hedges were $2 million and $3     
   million, respectively, and were included in interest expense. For the    
   three and six months ended June 30, 2014, 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, 2014, 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.           

2013 derivative instruments summary

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of Canadian $,            Natural   Foreign           
 unless noted otherwise)                Power       gas  exchange  Interest 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Derivative instruments held for                                             
 trading(1)                                                                 
Fair values(2,3)                                                            
  Assets                                 $265       $73        $-        $8 
  Liabilities                           ($280)     ($72)     ($12)      ($7)
Notional values(3)                                                          
  Volumes(4)                                                                
    Purchases                          29,301        88         -         - 
    Sales                              28,534        60         -         - 
  Canadian dollars                          -         -         -       400 
  U.S. dollars                              -         -  US 1,015    US 100 
Net unrealized gains/(losses) in the                                        
 period(5)                                                                  
  three months ended June 30, 2013         $5      ($21)     ($10)       $- 
  six months ended June 30, 2013          ($3)     ($12)     ($16)       $- 
Net realized losses in the period(5)                                        
  three months ended June 30, 2013       ($29)      ($5)      ($6)       $- 
  six months ended June 30, 2013         ($36)      ($7)      ($7)       $- 
Maturity dates(3)                   2014-2017 2014-2016      2014 2014-2016 
----------------------------------------------------------------------------
Derivative instruments in hedging                                           
 relationships(6,7)                                                         
Fair values(2,3)                                                            
  Assets                                 $150        $-        $-        $6 
  Liabilities                            ($22)       $-       ($1)      ($1)
Notional values(3)                                                          
  Volumes(4)                                                                
    Purchases                           9,758         -         -         - 
    Sales                               6,906         -         -         - 
  U.S. dollars                              -         -     US 16    US 350 
Net realized (losses)/gains in the                                          
 period(5)                                                                  
  three months ended June 30, 2013       ($84)      ($1)       $-        $2 
  six months ended June 30, 2013         ($11)      ($1)       $-        $4 
Maturity dates(3)                   2014-2018         -      2014 2015-2018 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 2013.                                                 
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 $5 million and a notional amount of US$200   
   million as at December 31, 2013. Net realized gains on fair value hedges 
   for the three and six months ended June 30, 2013 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.  
7  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.           

Derivatives in cash flow hedging relationships

The components of OCI (Note 8) related to derivatives in cash flow hedging relationships are as follows:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of Canadian $,                                        
 pre-tax)                                2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Change in fair value of derivative                                          
 instruments recognized in OCI                                              
 (effective portion)                                                        
  Power                                    (7)      (70)       34       (34)
  Natural gas                              (1)        -        (1)        - 
  Foreign exchange                          -         2        10         4 
  Interest                                 (1)        -        (1)        - 
----------------------------------------------------------------------------
                                           (9)      (68)       42       (30)
----------------------------------------------------------------------------
Reclassification of (losses)/gains                                          
 on derivative instruments from AOCI                                        
 to net income (effective                                                   
 portion)(1)                                                                
  Power(2)                                 (1)       12      (109)        1 
  Natural gas                               2         2         2         2 
  Interest                                  3         4         8         8 
----------------------------------------------------------------------------
                                            4        18       (99)       11 
----------------------------------------------------------------------------
Gains/(losses) on derivative                                                
 instruments recognized in earnings                                         
 (ineffective portion)                                                      
  Power                                     3        (2)      (10)       (7)
----------------------------------------------------------------------------
                                            3        (2)      (10)       (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  No amounts have been excluded from the assessment of hedge effectiveness.
   Amounts in parentheses indicate losses recorded to OCI.                  
2  Reported within Energy revenues on the condensed consolidated statement  
   of income.                                                               

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 to 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                               
                                  instruments                               
at June 30, 2014                 presented on        Amounts                
(unaudited - millions of          the balance  available for                
 Canadian $)                            sheet      offset(1)    Net amounts 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Derivative - Asset                                                          
  Power                                   400           (317)            83 
  Natural gas                              51            (50)             1 
  Foreign exchange                         20            (20)             - 
  Interest                                 10             (1)             9 
----------------------------------------------------------------------------
Total                                     481           (388)            93 
----------------------------------------------------------------------------
Derivative - Liability                                                      
  Power                                  (355)           317            (38)
  Natural gas                             (70)            50            (20)
  Foreign exchange                       (208)            20           (188)
  Interest                                 (7)             1             (6)
----------------------------------------------------------------------------
Total                                    (640)           388           (252)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 2014, the Company had provided cash collateral of $164 million and letters of credit of $18 million to its counterparties. The Company held $1 million in letters of credit on asset exposures at June 30, 2014.

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, 2013:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                        Gross                               
                                   derivative                               
                                  instruments                               
at December 31, 2013             presented on        Amounts                
(unaudited - millions of          the balance  available for                
 Canadian $)                            sheet      offset(1)    Net amounts 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Derivative - Asset                                                          
  Power                                   415           (277)           138 
  Natural gas                              73            (61)            12 
  Foreign exchange                          5             (5)             - 
  Interest                                 14             (2)            12 
----------------------------------------------------------------------------
Total                                     507           (345)           162 
----------------------------------------------------------------------------
Derivative - Liability                                                      
  Power                                  (302)           277            (25)
  Natural gas                             (72)            61            (11)
  Foreign exchange                       (230)             5           (225)
  Interest                                 (8)             2             (6)
----------------------------------------------------------------------------
Total                                    (612)           345           (267)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 2013, the Company had provided cash collateral of $67 million and letters of credit of $85 million to its counterparties. The Company held $11 million in cash collateral and $32 million in letters of credit on asset exposures at December 31, 2013.

