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TransCanada Reports 15 Per Cent Increase in First Quarter Comparable Earnings

Funds Generated from Operations Exceed $1.1 Billion

CALGARY, ALBERTA -- (Marketwired) -- 05/02/14 -- TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada or the Company) today announced comparable earnings for first quarter 2014 of $422 million or $0.60 per share compared to $370 million or $0.52 per share for the same period in 2013, a 15 per cent increase on a per share basis. Funds generated from operations for first quarter 2014 were $1.102 billion, a 20 per cent increase compared to $916 million for the same period in 2013. TransCanada's Board of Directors also declared a quarterly dividend of $0.48 per common share for the quarter ending June 30, 2014, equivalent to $1.92 per common share on an annualized basis.

"The significant increase in earnings and cash flow reflects the strong performance of our existing assets as well as contributions from recently completed projects including the Keystone Gulf Coast extension," said Russ Girling, TransCanada's president and chief executive officer. "An unseasonably cold winter resulted in strong demand for our critical pipeline and power infrastructure assets and underscores their importance and value to the North American economy. As we move forward, we will remain focused on the safe and reliable operation of our assets and the careful execution of our future growth plans which are expected to generate significant shareholder value."

Today we are advancing $36 billion of commercially secured capital projects, all of which are backed by long-term contracts or cost of service business models. This unprecedented capital program will see a significant expansion of all three of our core businesses. Over the course of 2014, we expect to place approximately $3.6 billion of assets into service, including the recently completed Keystone Gulf Coast extension, the Tamazunchale Pipeline Extension, further expansions of the NGTL System and four additional Ontario Solar facilities. Over the remainder of the decade, subject to required approvals, our blue-chip portfolio of contracted energy infrastructure projects is expected to generate significant growth in earnings and cash flow.

Highlights

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


--  First quarter financial results
    --  Net income attributable to common shares of $412 million or $0.58
        per share
    --  Comparable earnings of $422 million or $0.60 per share
    --  Comparable earnings before interest, taxes, depreciation and
        amortization (EBITDA) of $1.4 billion
    --  Funds generated from operations of $1.1 billion
--  Declared a quarterly dividend of $0.48 per common share for the quarter
    ending June 30, 2014
--  Placed the US$2.6 billion Keystone Gulf Coast extension into service on
    January 22, 2014
--  Secured 2.0 billion cubic feet a day (Bcf/d) of long-term contracts on
    the ANR Pipeline
--  Filed a Project Description with the National Energy Board (NEB) for the
    $12 billion Energy East Project
--  Coastal GasLink and Prince Rupert Gas Transmission both submitted
    applications for an Environmental Assessment Certificate and
    applications with the British Columbia (B.C.) Oil and Gas Commission

Comparable earnings for first quarter 2014 were $422 million or $0.60 per share compared to $370 million or $0.52 per share for the same period in 2013. Higher earnings from the NGTL System, Keystone, Bruce Power, U.S. Power, and Natural Gas Storage all contributed to the increased results.

Net income attributable to common shares for first quarter 2014 was $412 million or $0.58 per share compared to $446 million or $0.63 per share in first quarter 2013. The first quarter 2013 results included $84 million of net income related to the 2012 impact of the NEB decision on the Canadian Mainline. This amount was excluded from comparable earnings.

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

Liquids Pipelines:


--  Keystone Pipeline System: We finished constructing the 780 kilometre
    (km) (485 mile) Gulf Coast extension of the Keystone Pipeline System,
    from Cushing, Oklahoma to the U.S. Gulf Coast. Crude oil transportation
    service on the pipeline began January 22, 2014 and we expect an average
    capacity of 520,000 barrels per day during its first year of operation.

--  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 the 90 day National Interest Determination
    period has been extended indefinitely. The DOS has said only that the
    permit process will conclude once factors that have a significant impact
    on determining national interest of the proposed project have been
    evaluated.

    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. We disagree with the decision of the Nebraska district court
    and are continuing to analyze the judgment and decide what next steps
    may be taken. Nebraska's Attorney General has filed an appeal and the
    Nebraska Supreme Court is expected to hear the appeal in third quarter
    2014.

    As of March 31, 2014, we have invested US$2.3 billion in the Keystone XL
    project.

--  Energy East Pipeline: On March 4, 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
    mid-2014 for approvals to construct and operate the pipeline project and
    terminal facilities.

--  Heartland Pipeline and TC Terminals: In February 2014, the application
    for the terminal facility was approved by the Alberta Energy Regulator.
    The Heartland Pipeline and TC Terminals will include a 200 km (125 mile)
    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.

Natural Gas Pipelines:


--  NGTL System: The NEB has approved approximately $400 million of
    expansion projects that are currently in various stages of development
    or construction at March 31, 2014. In addition, we have approximately
    $1.8 billion in other projects that have been applied for but are not
    yet approved by the NEB, mainly comprised of the $1.7 billion North
    Montney Project.

    On February 5, 2014, we received a Hearing Order for the North Montney
    Project. The hearing will begin in August 2014. The project includes
    approximately 300 km (186 miles) of new pipeline on the NGTL System to
    receive and transport natural gas from the North Montney area of B.C.

--  Canadian Mainline: On March 31, 2014, the NEB responded to the LDC
    Settlement application we filed on December 20, 2013. The NEB did not
    approve the application but provided direction that we can continue with
    the application as a contested tolls application, amend the application
    or terminate the processing of the application. We will be amending the
    application with additional information in second quarter 2014. On April
    22, 2014, the NEB issued a notice advising that it will hold a public
    hearing on the amended application and setting the list of issues. A
    further letter from the NEB setting out the hearing process and schedule
    is expected in the next few weeks.

--  ANR Pipeline: In March 2014, we announced that we secured approximately
    2.0 Bcf/d of firm natural gas transportation commitments on the ANR
    Pipeline system's Southeast Main Line at maximum rates for an average
    term of 23 years. Approximately 1.25 Bcf/d will commence in 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.
    Approximately US$100 million of capital investment will be required to
    bring this additional supply to market. We are also assessing further
    demand for services which could result in incremental opportunities to
    enhance and expand the ANR Pipeline system.

--  Tamazunchale Pipeline Extension Project: Construction activity on the
    US$600 million extension continues. The project is currently expected to
    be in service at the end of July 2014.

--  Coastal GasLink: We submitted an Environmental Assessment application to
    the B.C. Environmental Assessment Office (BCEAO) in January 2014 and a
    public comment period is currently underway. In addition, the B.C. Oil
    and Gas Commission application was filed on March 24, 2014, together
    with an addendum to the Environmental Assessment application to capture
    recent route refinements.

--  Prince Rupert Gas Transmission: We completed two key milestones in April
    2014. The Environmental Assessment application was submitted to the
    BCEAO on April 2, 2014 for a completeness review and the application to
    the B.C. Oil and Gas Commission was filed on April 4, 2014.

--  Alaska LNG Project: On April 20, 2014, the State of Alaska passed new
    legislation that will transition from the Alaska Gasline Inducement Act
    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. It is anticipated that two years of pre-front end
    engineering will be completed before further decisions to commercialize
    the project will be made.

Energy:


--  Ontario Solar: We expect the acquisition of four additional facilities
    to close in fourth quarter 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 sold under 20-
    year power purchase arrangements with the Ontario Power Authority.

--  Cancarb:  In January 2014, we reached an agreement to sell Cancarb and
    its related power generation business for proceeds of $190 million,
    subject to closing adjustments. The sale closed on April 15, 2014 and we
    expect to realize an after-tax gain of approximately $95 million in our
    second quarter 2014 results.

--  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. The contract contained provisions allowing for
    possible early termination. In consideration for this termination, we
    expect to record an after-tax charge of approximately $33 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.

Corporate:


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

--  In January 2014, we completed a public offering of 18 million Series 9
    Cumulative Redeemable First Preferred Shares at a price of $25 per
    share, resulting in gross proceeds of $450 million. The initial dividend
    rate is fixed to October 30, 2019 at $1.0625 per share per annum paid
    quarterly.

    In February 2014, we issued US$1.25 billion of senior notes maturing on
    March 1, 2034, bearing interest at 4.625 per cent.

    The net proceeds of these offerings will be used for general corporate
    purposes and to reduce short-term indebtedness, which was used to fund a
    portion of our capital program and for general corporate purposes.

--  In March 2014, we redeemed all four million outstanding TransCanada
    PipeLines Limited (TCPL) 5.60 per cent Cumulative Redeemable First
    Preferred Shares Series Y at a price of $50 per share plus $0.2455 of
    accrued and unpaid dividends. The total face value of the outstanding
    Series Y Shares was $200 million and they carried an aggregate of $11
    million in annualized dividends.

Teleconference - Audio and Slide Presentation:

We will hold a teleconference and webcast on Friday, May 2, 2014 to discuss our first 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 1 p.m. (MT) / 3 p.m. (ET).

Analysts, members of the media and other interested parties are invited to participate by calling 800.565.0813 or 416.340.8527 (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 May 9, 2014. Please call 800.408.3053 or 905.694.9451 and enter pass code 1890056.

The unaudited interim Consolidated Financial Statements and Management's Discussion and Analysis (MD&A) are available on SEDAR at www.sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website at www.transcanada.com.

