2014-05-02 | TransCanada Reports 15 Per Cent Increase in First Quarter Comparable Earnings | TSX:TRP

Funds Generated from Operations Exceed $1.1 Billion

CALGARY, ALBERTA--(Marketwired - May 2, 2014) - 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 Québec 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.

		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

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

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.

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 amortization		depreciation and 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 activities¹	(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 activities¹	(2	)	(6	)
Interest income and other	(8	)	13

Comparable income tax expense	(224	)	(159	)
Specific items:
NEB decision - 2012	-		42
Risk management activities¹	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 activities¹	(0.02	)	(0.01	)
Net income per common share	$0.58		$0.63

¹	Risk management activities	three months ended 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

three months ended March 31, 2014	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines¹		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

three months ended March 31, 2013	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines¹		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 Rapids¹	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 projects²
Keystone XL³	Approximately 2 years from date permit received	US 5.4	US 2.3
Energy East⁴	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 (TQM¹, 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$)
ANR	78		90
TC PipeLines, LP^1,2	26		17
Great Lakes³	19		10
Other U.S. pipelines (Bison⁴, Iroquois¹, GTN⁴, Portland⁵)	45		71
Mexico (Guadalajara, Tamazunchale)	25		26
International and other (Gas Pacifico/INNERGY¹, TransGas¹)	(1	)	(2	)
Non-controlling interests⁶	73		43
U.S. Pipelines and International - comparable EBITDA	265		255
Comparable depreciation and amortization	(54	)	(55	)
U.S. Pipelines and International - comparable EBIT	211		200
Foreign exchange impact	21		2
U.S. Pipelines and International - comparable EBIT (Cdn$)	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

three months ended March 31	Canadian Mainline¹		NGTL System²		ANR³
(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 Pipelines¹

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 Power¹	93		90
Bruce Power	64		31
Canadian Power - comparable EBITDA²	229		195
Comparable depreciation and amortization	(44	)	(43	)
Canadian Power - comparable EBIT²	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 EBIT²	268		203

Summary

Energy - comparable EBITDA²	345		277
Comparable depreciation and amortization	(77	)	(74	)
Energy - comparable EBIT²	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 Power¹

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 Power¹	142		109
Other²	51		31
	374		282
Income from equity investments³	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 Power¹	1,277		1,346
	Purchased
		Sundance A & B and Sheerness PPAs²	2,800		1,707
		Other purchases	5		-
			4,691		3,723
Sales
	Contracted
		Western Power	2,461		1,707
		Eastern Power¹	1,277		1,346
	Spot
		Western Power	953		670
			4,691		3,723
Plant availability³
Western Power⁴			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 Bécancour 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 investments¹
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 availability²
	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 MWh³
	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
Power¹	745		462
Capacity	70		47
	815		509
Commodity purchases resold	(549	)	(306	)
Plant operating costs and other²	(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 availability¹		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 Québec 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

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

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

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

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
	343		311
Other interest and amortization expense	10		1
Capitalized interest	(79	)	(55	)
Comparable interest expense	274		257

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

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

Funds generated from operations¹	1,102		916
Increase in operating working capital	(123	)	(210	)
Net cash provided by operations	979		706

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

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

Capital expenditures	778	929
Equity investments	89	32

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

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

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	)	-

LONG-TERM DEBT ISSUED

Amount (unaudited - millions of $)	Type	Maturity date	Interest rate		Date issued

US$1,250	Senior unsecured notes	March 1, 2034	4.625	%	February 2014

LONG-TERM DEBT RETIRED

Amount (unaudited - millions of $)	Type	Retirement date	Interest rate

$450	Medium term notes	January 2014	5.65	%
$300	Medium term notes	February 2014	5.05	%

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:

Quarterly dividend on our common shares

$0.48 per share
Payable on July 30, 2014 to shareholders of record at the close of business on June 30, 2014

Quarterly dividends on our preferred shares

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

SHARE INFORMATION

April 28, 2014

Common shares	Issued and outstanding
	708 million
Preferred shares	Issued and outstanding	Convertible to
Series 1	22 million	22 million Series 2 preferred shares
Series 3	14 million	14 million Series 4 preferred shares
Series 5	14 million	14 million Series 6 preferred shares
Series 7	24 million	24 million Series 8 preferred shares
Series 9	18 million	18 million Series 10 preferred shares

Options to buy common shares	Outstanding	Exercisable
	9 million	5 million

CREDIT FACILITIES

We use committed, revolving credit facilities to support our commercial paper programs along with additional demand facilities for general corporate purposes including issuing letters of credit and providing additional liquidity.

At March 31, 2014, we had $6 billion in unsecured credit facilities, including:

Amount	Unused capacity	Subsidiary	For	Matures

$3.0 billion	$3.0 billion	TCPL	Committed, syndicated, revolving, extendible credit facility that supports TCPL's Canadian commercial paper program	December 2018
US$1.0 billion	US$1.0 billion	TCPL USA	Committed, syndicated, revolving, extendible credit facility that is used for TCPL USA general corporate purposes	November 2014
US$1.0 billion	US$1.0 billion	TransCanada American Investments Ltd. (TAIL)	Committed, syndicated, revolving, extendible credit facility that supports the TAIL U.S. dollar commercial paper program in the U.S.	November 2014
$1.1 billion	$0.3 billion	TCPL, TCPL USA	Demand lines for 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	Demand

