TRP-03.31.2014-MD&A

EX-13.1 2 trp-03312014xmda.htm MANAGEMENT'S DISCUSSION AND ANALYSIS TRP-03.31.2014-MD&A

EXHIBIT 13.1

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

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FIRST QUARTER 2014

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

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•	amount of capacity sold and rates achieved in our pipeline businesses


•	the availability and price of energy commodities


•	the amount of capacity payments and revenues we receive from our energy business


•	regulatory decisions and outcomes


•	outcomes of legal proceedings, including arbitration


•	performance of our counterparties


•	changes in the political environment


•	changes in environmental and other laws and regulations


•	competitive factors in the pipeline and energy sectors


•	construction and completion of capital projects


•	costs for labour, equipment and materials


•	access to capital markets


•	interest and foreign exchange rates


•	weather


•	cyber security


•	technological developments


•	economic conditions in North America as well as globally.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2013 Annual Report.

You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.

FOR MORE INFORMATION

You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).

NON-GAAP MEASURES

We use the following non-GAAP measures:


•	EBITDA


•	EBIT


•	funds generated from operations


•	comparable earnings


•	comparable earnings per common share


•	comparable EBITDA


•	comparable EBIT


•	comparable depreciation and amortization


•	comparable interest expense


•	comparable interest income and other


•	comparable income tax expense.

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

EBITDA and EBIT

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

Funds generated from operations

Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a better measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period. See Financial condition section for a reconciliation to net cash provided by operations.

Comparable measures

We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.

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Comparable measure	Original measure

comparable earnings	net income attributable to common shares
comparable earnings per common share	net income per common share
comparable EBITDA	EBITDA
comparable EBIT	EBIT
comparable depreciation and 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.

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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

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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.

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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.

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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.

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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$)
ANR	78		90
TC PipeLines, LP^1,2	26		17
Great Lakes³	19		10
Other U.S. pipelines (Bison⁴, Iroquois^1,GTN⁴, Portland⁵)	45		71
Mexico (Guadalajara, Tamazunchale)	25		26
International and other (Gas Pacifico/INNERGY¹, TransGas¹)	(1	)	(2	)
Non-controlling interests⁶	73		43
U.S. Pipelines and International - comparable EBITDA	265		255
Comparable depreciation and amortization	(54	)	(55	)
U.S. Pipelines and International - comparable EBIT	211		200
Foreign exchange impact	21		2
U.S. Pipelines and International - comparable EBIT(Cdn$)	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.

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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.

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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.

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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.

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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.

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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.

TRANSCANADA [15

FIRST QUARTER 2014

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.

TRANSCANADA [16

FIRST QUARTER 2014

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.

TRANSCANADA [17

FIRST QUARTER 2014

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

TRANSCANADA [18

FIRST QUARTER 2014

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.

TRANSCANADA [19

FIRST QUARTER 2014

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.

TRANSCANADA [20

FIRST QUARTER 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

TRANSCANADA [21

FIRST QUARTER 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

TRANSCANADA [22

FIRST QUARTER 2014

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.

TRANSCANADA [23

FIRST QUARTER 2014

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

TRANSCANADA [24

FIRST QUARTER 2014

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

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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.

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.

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.

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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.

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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.

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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.