With more than 60 years' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 68,500 kilometres (42,500 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with more than 400 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns or has interests in over 11,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: www.transcanada.com or check us out on Twitter @TransCanada or http://blog.transcanada.com.

Forward Looking Information

This news release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as "anticipate", "expect", "believe", "may", "will", "should", "estimate", "intend" or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future plans and financial outlook. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to TransCanada's Quarterly Report to Shareholders dated May 1, 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, 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 May 1, 2014.

Quarterly report to shareholders

First quarter 2014

Financial highlights

Comparable EBITDA, comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See non-GAAP measures section for more information.


----------------------------------------------------------------------------
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                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $, except per share
 amounts)                                               2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Income
Revenue                                                2,884          2,252
Comparable EBITDA                                      1,396          1,168
Net income attributable to common shares                 412            446
  per common share - basic and diluted                 $0.58          $0.63
Comparable earnings                                      422            370
  per common share                                     $0.60          $0.52

Operating cash flow
Funds generated from operations                        1,102            916
Increase in operating working capital                   (123)          (210)
----------------------------------------------------------------------------
Net cash provided by operations                          979            706
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----------------------------------------------------------------------------

Investing activities
Capital expenditures                                     778            929
Equity investments                                        89             32

Dividends
Per common share                                       $0.48          $0.46

Basic common shares outstanding (millions)
Average for the period                                   708            706
End of period                                            708            706
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Management's discussion and analysis

May 1, 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 months ended March 31, 2014, and should be read with the accompanying unaudited condensed consolidated financial statements for the three months ended March 31, 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 May 1, 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 better 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 better 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. 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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. These may include:


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

Reconciliation of non-GAAP measures


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $, except per share
 amounts)                                               2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

EBITDA                                                 1,385          1,219
NEB decision - 2012                                        -            (55)
Non-comparable risk management activities
 affecting EBITDA                                         11              4
----------------------------------------------------------------------------
Comparable EBITDA                                      1,396          1,168
Comparable depreciation and amortization                (393)          (354)
----------------------------------------------------------------------------
Comparable EBIT                                        1,003            814
----------------------------------------------------------------------------
Other income statement items
Comparable interest expense                             (274)          (257)
Comparable interest income and other                      (6)            18
Comparable income tax expense                           (224)          (159)
Net income attributable to non-controlling
 interests                                               (54)           (31)
Preferred share dividends                                (23)           (15)
----------------------------------------------------------------------------
Comparable earnings                                      422            370
Specific items (net of tax):
NEB decision - 2012                                        -             84
Risk management activities(1)                            (10)            (8)
----------------------------------------------------------------------------
Net income attributable to common shares                 412            446
----------------------------------------------------------------------------

Comparable depreciation and amortization                (393)          (354)
Specific item:
NEB decision - 2012                                        -            (13)
----------------------------------------------------------------------------
Depreciation and amortization                           (393)          (367)
----------------------------------------------------------------------------

Comparable interest expense                             (274)          (257)
Specific item:
NEB decision - 2012                                        -             (1)
----------------------------------------------------------------------------
Interest expense                                        (274)          (258)
----------------------------------------------------------------------------

Comparable interest income and other                      (6)            18
Specific items:
NEB decision - 2012                                        -              1
Risk management activities(1)                             (2)            (6)
----------------------------------------------------------------------------
Interest income and other                                 (8)            13
----------------------------------------------------------------------------

Comparable income tax expense                           (224)          (159)
Specific items:
NEB decision - 2012                                        -             42
Risk management activities(1)                              3              2
----------------------------------------------------------------------------
Income tax expense                                      (221)          (115)
----------------------------------------------------------------------------

Comparable earnings per common share                   $0.60          $0.52
Specific items (net of tax):
NEB decision - 2012                                        -           0.12
Risk management activities(1)                          (0.02)         (0.01)
----------------------------------------------------------------------------
Net income per common share                            $0.58          $0.63
----------------------------------------------------------------------------
----------------------------------------------------------------------------

    ------------------------------------------------------------------------
    ------------------------------------------------------------------------
                                                    three months ended
(1) Risk management activities                           March 31
                                              ------------------------------
                                              ------------------------------
    (unaudited - millions of $)                         2014           2013
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------

    Canadian Power                                         -             (2)
    U.S. Power                                            (2)             1
    Natural Gas Storage                                   (9)            (3)
    Foreign exchange                                      (2)            (6)
    Income tax attributable to risk management
     activities                                            3              2
    ------------------------------------------------------------------------
    Total losses from risk management
     activities                                          (10)            (8)
    ------------------------------------------------------------------------
    ------------------------------------------------------------------------

Comparable EBITDA and EBIT by business segment

----------------------------------------------------------------------------
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three months ended March
 31, 2014                   Natural Gas      Liquids
(unaudited - millions of $)   Pipelines Pipelines(1) Energy Corporate  Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------

EBITDA                             848          241    334       (38) 1,385
Non-comparable risk
 management activities
 affecting EBITDA                    -            -     11         -     11
----------------------------------------------------------------------------
Comparable EBITDA                  848          241    345       (38) 1,396
Comparable depreciation and
 amortization                     (262)         (49)   (77)       (5)  (393)
----------------------------------------------------------------------------
Comparable EBIT                    586          192    268       (43) 1,003
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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three months ended March
 31, 2013                   Natural Gas      Liquids
(unaudited - millions of $)   Pipelines Pipelines(1) Energy Corporate  Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------

EBITDA                             801          179    273       (34) 1,219
NEB decision - 2012                (55)           -      -         -    (55)
Non-comparable risk
 management activities
 affecting EBITDA                    -            -      4         -      4
----------------------------------------------------------------------------
Comparable EBITDA                  746          179    277       (34) 1,168
Comparable depreciation and
 amortization                     (240)         (37)   (74)       (3)  (354)
----------------------------------------------------------------------------
Comparable EBIT                    506          142    203       (37)   814
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Previously Oil Pipelines.

Results - First quarter 2014

Net income attributable to common shares is comprised of comparable earnings and specific income statement items excluded from comparable earnings. Net income attributable to common shares was $412 million this quarter compared to $446 million in first quarter 2013. The first quarter 2013 results included $84 million of net income related to the 2012 impact of the NEB decision (RH-003-2011). This amount was excluded from comparable earnings. Net income also includes net unrealized after-tax gains or losses resulting from changes in the fair value of certain risk management activities, which are excluded from comparable earnings. For the three months ended March 31, 2014 comparable earnings excluded losses of $10 million ($13 million before tax) compared to losses of $8 million ($10 million before tax) for the same period in 2013 resulting from these risk management activities.

The discussion of segmented results will focus on the remaining aspects of net income through a discussion of comparable earnings.

Comparable earnings this quarter were $52 million higher than first quarter 2013, an increase of $0.08 per share.

This was primarily the net effect of the following:


--  incremental earnings from the Gulf Coast extension of the Keystone
    Pipeline System which was placed in service on January 22, 2014
--  higher equity income from Bruce Power because of higher earnings from
    Bruce B, reflecting lower planned outage days, and higher earnings from
    Bruce A Unit 4, following the completion of the planned life extension
    outage which began in third quarter 2012 and was completed in April 2013
--  higher earnings from U.S. Power mainly because of higher realized
    capacity and power prices
--  higher earnings from U.S. and international pipelines due to higher
    transportation revenue at Great Lakes and higher contributions from TC
    PipeLines, LP reflecting colder weather and increased demand
--  higher OM&A costs at ANR as well as lower storage revenues
--  higher interest expense due to new debt issuances.

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. With the Gulf Coast extension of the Keystone Pipeline System in service in January 2014, our commercially secured growth portfolio now stands at $36 billion. 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 $10 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.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
at March 31, 2014                         Expected    Estimated
(billions of $)                    In-Service Date Project Cost Amount Spent
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Small to medium-sized projects
Tamazunchale Extension                        2014       US 0.6       US 0.5
Ontario Solar                            2014-2015          0.5          0.2
Houston Lateral and Terminal                  2015       US 0.4       US 0.2
Heartland and TC Terminals                    2016          0.9            -
Keystone Hardisty Terminal                    2016          0.3          0.1
Topolobampo                                   2016       US 1.0       US 0.4
Mazatlan                                      2016       US 0.4       US 0.1
Grand Rapids(1)                          2015-2017          1.5          0.1
Northern Courier                              2017          0.8          0.1
NGTL System                              2014-2018          2.2          0.3
Napanee                               2017 or 2018          1.0            -
----------------------------------------------------------------------------
                                                            9.6          2.0
----------------------------------------------------------------------------
Large scale projects(2)
Keystone XL(3)                     Approximately 2
                                             years
                                  from date permit
                                          received       US 5.4       US 2.3
Energy East(4)                                2018         12.0          0.2
Prince Rupert Gas Transmission                2018          5.0          0.2
Coastal GasLink                              2018+          4.0          0.1
----------------------------------------------------------------------------
                                                           26.4          2.8
----------------------------------------------------------------------------
                                                           36.0          4.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents our 50 per cent share.
(2) Subject to cost adjustments due to market conditions, route refinement,
    permitting conditions and scheduling.
(3) Estimated project cost will increase depending on the timing of the
    Presidential permit.
(4) Excludes transfer of Canadian Mainline natural gas assets.