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

First quarter 2014	1.11
First quarter 2013	1.01

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

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

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	)
	165		141

NET INVESTMENT IN FOREIGN OPERATIONS

We hedge our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, 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:

	March 31, 2014			December 31, 2013
(unaudited - millions of $)	Fair value¹		Notional or principal amount	Fair value¹		Notional or principal amount

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
	(343	)	US 4,550	(212	)	US 4,650

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

(unaudited - millions of $)	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)

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

(unaudited - millions of $)	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

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:

(unaudited - millions of $)	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	)

The effect of derivative instruments on the consolidated statement of income

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

		three months ended March 31
(unaudited - millions of $, pre-tax)		2014		2013
Derivative instruments held for trading¹
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

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:

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

Change in fair value of derivative instruments recognized in OCI (effective portion)
	Power	41		36
	Foreign Exchange	10		2
		51		38
Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)
	Power	(108	)	(11	)
	Interest	5		4
		(103	)	(7	)
Losses on derivative instruments recognized in earnings (ineffective portion)
	Power	(13	)	(5	)
		(13	)	(5	)

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

		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

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 31	Natural Gas Pipelines				Liquids Pipelines¹				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

¹Previously Oil Pipelines.

TOTAL ASSETS

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

Natural Gas Pipelines	25,765	25,165
Liquids Pipelines¹	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 - millions of $)	Type	Maturity date	Interest rate		Date issued
US$1,250	Senior unsecured notes	March 1, 2034	4.63	%	February 2014

LONG-TERM DEBT RETIRED

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

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:

three months ended March 31, 2014	Before tax		Income 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

three months ended March 31, 2013	Before tax		Income 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 - millions of Canadian $)	Currency translation adjustments		Cash flow hedges		Pension and OPEB plan adjustments		Equity Investments		Total¹

AOCI balance at January 1, 2014	(629	)	(4	)	(197	)	(104	)	(934	)
Other comprehensive income before reclassifications²	69		31		-		-		100
Amounts reclassified from accumulated other comprehensive loss³	-		(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:

three months ended March 31, 2014 (unaudited - millions of Canadian $)	Amounts reclassified from accumulated other comprehensive loss¹		Affected line item in the condensed consolidated 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 cost²	(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
	Pension benefit plans				Other post-retirement 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
(unaudited - millions of Canadian $)	Fair Value¹		Notional or principal amount	Fair value¹		Notional or principal 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.
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 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 amount¹		Fair value		Carrying amount¹		Fair value

Notes receivable and other¹	199		246		226		269
Available for sale assets²	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 $ unless noted otherwise)			Power		Natural gas		Foreign exchange		Interest

Derivative instruments held for trading¹
Fair values^2,3
	Assets		$288		$67		$-		$7
	Liabilities		($303	)	($73	)	($12	)	($7	)
Notional values³
	Volumes⁴
		Purchases	39,687		110		-		-
		Sales	38,719		60		-		-
	Canadian dollars		-		-		-		-
	U.S. dollars		-		-		US 985		US 100
Net unrealized gains/(losses) in the period⁵
	three months ended March 31, 2014		$9		($7	)	($2	)	$-
Net realized (losses)/gains in the period⁵
	three months ended March 31, 2014		($28	)	$50		($17	)	$-
Maturity dates³			2014-2018		2014-2016		2014		2016
Derivative instruments in hedging relationships^6,7
Fair values^2,3
	Assets		$90		$-		$-		$6
	Liabilities		($30	)	$-		$-		($1	)
Notional values³
	Volumes⁴
		Purchases	8,887		-		-		-
		Sales	6,299		-		-		-
	U.S. dollars		-		-		-		US 450
Net realized gains in the period⁵
	three months ended March 31, 2014		$192		$-		$-		$1
Maturity dates³			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 $ unless noted otherwise)			Power		Natural gas		Foreign exchange		Interest

Derivative instruments held for trading¹
Fair values^2,3
	Assets		$265		$73		$-		$8
	Liabilities		($280	)	($72	)	($12	)	($7	)
Notional values³
	Volumes⁴
		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 period⁵
	three months ended March 31, 2013		($8	)	$9		($6	)	$-
Net realized losses in the period⁵
	three months ended March 31, 2013		($7	)	($2	)	($1	)	$-
Maturity dates³			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 values³
	Volumes⁴
		Purchases	9,758		-		-		-
		Sales	6,906		-		-		-
	U.S. dollars		-		-		US 16		US 350
Net realized gains in the period⁵
	three months ended March 31, 2013		$73		$-		$-		$2
Maturity dates³			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
	Power²	(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:


at March 31, 2014 (unaudited - millions of Canadian $)		Gross derivative instruments presented on the balance sheet		Amounts available for offset¹		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:


at December 31, 2013 (unaudited - millions of Canadian $)		Gross derivative instruments presented on the balance sheet		Amounts available for offset¹		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:


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


at December 31, 2013 (unaudited - millions of Canadian $, pre-tax)		Quoted prices in active markets (Level I)¹		Significant other observable inputs (Level II)¹		Significant unobservable inputs (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:

	Derivatives¹
	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 Canadian $)	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value

Bruce Power	ranging to 2019²	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.

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

Marketwired (Canada)

May 2, 2014 - 8:30 AM EDT

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TransCanada Reports 15 Per Cent Increase in First Quarter Comparable Earnings

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TransCanada Reports 15 Per Cent Increase in First Quarter Comparable Earnings

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