Credit risk related contingent features of derivative instruments

Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit risk related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade.

Based on contracts in place and market prices at June 30, 2014, the aggregate fair value of all derivative instruments with credit risk related contingent features that were in a net liability position was $17 million (December 31, 2013 - $16 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2013 - nil). If the credit risk related contingent features in these agreements were triggered on June 30, 2014, the Company would have been required to provide collateral of $17 million (December 31, 2013 - $16 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:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                              Quoted   Significant                          
                           prices in         other    Significant           
at June 30, 2014              active    observable   unobservable           
(unaudited - millions of     markets        inputs         inputs           
 Canadian $, pre-tax)   (Level I)(1) (Level II)(1) (Level III)(1)     Total 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Derivative instrument                                                       
 assets:                                                                    
  Power commodity                                                           
   contracts                       -           396              4       400 
  Natural gas commodity                                                     
   contracts                      33            18              -        51 
  Foreign exchange                                                          
   contracts                       -            20              -        20 
  Interest rate                                                             
   contracts                       -            10              -        10 
Derivative instrument                                                       
 liabilities:                                                               
  Power commodity                                                           
   contracts                       -          (352)            (3)     (355)
  Natural gas commodity                                                     
   contracts                     (32)          (36)            (2)      (70)
  Foreign exchange                                                          
   contracts                       -          (208)             -      (208)
  Interest rate                                                             
   contracts                       -            (7)             -        (7)
Non-derivative financial                                                    
 instruments:                                                               
  Available for sale                                                        
   assets                          -            46              -        46 
----------------------------------------------------------------------------
                                   1          (113)            (1)     (113)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  There were no transfers from Level I to Level II or from Level II to     
   Level III for the six months ended June 30, 2014.                        

The fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2013, are categorized as follows:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                              Quoted   Significant                          
                           prices in         other    Significant           
at December 31, 2013          active    observable   unobservable           
(unaudited - millions of     markets        inputs         inputs           
 Canadian $, pre-tax)   (Level I)(1) (Level II)(1) (Level III)(1)     Total 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Derivative instrument                                                       
 assets:                                                                    
  Power commodity                                                           
   contracts                       -           411              4       415 
  Natural gas commodity                                                     
   contracts                      48            25              -        73 
  Foreign exchange                                                          
   contracts                       -             5              -         5 
  Interest rate                                                             
   contracts                       -            14              -        14 
Derivative instrument                                                       
 liabilities:                                                               
  Power commodity                                                           
   contracts                       -          (299)            (3)     (302)
  Natural gas commodity                                                     
   contracts                     (50)          (22)             -       (72)
  Foreign exchange                                                          
   contracts                       -          (230)             -      (230)
  Interest rate                                                             
   contracts                       -            (8)             -        (8)
Non-derivative financial                                                    
 instruments:                                                               
  Available for sale                                                        
   assets                          -            47              -        47 
----------------------------------------------------------------------------
                                  (2)          (57)             1       (58)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  There were no transfers from Level I to Level II or from Level II to     
   Level III for the year ended December 31, 2013.                          

The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                 Derivatives(1)             
                                    ----------------------------------------
                                    ----------------------------------------
                                     three months ended   six months ended  
                                         June 30               June 30      
                                    ------------------- --------------------
                                    ------------------- --------------------
(unaudited - millions of Canadian $,                                        
 pre-tax)                                2014      2013      2014      2013 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Balance at beginning of period              1         1         1        (2)
Settlements                                 -         1         -         1 
Transfers out of Level III                  -        (1)        -        (1)
Total losses included in net income        (2)        -        (2)        - 
Total (losses)/gains included in OCI        -        (1)        -         2 
----------------------------------------------------------------------------
Balance at end of period                   (1)        -        (1)        - 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  For the three and six months ended June 30, 2014, energy revenues include
   unrealized losses attributed to derivatives in the Level III category    
   that were still held at the reporting date of $2 million (2013 - nil).   

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $4 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at June 30, 2014.

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.

GUARANTEES

TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust (BPC), have each severally guaranteed certain contingent financial obligations of Bruce B related to a lease agreement and contractor and supplier 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 delivery 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, 2014    at December 31, 2013
                                 --------------------- ---------------------
                                 --------------------- ---------------------
(unaudited -                                                                
 millions of                       Potential  Carrying  Potential   Carrying
 Canadian $)                Term Exposure(1)     Value Exposure(1)     Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Bruce Power           ranging to                                            
                         2019(2)         674         7         740         8
Other jointly                                                               
 owned entities  ranging to 2040          64        10          51        10
----------------------------------------------------------------------------
                                         738        17         791        18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1  TransCanada's share of the potential estimated current or contingent     
   exposure.                                                                
2  Except for one guarantee with no termination date.                       

Contacts:
TransCanada Media Enquiries:
Shawn Howard/Davis Sheremata
403.920.7859 or 800.608.7859

TransCanada Investor & Analyst Enquiries:
David Moneta/Lee Evans
403.920.7911 or 800.361.6522

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