Outlook

The sale of Cancarb Limited and its related power generation facility on April 15, 2014 is expected to result in an after-tax gain of approximately $95 million to our second quarter 2014 earnings. In addition, effective April 30, 2014, we terminated a long-term natural gas storage contract with a third party provider in Alberta, which is expected to result in a charge of approximately $33 million after-tax to our second quarter 2014 earnings.

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

Natural Gas Pipelines

Comparable EBITDA and comparable EBIT are non-GAAP measures. Comparable EBIT is equivalent to our Natural Gas Pipelines segmented earnings after adjusting for $42 million of EBIT in 2013 related to the 2012 impact from the NEB decision (RH-003-2011). See non-GAAP measures section for more information.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $)                             2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Canadian Pipelines
Canadian Mainline                                        315            280
NGTL System                                              219            182
Foothills                                                 27             29
Other Canadian pipelines (TQM(1), Ventures LP)             5              6
----------------------------------------------------------------------------
Canadian Pipelines - comparable EBITDA                   566            497
Comparable depreciation and amortization                (203)          (184)
----------------------------------------------------------------------------
Canadian Pipelines - comparable EBIT                     363            313
----------------------------------------------------------------------------

U.S. and International (US$)
ANR                                                       78             90
TC PipeLines, LP(1,2)                                     26             17
Great Lakes(3)                                            19             10
Other U.S. pipelines (Bison(4), Iroquois(1),
 GTN(4), Portland(5))                                     45             71
Mexico (Guadalajara, Tamazunchale)                        25             26
International and other (Gas
 Pacifico/INNERGY(1), TransGas(1))                        (1)            (2)
Non-controlling interests(6)                              73             43
----------------------------------------------------------------------------
U.S. Pipelines and International - comparable
 EBITDA                                                  265            255
Comparable depreciation and amortization                 (54)           (55)
----------------------------------------------------------------------------
U.S. Pipelines and International - comparable
 EBIT                                                    211            200
Foreign exchange impact                                   21              2
----------------------------------------------------------------------------
U.S. Pipelines and International - comparable
 EBIT (Cdn$)                                             232            202
----------------------------------------------------------------------------
Business Development comparable EBITDA and
 EBIT                                                     (9)            (9)
----------------------------------------------------------------------------
Natural Gas Pipelines - comparable EBIT                  586            506
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Summary
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural Gas Pipelines - comparable EBITDA                848            746
Comparable depreciation and amortization                (262)          (240)
----------------------------------------------------------------------------
Natural Gas Pipelines - comparable EBIT                  586            506
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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, 2013   May 22, 2013 January 1, 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) Comparable EBITDA for the portions of TC PipeLines, LP and Portland we
    do not own.

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES

----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $)                              2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Canadian Mainline - net income                             66            151
Canadian Mainline - comparable earnings                    66             67
NGTL System                                                63             56
Foothills                                                   4              4
----------------------------------------------------------------------------

OPERATING STATISTICS - WHOLLY OWNED PIPELINES


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                           Canadian      NGTL
three months ended March 31              Mainline(1)  System(2)     ANR(3)
                                         ----------- ----------- -----------
                                         ----------- ----------- -----------
(unaudited)                               2014  2013  2014  2013  2014  2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Average investment base (millions of $)  5,706 5,870 6,137 5,824   n/a   n/a
Delivery volumes (Bcf)
Total                                      528   426 1,131   994   525   465
Average per day                            5.9   4.7  12.6  11.0   5.8   5.2
----------------------------------------------------------------------------
(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 three months ended March 31,
    2014 were 357 Bcf (2013 - 231 Bcf). Average per day was 4.0 Bcf (2013 -
    2.6 Bcf).
(2) Field receipt volumes for the NGTL System for the three months ended
    March 31, 2014 were 933 Bcf (2013 - 916 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.

CANADIAN PIPELINES

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

Canadian Mainline's comparable earnings reflect an ROE of 11.50 per cent on deemed common equity of 40 per cent and have decreased by $1 million for the three months ended March 31, 2014 compared to the same period in 2013 because of a lower average investment base. Net income for the three months ended March 31, 2014 was $85 million lower than the same period in 2013 as net income in 2013 included $84 million related to the 2012 impact of the NEB decision (RH-003-2011), which was excluded from comparable earnings.

Net income for the NGTL System increased by $7 million for the three months ended March 31, 2014 compared to the same periods in 2013 primarily due to a higher average investment base as well as an increase in the ROE. The 2013-2014 NGTL Settlement approved by the NEB in November 2013 included an ROE of 10.10 per cent on deemed common equity of 40 per cent. Results for the three months ended March 31, 2013 reflected 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. pipelines operations is generally affected by contracted volume levels, volumes delivered and the rates charged, as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.

Comparable EBITDA for the U.S. and international pipelines increased US$10 million for the three months ended March 31, 2014 compared to the same period in 2013. This was the net effect of:


--  higher transportation revenues at Great Lakes and higher contributions
    from TC PipeLines, LP reflecting colder weather and increased demand
--  higher OM&A costs at ANR as well as lower storage revenues
--  a stronger U.S. dollar which had a positive impact on the Canadian
    dollar equivalent comparable earnings in our U.S. operations.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased $22 million for the three months ended March 31, 2014 compared to the same period in 2013 mainly because of a higher investment base and higher depreciation rates on the NGTL System.

Liquids Pipelines(1)

Comparable EBITDA and comparable EBIT are non-GAAP measures. Comparable EBIT is equivalent to our Liquids Pipelines segmented earnings. See non-GAAP measures section for more information.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $)                             2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Keystone Pipeline System                                 248            186
Liquids Pipelines Business Development                    (7)            (7)
----------------------------------------------------------------------------
Liquids Pipelines - comparable EBITDA                    241            179
Comparable depreciation and amortization                 (49)           (37)
----------------------------------------------------------------------------
Liquids Pipelines - comparable EBIT                      192            142
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable EBIT denominated as follows:
Canadian dollars                                          49             47
U.S. dollars                                             129             94
Foreign exchange impact                                   14              1
----------------------------------------------------------------------------
                                                         192            142
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Previously Oil Pipelines.

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 $62 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase is primarily due to:


--  incremental earnings from the Gulf Coast extension which was placed in
    service on January 22, 2014
--  a stronger U.S. dollar which had a positive impact on the Canadian
    dollar equivalent comparable earnings in our U.S. operations.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $12 million for the three months ended March 31, 2014 compared to the same period in 2013 due to the Gulf Coast extension.

Energy

Comparable EBITDA and comparable EBIT are non-GAAP measures. Comparable EBIT is equivalent to our Energy segmented earnings after adjusting for $11 million (2013 - $4 million) related to unrealized losses on risk management activities. See non-GAAP measures section for more information.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $)                             2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Canadian Power
Western Power                                             72             74
Eastern Power(1)                                          93             90
Bruce Power                                               64             31
----------------------------------------------------------------------------
Canadian Power - comparable EBITDA(2)                    229            195
Comparable depreciation and amortization                 (44)           (43)
----------------------------------------------------------------------------
Canadian Power - comparable EBIT(2)                      185            152
U.S. Power (US$)
U.S. Power - comparable EBITDA                            86             67
Comparable depreciation and amortization                 (27)           (28)
----------------------------------------------------------------------------
U.S. Power - comparable EBIT                              59             39
Foreign exchange impact                                    5              1
----------------------------------------------------------------------------
U.S. Power - comparable EBIT (Cdn$)                       64             40
----------------------------------------------------------------------------
Natural Gas Storage and other
Natural Gas Storage and other - comparable
 EBITDA                                                   27             18
Comparable depreciation and amortization                  (3)            (3)
----------------------------------------------------------------------------
Natural Gas Storage and other - comparable
 EBIT                                                     24             15
Business Development comparable EBITDA and
 EBIT                                                     (5)            (4)
----------------------------------------------------------------------------
Energy - comparable EBIT(2)                              268            203
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Summary
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Energy - comparable EBITDA(2)                            345            277
Comparable depreciation and amortization                 (77)           (74)
----------------------------------------------------------------------------
Energy - comparable EBIT(2)                              268            203
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 increased by $68 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase was the result of:


--  higher equity income from Bruce Power because of higher earnings from
    Bruce B, reflecting lower planned outage days, and higher earnings from
    Bruce A Unit 4, following the completion of the planned life extension
    outage which began in third quarter 2012 and was completed in April 2013
--  higher earnings from U.S. Power mainly because of higher realized
    capacity and power prices
--  higher earnings from natural gas storage mainly due to increased
    proprietary revenues, partially offset by decreased third party storage
    revenues.

CANADIAN POWER

Western and Eastern Power(1)

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                                 ---------------------------
                                                 ---------------------------
(unaudited - millions of $)                             2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenue
Western Power                                            181            142
Eastern Power(1)                                         142            109
Other(2)                                                  51             31
----------------------------------------------------------------------------
                                                         374            282
Income from equity investments(3)                         20             22
Commodity purchases resold                              (101)           (67)
Plant operating costs and other                         (128)           (73)
----------------------------------------------------------------------------
Comparable EBITDA                                        165            164
Comparable depreciation and amortization                 (44)           (43)
----------------------------------------------------------------------------
Comparable EBIT                                          121            121
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Breakdown of comparable EBITDA
Western Power                                             72             74
Eastern Power                                             93             90
----------------------------------------------------------------------------
Comparable EBITDA                                        165            164
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes four Ontario solar facilities acquired between June and
    December 2013.
(2) Includes sale of excess natural gas purchased for generation and sales
    of thermal carbon black.
(3) Includes our share of equity income from our investments in ASTC Power
    Partnership, which holds the Sundance B PPA, and Portlands Energy.

Sales volumes and plant availability

Includes our share of volumes from our equity investments.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited)                                             2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Sales volumes (GWh)
Supply
  Generation
    Western Power                                        609            670
    Eastern Power(1)                                   1,277          1,346
  Purchased
    Sundance A & B and Sheerness PPAs(2)               2,800          1,707
    Other purchases                                        5              -
----------------------------------------------------------------------------
                                                       4,691          3,723
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales
  Contracted
    Western Power                                      2,461          1,707
    Eastern Power(1)                                   1,277          1,346
  Spot
    Western Power                                        953            670
----------------------------------------------------------------------------
                                                       4,691          3,723
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Plant availability(3)
Western Power(4)                                          96%            97%
Eastern Power(1,5)                                        98%            96%
----------------------------------------------------------------------------
(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 $2 million for the three months ended March 31, 2014 compared to the same period 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 3 per cent to $62/MWh for the three months ended March 31, 2014 compared to the same period in 2013. 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.

72 per cent of Western Power sales volumes were sold under contract in first quarter 2014 and 2013.

Eastern Power

Eastern Power's comparable EBITDA increased by $3 million for the three months ended March 31, 2014 compared to the same period in 2013 mainly due to the incremental earnings from the Ontario solar facilities acquired in 2013.

BRUCE POWER

Our proportionate share


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $ unless noted
 otherwise)                                             2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Income/(loss) from equity investments(1)
Bruce A                                                   49             36
Bruce B                                                   15             (5)
----------------------------------------------------------------------------
                                                          64             31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comprised of:
  Revenues                                               300            287
  Operating expenses                                    (157)          (173)
  Depreciation and other                                 (79)           (83)
----------------------------------------------------------------------------
                                                          64             31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bruce Power - Other information
Plant availability(2)
  Bruce A                                                 80%            66%
  Bruce B                                                 85%            78%
  Combined Bruce Power                                    83%            72%
Planned outage days
  Bruce A                                                  -             90
  Bruce B                                                 49             70
Unplanned outage days
  Bruce A                                                 60              8
  Bruce B                                                  -              9
Sales volumes (GWh)(1)
  Bruce A                                              2,527          2,097
  Bruce B                                              1,924          1,735
----------------------------------------------------------------------------
                                                       4,451          3,832
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized sales price per MWh(3)
  Bruce A                                                $71            $68
  Bruce B                                                $56            $53
  Combined Bruce Power                                   $63            $59
----------------------------------------------------------------------------
(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 increased by $13 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase was mainly a result of 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. The increase was partially offset by:


--  lower volumes from Units 1 and 2 due to higher unplanned outage days
--  the impact of an insurance recovery of approximately $40 million
    recognized in first quarter 2013.

Equity income from Bruce B increased by $20 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase was mainly due to higher volumes and lower operating costs resulting from lower 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/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 monthly average spot price exceeds the floor price. Although the first quarter 2014 average spot price exceeded the floor price, spot prices are expected to fall below the floor price for the remainder of 2014. As a result, amounts received above the floor price in first quarter 2014 are not expected to be realized under the Bruce B floor price mechanism and therefore, have not been reflected in equity income.

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 mid 80s for Bruce A and high 80s for Bruce B. Planned maintenance on a Bruce A unit will occur in second quarter 2014. Planned maintenance on one of the Bruce B units is scheduled to occur in fourth quarter 2014.

U.S. POWER

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of US $)                          2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenue
Power(1)                                                 745            462
Capacity                                                  70             47
----------------------------------------------------------------------------
                                                         815            509
Commodity purchases resold                              (549)          (306)
Plant operating costs and other(2)                      (180)          (136)
----------------------------------------------------------------------------
Comparable EBITDA                                         86             67
Comparable depreciation and amortization                 (27)           (28)
----------------------------------------------------------------------------
Comparable EBIT                                           59             39
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The realized gains and losses from financial derivatives used to buy and
    sell power, natural gas and fuel oil to manage U.S. Power's assets are
    presented on a net basis in power revenues.
(2) Includes the cost of fuel consumed in generation.

Sales volumes and plant availability


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited)                                             2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Physical sales volumes (GWh)
Supply
  Generation                                           1,238          1,051
  Purchased                                            2,829          2,479
----------------------------------------------------------------------------
                                                       4,067          3,530
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Plant availability(1)                                     85%            79%
----------------------------------------------------------------------------
(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$19 million for the three months ended March 31, 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 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
--  a stronger U.S. dollar which had a positive impact on the Canadian
    dollar equivalent comparable earnings in our U.S. operations.

Wholesale electricity prices in New York and New England were significantly higher for the three months ended March 31, 2014 compared to the same period in 2013. Average spot power prices for the Western/Central Massachusetts load zone in New England increased 75 per cent to $143/MWh and in New York City spot power prices increased 78 per cent to an average of $126/MWh. Colder winter temperatures compared to the same period in 2013 and gas transmission constraints resulted in higher natural gas prices in the predominantly gas-fired New England and New York power markets for the three months ended March 31, 2014.

Spot capacity prices in New York City were 102 per cent higher in first quarter 2014 compared to the same period in 2013. This increase in spot capacity prices and the impact of hedging activities resulted in higher realized capacity prices in New York.

Physical sales volumes for the three months ended March 31, 2014 were higher than the same period in 2013 due to higher purchased volumes sold to wholesale, commercial and industrial customers in our PJM markets and higher generation at our Ravenswood facility in New York.

As at March 31, 2014, approximately 5,300 GWh or 63 per cent of U.S. Power's planned generation is contracted for the remainder of 2014, and 3,200 GWh or 38 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 increased $9 million for the three months ended March 31, 2014 compared to the same period in 2013 primarily due to increased proprietary revenues 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 Pipelines

NGTL System

The NEB has approved $400 million in NGTL facility expansions that were in various stages of development or construction at March 31, 2014. In addition, we have approximately $1.8 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.

On February 5, 2014, we received a Hearing Order for the 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 hearing will begin August 19, 2014 with a second portion beginning September 8, 2014. The proposed project consists of approximately 300 km (186 miles) of pipeline.

On March 5, 2014, we received an NEB Safety Order in response to the 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. On April 14, 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 as reviewed and varied.

Canadian Mainline

LDC Settlement

On March 31, 2014, the NEB responded to the LDC Settlement application we filed on December 20, 2013. The NEB did not approve the application but provided direction that we can continue with the application as a contested tolls application, amend the application or terminate the processing of the application. We will be amending the application with additional information in second quarter 2014. On April 22, 2014, the NEB issued a notice advising that it will hold a public hearing on the amended application and setting the list of issues. A further letter from the NEB setting out the hearing process and schedule is expected in the next few weeks.

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 activity on the US$600 million extension continues. The extension is currently expected to be in service at the end of July 2014.

LNG Pipeline Projects

Coastal GasLink

In January 2014, we filed the Application for an Environmental Assessment Certificate with the B.C. Environmental Assessment Office. The 180-day Environmental Assessment Office public review period began in March 2014 and includes a 45-day public comment period. In addition, the B.C. Oil and Gas Commission application was filed in March 2014, together with an addendum to the B.C. Environmental Assessment application to capture recent route refinements.

Prince Rupert Gas Transmission

The project completed two key milestones in April 2014. The Environmental Assessment application was submitted to the B.C. Environmental Assessment Office for a completeness review and the application was filed with the B.C. Oil and Gas Commission.

Alaska

In April 2014, the State of Alaska passed new legislation that will transition from the Alaska Gasline Inducement Act 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. It is anticipated that two years of pre-front end engineering will be completed before further decisions to commercialize the project will be made.

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. We are projecting an average pipeline capacity of 520,000 Bbl/d for the first year of operation.

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 the National Interest Determination period has been extended indefinitely. The DOS has said only that the permit process will conclude once factors that have a significant impact on determining national interest of the proposed project have been evaluated.

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. We disagree with the decision of the Nebraska district court and are continuing to analyze the judgment and decide what next steps may be taken. Nebraska's Attorney General has filed an appeal and the Nebraska Supreme Court is expected to hear the appeal in third quarter 2014. As of March 31, 2014, we have invested US$2.3 billion in the Keystone XL project.

Energy East Pipeline

On March 4, 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 mid-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 mile) 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.

ENERGY

Ontario Solar

We expect the acquisition of four additional Ontario solar generation facilities to close in fourth quarter 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.

Cancarb Limited and Cancarb Waste Heat Facility

On January 20, 2014, we announced we had reached an agreement for the sale of Cancarb Limited, our thermal carbon black business, and its related power generation facility. The sale closed on April 15, 2014 for proceeds of $190 million, subject to closing adjustments. We expect to realize a gain on the sale of approximately $95 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. In consideration for this termination, we expect to record an after-tax charge of approximately $33 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.

Other income statement items


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                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $)                             2014           2013
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Comparable interest expense                              274            257
Comparable interest income and other                       6            (18)
Comparable income tax expense                            224            159
Net income attributable to non-controlling
 interests                                                54             31
Preferred share dividends                                 23             15
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                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $)                             2014           2013
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Comparable interest on long-term debt
 (including interest on junior subordinated
 notes)
Canadian dollar-denominated                              114            122
U.S. dollar-denominated (US$)                            207            188
Foreign exchange impact                                   22              1
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                                                         343            311
Other interest and amortization expense                   10              1
Capitalized interest                                     (79)           (55)
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Comparable interest expense                              274            257
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Comparable interest expense increased $17 million for the three months ended March 31, 2014 compared to the same period in 2013 because of the net effect 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$750 million in January 2013
    --  US$500 million in July 2013 by TC PipeLines, LP
--  higher capitalized interest primarily for the Keystone XL project,
    Mexican projects and other liquids and LNG pipeline projects partially
    offset by the Gulf Coast extension of the Keystone Pipeline System,
    which was placed in service in first quarter 2014
--  higher foreign exchange on interest expense related to U.S. denominated
    debt, partially offset by Canadian and U.S. dollar-denominated debt
    maturities.

Comparable interest income and other decreased $24 million for the three months ended March 31, 2014 compared to the same period in 2013 reflecting 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.

Comparable income tax expense increased $65 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase was mainly the result of higher pre-tax earnings in 2014, compared to 2013, combined with 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.

Net income attributable to non-controlling interests increased $23 million for the three months ended March 31, 2014 compared to the same period in 2013 primarily due to the sale of a 45 per cent interest in each of GTN LLC and Bison to TC PipeLines, LP in July 2013.

Preferred share dividends increased $8 million for the three months ended March 31, 2014, compared to the same period 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


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                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $)                             2014           2013
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Funds generated from operations(1)                     1,102            916
Increase in operating working capital                   (123)          (210)
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Net cash provided by operations                          979            706
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(1) See the non-GAAP measures section in this MD&A for further discussion of
    funds generated from operations.

Net cash provided by operations was $979 million for the three months ended March 31, 2014 compared to $706 million for the same period in 2013 mainly due to higher earnings in each of our operating segments and higher distributions from equity investments.

At March 31, 2014, our current assets were $3.5 billion and current liabilities were $5.1 billion, leaving us with a working capital deficit of $1.6 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 INVESTING ACTIVITIES


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                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $)                              2014           2013
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Capital expenditures                                      778            929
Equity investments                                         89             32
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Our capital expenditures this quarter were primarily related to the Gulf Coast extension of the Keystone Pipeline System, expansion of the NGTL System and construction of the Mexican pipelines.

Our cash used in equity investments increased this quarter due to our investment in the Grand Rapids Pipeline.

CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES


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                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $)                             2014           2013
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Long-term debt issued, net of issue costs              1,364            734
Long-term debt repaid                                   (777)           (14)
Notes payable repaid, net                               (747)          (829)
Dividends and distributions paid                        (390)          (350)
Common shares issued, net of issue costs                  10             32
Preferred shares issued, net of issue costs              440            586
Preferred shares of subsidiary redeemed                 (200)             -
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LONG-TERM DEBT ISSUED

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Amount
(unaudited -                                          Interest
millions of $)      Type                Maturity date     rate   Date issued
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                    Senior unsecured
US$1,250            notes               March 1, 2034   4.625% February 2014
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LONG-TERM DEBT RETIRED

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Amount                                                              Interest
(unaudited - millions of $)  Type                Retirement date        rate
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$450                         Medium term notes      January 2014       5.65%
$300                         Medium term notes     February 2014       5.05%
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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 May 1, 2014, we declared quarterly dividends as follows:


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Quarterly dividend on our common shares
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$0.48 per share
Payable on July 30, 2014 to shareholders of record at the close of business
 on June 30, 2014
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Quarterly dividends on our preferred shares
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Series 1  $0.2875
Series 3  $0.25
Payable on June 30, 2014 to shareholders of record at the close of business
 on June 2, 2014
Series 5  $0.275
Series 7  $0.25
Series 9  $0.266
Payable on July 30, 2014 to shareholders of record at the close of business
 on June 30, 2014
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SHARE INFORMATION

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April 28, 2014
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Common shares             Issued and
                         outstanding
                         708 million
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Preferred                 Issued and                          Convertible to
shares                   outstanding
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
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Options to buy
common shares            Outstanding                             Exercisable
                           9 million                               5 million
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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 March 31, 2014, we had $6 billion in unsecured credit facilities, including:


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Amount    Unused    Subsidiary        For                 Matures
          capacity
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$3.0      $3.0      TCPL              Committed,          December 2018
billion   billion                     syndicated,
                                      revolving,
                                      extendible credit
                                      facility that
                                      supports TCPL's
                                      Canadian commercial
                                      paper program
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US$1.0    US$1.0    TCPL USA          Committed,          November 2014
billion   billion                     syndicated,
                                      revolving,
                                      extendible credit
                                      facility that is
                                      used for TCPL USA
                                      general corporate
                                      purposes
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US$1.0    US$1.0    TransCanada       Committed,          November 2014
billion   billion   American          syndicated,
                    Investments Ltd.  revolving,
                    (TAIL)            extendible credit
                                      facility that
                                      supports the TAIL
                                      U.S. dollar
                                      commercial paper
                                      program in the U.S.
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$1.1      $0.3      TCPL,             Demand lines for    Demand
billion   billion   TCPL USA          issuing letters of
                                      credit and as a
                                      source of additional
                                      liquidity. At March
                                      31, 2014, we had
                                      $0.7 billion
                                      outstanding in
                                      letters of credit
                                      under these lines
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See Financial risks and financial instruments for more information about liquidity, market and other risks.

CONTRACTUAL OBLIGATIONS

Our capital commitments have decreased by $522 million since December 31, 2013, primarily due to the completion or advancement of capital projects. There were no other material changes to our contractual obligations in first 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 March 31, 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 $220 million with one counterparty at March 31, 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 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


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First quarter 2014                                                      1.11
First quarter 2013                                                      1.01
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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. Comparable EBIT is a non-GAAP measure.

Significant U.S. dollar-denominated amounts


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                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of US$)                           2014           2013
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U.S. and International Natural Gas Pipelines
 comparable EBIT                                         211            200
U.S. Liquids Pipelines comparable EBIT                   129             94
U.S. Power comparable EBIT                                59             39
Interest expense on U.S. dollar-denominated
 long-term debt                                         (207)          (188)
Capitalized interest on U.S. capital
 expenditures                                             52             44
U.S. non-controlling interests and other                 (79)           (48)
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                                                         165            141
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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:


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                                   March 31, 2014        December 31, 2013
                               ---------------------- ----------------------
                               ---------------------- ----------------------
                                          Notional or            Notional or
                                     Fair   principal       Fair   principal
(unaudited - millions of $)      value(1)      amount   value(1)      amount
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Asset/(liability)
U.S. dollar cross-currency
 swaps
(maturing 2014 to 2019)(2)          (326)    US 3,550      (201)    US 3,800
U.S. dollar foreign exchange
 forward contracts
(maturing 2014)                      (17)    US 1,000       (11)      US 850
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                                    (343)    US 4,550      (212)    US 4,650
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(1) Fair values equal carrying values.
(2) Net Income in the three months ended March 31, 2014 included net
    realized gains of $6 million (2013 - gains of $7 million) related to the
    interest component of cross-currency swap settlements.

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


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(unaudited - millions of $)               March 31, 2014   December 31, 2013
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Carrying value                        16,200 (US 14,600)  14,200 (US 13,400)
Fair value                            18,500 (US 16,700)  16,000 (US 15,000)
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The balance sheet classification of the fair value of derivatives used to hedge our net investment in foreign operations is as follows:


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(unaudited - millions of $)                 March 31, 2014 December 31, 2013
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Other current assets                                    5                 5
Intangible and other assets                             1                 -
Accounts payable and other                            (93)              (50)
Other long-term liabilities                          (256)             (167)
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                                                     (343)             (212)
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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 purchases and normal sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.

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, intangibles 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 Other comprehensive income (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 the 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:


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(unaudited - millions of $)                 March 31, 2014 December 31, 2013
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Other current assets                                  364               395
Intangible and other assets                           100               112
Accounts payable and other                           (434)             (357)
Other long-term liabilities                          (341)             (255)
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                                                     (311)             (105)
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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.


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                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $, pre-tax)                    2014           2013
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Derivative instruments held for trading(1)
Amount of unrealized gains/(losses) in the
 period
  Power                                                    9             (8)
  Natural gas                                             (7)             9
  Foreign exchange                                        (2)            (6)
Amount of realized (losses)/gains in the
 period
  Power                                                  (28)            (7)
  Natural gas                                             50             (2)
  Foreign exchange                                       (17)            (1)
Derivative instruments in hedging
 relationships(2,3)
Amount of realized gains in the period
  Power                                                  192             73
  Interest                                                 1              2
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(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 March 31, 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 $6 million (2013 -
    $10 million) and a notional amount of US$300 million (2013 - US$350
    million). For the three months ended March 31, 2014, net realized gains
    on fair value hedges were $1 million (2013 - $2 million) and were
    included in interest expense. For the three months ended March 31, 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 months ended March 31, 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:


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                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of $, pre-tax)                    2014           2013
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Change in fair value of derivative instruments
 recognized in OCI (effective portion)
  Power                                                   41             36
  Foreign Exchange                                        10              2
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                                                          51             38
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Reclassification of (losses)/gains on
 derivative instruments from AOCI to net
 income (effective portion)
  Power                                                 (108)           (11)
  Interest                                                 5              4
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                                                        (103)            (7)
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Losses on derivative instruments recognized in
 earnings (ineffective portion)
  Power                                                  (13)            (5)
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                                                         (13)            (5)
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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 March 31, 2014, the aggregate fair value of all derivative contracts with credit risk related contingent features that were in a net liability position was $19 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 March 31, 2014, we would have been required to provide collateral of $19 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 March 31, 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 first 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.

QUARTERLY RESULTS

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA


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                      2014              2013                    2012
                     ------ --------------------------- --------------------
                     ------ --------------------------- --------------------
(unaudited - millions
 of $, except per
 share amounts)       First Fourth  Third  Second First Fourth  Third Second
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenues              2,884  2,332  2,204  2,009  2,252  2,089  2,126  1,847
Net income
 attributable to
 common shares          412    420    481    365    446    306    369    272
Comparable earnings     422    410    447    357    370    318    349    300
Comparable earnings
 per share            $0.60  $0.58  $0.63  $0.51  $0.52  $0.45  $0.50  $0.43
Share statistics
  Net Income per
   common share -
   basic and diluted  $0.58  $0.59  $0.68  $0.52  $0.63  $0.43  $0.52  $0.39
  Dividends declared
   per common share   $0.48  $0.46  $0.46  $0.46  $0.46  $0.44  $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 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).

In second quarter 2012, comparable earnings excluded a $15 million after-tax charge ($20 million pre-tax) from the Sundance A PPA arbitration decision.


                 Condensed consolidated statement of income

----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                    three months ended
                                                         March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of Canadian $ except per
 share amounts)                                          2014          2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenues
Natural gas pipelines                                   1,215         1,157
Liquids pipelines                                         359           271
Energy                                                  1,310           824
----------------------------------------------------------------------------
                                                        2,884         2,252
Income from Equity Investments                            135            93
Operating and Other Expenses
Plant operating costs and other                           805           641
Commodity purchases resold                                706           376
Property taxes                                            123           109
Depreciation and amortization                             393           367
----------------------------------------------------------------------------
                                                        2,027         1,493
----------------------------------------------------------------------------
Financial Charges/(Income)
Interest expense                                          274           258
Interest income and other                                   8           (13)
----------------------------------------------------------------------------
                                                          282           245
----------------------------------------------------------------------------
Income before Income Taxes                                710           607
----------------------------------------------------------------------------
Income Tax Expense
Current                                                    59            79
Deferred                                                  162            36
----------------------------------------------------------------------------
                                                          221           115
----------------------------------------------------------------------------
Net Income                                                489           492
Net income attributable to non-controlling
 interests                                                 54            31
----------------------------------------------------------------------------
Net Income Attributable to Controlling
 Interests                                                435           461
Preferred share dividends                                  23            15
----------------------------------------------------------------------------
Net Income Attributable to Common Shares                  412           446
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net Income per Common Share
Basic and diluted                                       $0.58         $0.63
----------------------------------------------------------------------------
Dividends Declared per Common Share                     $0.48         $0.46
----------------------------------------------------------------------------
Weighted Average Number of Common Shares
 (millions)
Basic                                                     708           706
Diluted                                                   708           707
----------------------------------------------------------------------------

See accompanying notes to the condensed consolidated financial statements.

          Condensed consolidated statement of comprehensive income

----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                    three months ended
                                                         March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of Canadian $)                    2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net Income                                               489            492
----------------------------------------------------------------------------
Other Comprehensive Income, Net of Income
 Taxes
Foreign currency translation gains and losses
 on net investment in foreign operations                 240            111
Change in fair value of net investment hedges           (127)           (49)
Change in fair value of cash flow hedges                  31             21
Reclassification to Net Income of gains and
 losses on cash flow hedges                              (62)            (4)
Reclassification to Net Income of actuarial
 gains and losses and prior service costs on
 pension and other post-retirement benefit
 plans                                                     4              6
Other comprehensive loss on equity investments             -             (1)
----------------------------------------------------------------------------
Other comprehensive income (Note 7)                       86             84
----------------------------------------------------------------------------
Comprehensive Income                                     575            576
Comprehensive income attributable to non-
 controlling interests                                    98             51
----------------------------------------------------------------------------
Comprehensive Income Attributable to
 Controlling Interests                                   477            525
Preferred share dividends                                 25             15
----------------------------------------------------------------------------
Comprehensive Income Attributable to Common
 Shares                                                  452            510
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the condensed consolidated financial statements.

               Condensed consolidated statement of cash flows

----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                    three months ended
                                                         March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of Canadian $)                    2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash Generated from Operations
Net income                                               489            492
Depreciation and amortization                            393            367
Deferred income taxes                                    162             36
Income from equity investments                          (135)           (93)
Distributed earnings received from equity
 investments                                             170             84
Employee post-retirement benefits funding
 lower than expense                                       10             15
Other                                                     13             15
Increase in operating working capital                   (123)          (210)
----------------------------------------------------------------------------
Net cash provided by operations                          979            706
----------------------------------------------------------------------------
Investing Activities
Capital expenditures                                    (778)          (929)
Equity investments                                       (89)           (32)
Deferred amounts and other                               (23)           (20)
----------------------------------------------------------------------------
Net cash used in investing activities                   (890)          (981)
----------------------------------------------------------------------------
Financing Activities
Dividends on common and preferred shares                (345)          (315)
Distributions paid to non-controlling
 interests                                               (45)           (35)
Notes payable repaid, net                               (747)          (829)
Long-term debt issued, net of issue costs              1,364            734
Repayment of long-term debt                             (777)           (14)
Common shares issued, net of issue costs                  10             32
Preferred shares issued, net of issue costs              440            586
Preferred shares of subsidiary redeemed                 (200)             -
----------------------------------------------------------------------------
Net cash (used in)/provided by financing
 activities                                             (300)           159
----------------------------------------------------------------------------
Effect of Foreign Exchange Rate Changes on
 Cash and Cash Equivalents                                33              8
----------------------------------------------------------------------------
Decrease in Cash and Cash Equivalents                   (178)          (108)
----------------------------------------------------------------------------
Cash and Cash Equivalents
Beginning of period                                      927            551
----------------------------------------------------------------------------
Cash and Cash Equivalents
End of period                                            749            443
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the condensed consolidated financial statements.

                    Condensed consolidated balance sheet

----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                     March 31    December 31
(unaudited - millions of Canadian $)                    2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

ASSETS
Current Assets
Cash and cash equivalents                                749            927
Accounts receivable                                    1,517          1,122
Inventories                                              236            251
Other                                                    962            847
----------------------------------------------------------------------------
                                                       3,464          3,147
Plant, Property and Equipment, net of
 accumulated depreciation of $18,349 and
 $17,851, respectively                                38,625         37,606
Equity Investments                                     5,800          5,759
Regulatory Assets                                      1,705          1,735
Goodwill                                               3,842          3,696
Intangible and Other Assets                            2,058          1,955
----------------------------------------------------------------------------
                                                      55,494         53,898
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current Liabilities
Notes payable                                          1,137          1,842
Accounts payable and other                             2,431          2,155
Accrued interest                                         379            388
Current portion of long-term debt                      1,109            973
----------------------------------------------------------------------------
                                                       5,056          5,358
Regulatory Liabilities                                   221            229
Other Long-Term Liabilities                              746            656
Deferred Income Tax Liabilities                        4,808          4,564
Long-Term Debt                                        22,997         21,892
Junior Subordinated Notes                              1,105          1,063
----------------------------------------------------------------------------
                                                      34,933         33,762
EQUITY
Common shares, no par value                           12,161         12,149
Issued and outstanding:     March 31, 2014 -
                             708 million
                             shares
                            December 31, 2013
                             - 707 million
                             shares
Preferred shares                                       2,255          1,813
Additional paid-in capital                               396            401
Retained earnings                                      5,167          5,096
Accumulated other comprehensive loss (Note 7)           (892)          (934)
----------------------------------------------------------------------------
Controlling Interests                                 19,087         18,525
Non-controlling interests                              1,474          1,611
----------------------------------------------------------------------------
                                                      20,561         20,136
----------------------------------------------------------------------------
                                                      55,494         53,898
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contingencies and Guarantees (Note 10)
Subsequent Events (Note 11)

See accompanying notes to the condensed consolidated financial statements.

                 Condensed consolidated statement of equity

----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                    three months ended
                                                         March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of Canadian $)                    2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Common Shares
Balance at beginning of period                        12,149         12,069
Shares issued on exercise of stock options                12             37
----------------------------------------------------------------------------
Balance at end of period                              12,161         12,106
----------------------------------------------------------------------------
Preferred Shares
Balance at beginning of period                         1,813          1,224
Shares issued under public offering, net of
 issue costs                                             442            586
----------------------------------------------------------------------------
Balance at end of period                               2,255          1,810
----------------------------------------------------------------------------
Additional Paid-In Capital
Balance at beginning of period                           401            379
Exercise of stock options, net of issuances                1             (3)
Redemption of subsidiary's preferred shares               (6)             -
----------------------------------------------------------------------------
Balance at end of period                                 396            376
----------------------------------------------------------------------------
Retained Earnings
Balance at beginning of period                         5,096          4,687
Net income attributable to controlling
 interests                                               435            461
Common share dividends                                  (339)          (324)
Preferred share dividends                                (25)           (15)
----------------------------------------------------------------------------
Balance at end of period                               5,167          4,809
----------------------------------------------------------------------------
Accumulated Other Comprehensive Loss
Balance at beginning of period                          (934)        (1,448)
Other comprehensive income                                42             64
----------------------------------------------------------------------------
Balance at end of period                                (892)        (1,384)
----------------------------------------------------------------------------
Equity Attributable to Controlling Interests          19,087         17,717
----------------------------------------------------------------------------
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                                        45             19
  Preferred share dividends of TCPL                        2              6
  Portland                                                 7              6
Other comprehensive income attributable to
 non-controlling interests                                44             20
Distributions to non-controlling interests               (51)           (35)
Redemption of subsidiary's preferred shares             (194)             -
Foreign exchange and other                                10              3
----------------------------------------------------------------------------
Balance at end of period                               1,474          1,444
----------------------------------------------------------------------------
Total Equity                                          20,561         19,161
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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.

3. Segmented information


----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months
 ended March    Natural Gas    Liquids
 31              Pipelines  Pipelines(1)    Energy    Corporate     Total
               ------------ ------------ ----------- ---------- ------------
               ------------ ------------ ----------- ---------- ------------
(unaudited -
 millions of
 Canadian $)    2014  2013   2014  2013   2014 2013  2014 2013   2014  2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenues       1,215 1,157    359   271  1,310  824     -    -  2,884 2,252
Income from
 equity
 investments      52    40      -     -     83   53     -    -    135    93
Plant
 operating
 costs and
 other          (333) (318)  (101)  (79)  (333)(210)  (38) (34)  (805) (641)
Commodity
 purchases
 resold            -     -      -     -   (706)(376)    -    -   (706) (376)
Property taxes   (86)  (78)   (17)  (13)   (20) (18)    -    -   (123) (109)
Depreciation
 and
 amortization   (262) (253)   (49)  (37)   (77) (74)   (5)  (3)  (393) (367)
----------------------------------------------------------------------------
Segmented
 earnings        586   548    192   142    257  199   (43) (37)   992   852
---------------------------------------------------------------
---------------------------------------------------------------
Interest
 expense                                                         (274) (258)
Interest income and other                                          (8)   13
----------------------------------------------------------------------------
Income before income taxes                                        710   607
Income tax expense                                               (221) (115)
----------------------------------------------------------------------------
Net income                                                        489   492
Net income attributable to non-controlling interests              (54)  (31)
----------------------------------------------------------------------------
Net income attributable to controlling interests                  435   461
Preferred share dividends                                         (23)  (15)
----------------------------------------------------------------------------
Net income attributable to common shares                          412   446
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Previously Oil Pipelines.

TOTAL ASSETS

----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of Canadian $)        March 31, 2014 December 31, 2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Natural Gas Pipelines                               25,765            25,165
Liquids Pipelines(1)                                14,047            13,253
Energy                                              13,954            13,747
Corporate                                            1,728             1,733
----------------------------------------------------------------------------
                                                    55,494            53,898
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Previously Oil Pipelines.

4. Income taxes

At March 31, 2014, the total unrecognized tax benefit of uncertain tax positions was approximately $24 million (December 31, 2013 - $23 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. There is $1 million of interest expense and nil for penalties included in net tax expense for the three months ended March 31, 2014 (March 31, 2013 - $1 million and nil for penalties). At March 31, 2014, the Company had $7 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 three-month periods ended March 31, 2014 and 2013 were 31 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) and changes in the proportion of income earned between Canadian and foreign jurisdictions in 2014 as well as higher flow-through taxes in 2014 on Canadian regulated pipelines.

5. Long-term debt

In the three months ended March 31, 2014, TransCanada capitalized interest related to capital projects of $79 million (March 31, 2013 - $55 million).

LONG-TERM DEBT ISSUED


----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
(unaudited -                                        Interest
millions of $)     Type              Maturity date      rate     Date issued
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                   Senior
US$1,250           unsecured notes   March 1, 2034     4.63%   February 2014
----------------------------------------------------------------------------

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

LONG-TERM DEBT RETIRED


----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
(unaudited -
 millions of                                                        Interest
 Canadian $)         Type                    Retirement date            rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$450                 Medium term notes          January 2014           5.65%
$300                 Medium term notes         February 2014           5.05%
----------------------------------------------------------------------------

6. 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.

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

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                     Income tax
three months ended March 31, 2014       Before tax    recovery/   Net of tax
(unaudited - millions of Canadian $)        amount    (expense)       amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Foreign currency translation gains
 and losses on net investment in
 foreign operations                           191           49          240
Change in fair value of net
 investment hedges                           (171)          44         (127)
Change in fair value of cash flow
 hedges                                        51          (20)          31
Reclassification to net income of
 gains and losses on cash flow hedges        (103)          41          (62)
Reclassification to net income of
 actuarial gains and losses and prior
 service costs on pension and other
 post-retirement benefit plans                  6           (2)           4
----------------------------------------------------------------------------
Other comprehensive (loss)/income             (26)         112           86
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                     Income tax
three months ended March 31, 2013       Before tax    recovery/   Net of tax
(unaudited - millions of Canadian $)        amount    (expense)       amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Foreign currency translation gains
 and losses on net investment in
 foreign operations                            77           34          111
Change in fair value of net
 investment hedges                            (66)          17          (49)
Change in fair value of cash flow
 hedges                                        38          (17)          21
Reclassification to net income of
 gains and losses on cash flow hedges          (7)           3           (4)
Reclassification to net income of
 actuarial gains and losses and prior
 service costs on pension and other
 post-retirement benefit plans                 10           (4)           6
Other comprehensive loss on equity
 investments                                   (1)           -           (1)
----------------------------------------------------------------------------
Other comprehensive income                     51           33           84
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended
 March 31, 2014
(unaudited -              Currency    Cash  Pension and
 millions of           translation    flow    OPEB plan      Equity
 Canadian $)           adjustments  hedges  adjustments Investments Total(1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

AOCI balance at
 January 1, 2014             (629)     (4)        (197)       (104)   (934)
Other comprehensive
 income before
 reclassifications(
 2)                            69      31            -           -     100
Amounts
 reclassified from
 accumulated other
 comprehensive
 loss(3)                        -     (62)           4           -     (58)
----------------------------------------------------------------------------
Net current period
 other
 comprehensive
 income/(loss)                 69     (31)           4           -      42
----------------------------------------------------------------------------
AOCI balance at
 March 31, 2014              (560)    (35)        (193)       (104)   (892)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 gains of $44
    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 $34
    million ($21 million, net of tax) at March 31, 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  Affected line item
three months ended March 31, 2014           other  in the condensed
(unaudited - millions of Canadian   comprehensive  consolidated
 $)                                       loss(1)  statement of income
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash flow hedges
Power                                        108   Revenue (Energy)
Interest                                      (5)  Interest expense
----------------------------------------------------------------------------
                                             103   Total before tax
                                             (41)  Income tax expense
----------------------------------------------------------------------------
                                              62   Net of tax
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Pension and other post-retirement
 plan adjustments
Amortization of actuarial loss and
 past service cost(2)                         (6)  Total before tax
                                               2   Income tax expense
----------------------------------------------------------------------------
                                              (4)  Net of tax
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) All amounts in parentheses indicate expenses to the condensed
    consolidated statement of income.
(2) These accumulated other comprehensive loss components are included in
    the computation of net benefit cost. Refer to Note 8 for additional
    detail.

8. Employee post-retirement benefits

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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                        three months ended March 31
                               ---------------------------------------------
                               ---------------------------------------------
                                                      Other post-retirement
                               Pension benefit plans      benefit plans
                               --------------------- -----------------------
                               --------------------- -----------------------
(unaudited - millions of
 Canadian $)                        2014       2013        2014        2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Service cost                          22         19           1           1
Interest cost                         28         24           2           2
Expected return on plan assets       (35)       (29)          -           -
Amortization of actuarial loss         5          9           1           1
Amortization of regulatory
 asset                                 5          7           -           -
----------------------------------------------------------------------------
Net benefit cost recognized           25         30           4           4
----------------------------------------------------------------------------
----------------------------------------------------------------------------

9. 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 March 31, 2014, there were no significant amounts past due or impaired, and there were no significant credit losses during the period.

At March 31, 2014, the Company had a credit risk concentration of $220 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 $)      March 31, 2014   December 31, 2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Carrying value                        16,200 (US 14,600)  14,200 (US 13,400)
Fair value                            18,500 (US 16,700)  16,000 (US 15,000)
----------------------------------------------------------------------------

Derivatives designated as a net investment hedge

----------------------------------------------------------------------------
----------------------------------------------------------------------------
                               March 31, 2014          December 31, 2013
                         ------------------------- -------------------------
                         ------------------------- -------------------------
                                       Notional or               Notional or
(unaudited - millions of         Fair    principal         Fair    principal
 Canadian $)                 Value(1)       amount     value(1)       amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Asset/(liability)
U.S. dollar cross-
 currency interest rate
 swaps
(maturing 2014 to
 2019)(2)                       (326)     US 3,550        (201)     US 3,800
U.S. dollar foreign
 exchange forward
 contracts
(maturing 2014)                  (17)     US 1,000         (11)       US 850
----------------------------------------------------------------------------
                                (343)     US 4,550        (212)     US 4,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(1) Fair values equal carrying values.
    Net income in the three months ended March 31, 2014 included net
    realized gains of $6 million (2013 - gains of $7 million) related to the
(2) interest component of cross-currency swap settlements and are included
    in interest expense.

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 $)        March 31, 2014 December 31, 2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Other current assets                                    5                 5
Intangible and other assets                             1                 -
Accounts payable and other                            (93)              (50)
Other long-term liabilities                          (256)             (167)
----------------------------------------------------------------------------
                                                     (343)             (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:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                     March 31, 2014      December 31, 2013
                                 --------------------- ---------------------
                                 --------------------- ---------------------
(unaudited - millions of Canadian  Carrying       Fair   Carrying       Fair
 $)                               amount(1)      value  amount(1)      value
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Notes receivable and other(1)          199        246        226        269
Available for sale assets(2)            45         45         47         47
Current and long-term debt(3,4)    (24,106)   (28,239)   (22,865)   (26,134)
Junior subordinated notes           (1,105)    (1,144)    (1,063)    (1,093)
----------------------------------------------------------------------------
                                   (24,967)   (29,092)   (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 months ended March 31, 2014
    included losses of $6 million (2013 - losses of $10 million) 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 March 31, 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 $)        March 31, 2014 December 31, 2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Other current assets                                  364               395
Intangible and other assets                           100               112
Accounts payable and other                           (434)             (357)
Other long-term liabilities                          (341)             (255)
----------------------------------------------------------------------------
                                                     (311)             (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                                 $288       $67        $-        $7
  Liabilities                           ($303)     ($73)     ($12)      ($7)
Notional values(3)
  Volumes(4)
    Purchases                          39,687       110         -         -
    Sales                              38,719        60         -         -
  Canadian dollars                          -         -         -         -
  U.S. dollars                              -         -     US 985    US 100
Net unrealized gains/(losses) in the
 period(5)
  three months ended March 31, 2014        $9       ($7)      ($2)       $-
Net realized (losses)/gains in the
 period(5)
  three months ended March 31, 2014      ($28)      $50      ($17)       $-
Maturity dates(3)                    2014-2018 2014-2016     2014      2016
----------------------------------------------------------------------------
Derivative instruments in hedging
 relationships(6,7)
Fair values(2,3)
  Assets                                  $90        $-        $-        $6
  Liabilities                            ($30)       $-        $-       ($1)
Notional values(3)
  Volumes(4)
    Purchases                           8,887         -         -         -
    Sales                               6,299         -         -         -
  U.S. dollars                              -         -         -     US 450
Net realized gains in the period(5)
  three months ended March 31, 2014      $192        $-        $-        $1
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 March 31, 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 $6 million and a notional amount of US$300
    million as at March 31, 2014. For the three months ended March 31, 2014,
    net realized gains on fair value hedges were $1 million and were
    included in interest expense. For the three months ended March 31, 2014,
    the Company did not record any amounts in net income related to
    ineffectiveness for fair value hedges.
(7) For the three months ended March 31, 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 (losses)/gains in the
 period(5)
  three months ended March 31, 2013       ($8)       $9       ($6)       $-
Net realized losses in the period(5)
  three months ended March 31, 2013       ($7)      ($2)      ($1)       $-
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 gains in the period(5)
  three months ended March 31, 2013       $73        $-        $-        $2
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 months ended March 31, 2013 were $2 million and were
    included in Interest expense. In the three months ended March 31, 2013,
    the Company did not record any amounts in net income related to
    ineffectiveness for fair value hedges.
(7) For the three months ended March 31, 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 7) related to derivatives in cash flow hedging relationships are as follows:


----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                three months ended March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of Canadian $, pre-tax)           2014           2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Change in fair value of derivative instruments
 recognized in OCI (effective portion)(1)
  Power                                                   41             36
  Foreign exchange                                        10              2
----------------------------------------------------------------------------
                                                          51             38
----------------------------------------------------------------------------
Reclassification of (losses)/gains on
 derivative instruments from AOCI to net
 income (effective portion)(1)
  Power(2)                                              (108)           (11)
  Interest                                                 5              4
----------------------------------------------------------------------------
                                                        (103)            (7)
----------------------------------------------------------------------------
Losses on derivative instruments recognized in
 net income (ineffective portion)
  Power                                                  (13)            (5)
----------------------------------------------------------------------------
                                                         (13)            (5)
----------------------------------------------------------------------------
(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 of offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                         Gross
                                    derivative
                                   instruments
at March 31, 2014                 presented on        Amounts
(unaudited - millions of           the balance  available for
 Canadian $)                             sheet      offset(1)    Net amounts
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Derivative - Asset
  Power                                   378           (261)           117
  Natural gas                              67            (51)            16
  Foreign exchange                          6             (9)            (3)
  Interest                                 13              -             13
----------------------------------------------------------------------------
Total                                     464           (321)           143
----------------------------------------------------------------------------
Derivative - Liability
  Power                                  (333)           261            (72)
  Natural gas                             (73)            51            (22)
  Foreign exchange                       (361)             9           (352)
  Interest                                 (8)             -             (8)
----------------------------------------------------------------------------
Total                                    (775)           321           (454)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 March 31, 2014, the Company had provided cash collateral of $78 million and letters of credit of $41 million to its counterparties. The Company held $2 million in cash collateral and $29 million in letters of credit on asset exposures at March 31, 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 March 31, 2014, the aggregate fair value of all derivative instruments with credit risk related contingent features that were in a net liability position was $19 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 March 31, 2014, the Company would have been required to provide collateral of $19 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 for 2014, are categorized as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                          Significant
at March 31, 2014        Quoted prices          other    Significant
(unaudited - millions        in active     observable   unobservable
 of Canadian $, pre-           markets         inputs         inputs
 tax)                     (Level I)(1)  (Level II)(1) (Level III)(1)   Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Derivative instrument
 assets:
 Power commodity
  contracts                         -            374              4     378
 Natural gas commodity
  contracts                        48             19              -      67
 Foreign exchange
  contracts                         -              6              -       6
 Interest rate
  contracts                         -             13              -      13
Derivative instrument
 liabilities:
 Power commodity
  contracts                         -           (330)            (3)   (333)
 Natural gas commodity
  contracts                       (46)           (27)             -     (73)
 Foreign exchange
  contracts                         -           (361)             -    (361)
 Interest rate
  contracts                         -             (8)             -      (8)
Non-derivative
 financial instruments:
 Available for sale
  assets                            -             45              -      45
----------------------------------------------------------------------------
                                    2           (269)             1    (266)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) There were no transfers from Level I to Level II or from Level II to
    Level III for the three months ended March 31, 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:


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

                                          Significant
at December 31, 2013     Quoted prices          other    Significant
(unaudited - millions        in active     observable   unobservable
 of Canadian $, pre-           markets         inputs         inputs
 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
                                                         March 31
                                              ------------------------------
                                              ------------------------------
(unaudited - millions of Canadian $, pre-tax)            2014          2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Balance at beginning of period                              1            (2)
Total gains included in OCI                                 -             3
----------------------------------------------------------------------------
Balance at end of period                                    1             1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Energy revenues include unrealized gains or losses attributed to
    derivatives in the Level III category that were still held at March 31,
    2014 of nil (2013 - nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at March 31, 2014.

10. 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 March 31, 2014   at December 31, 2013
                                  -------------------- ---------------------
                                  -------------------- ---------------------
(unaudited -
 millions of                        Potential Carrying   Potential  Carrying
 Canadian $)                 Term Exposure(1)    Value  Exposure(1)    Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                       ranging to
Bruce Power               2019(2)        708        8          740        8
Other jointly
 owned entities   ranging to 2040         62       10           51       10
----------------------------------------------------------------------------
                                         770       18          791       18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) TransCanada's share of the potential estimated current or contingent
    exposure.
(2) Except for one guarantee with no termination date.

11. Subsequent events

CANCARB ASSET SALE

As previously announced, on January 20, 2014, TransCanada reached an agreement to sell Cancarb Limited and its related power generation facility. On April 15, 2014, the sale was completed for aggregate gross proceeds of $190 million, subject to post-closing adjustments. TransCanada expects to realize a gain on the sale of approximately $95 million, net of tax, in second quarter 2014. These assets are classified as assets held for sale and presented in other current assets and accounts payable and other in the condensed consolidated balance sheet as at March 31, 2014.

NATURAL GAS STORAGE

Effective April 30, 2014, TransCanada 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. In consideration for this termination, TransCanada expects to record an after-tax charge of approximately $33 million in second quarter 2014. TransCanada has 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.

Contacts:
TransCanada Media Enquiries:
Shawn Howard/Grady Semmens/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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