exhibit13107262013q2.htm

EXHIBIT 13.1

Quarterly report to shareholders

Second quarter 2013

Financial highlights

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

	three months ended June 30					six months ended June 30
(unaudited - millions of $, except per share amounts)	2013			2012		2013			2012

Income
Revenue		2,009			1,847		4,261			3,792
Comparable EBITDA		1,143			997		2,311			2,110
Net income attributable to common shares		365			272		811			624
per common share - basic		$0.52			$0.39		$1.15			$0.89
Comparable earnings		357			300		727			663
per common share		$0.51			$0.43		$1.03			$0.94

Operating cash flow
Funds generated from operations		955			729		1,871			1,600
(Increase)/decrease in operating working capital		(114	)		14		(324	)		(155	)
Net cash provided by operations		841			743		1,547			1,445

Investing activities
Capital expenditures		1,109			397		2,038			861
Equity investments		39			197		71			413
Acquisition		55			-		55			-

Dividends
Per common share		$0.46			$0.44		$0.92			$0.88

Basic common shares outstanding (millions)
Average for the period		707			704		706			704
End of period		707			704		707			704

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SECOND QUARTER 2013

Management’s discussion and analysis

July 25, 2013

This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and six months ended June 30, 2013, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2013 which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2012 audited consolidated financial statements and notes and the MD&A in our 2012 Annual Report, which have been prepared in accordance with U.S. GAAP.

About this document

Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries.

Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2012 Annual Report.

All information is as of July 25, 2013 and all amounts are in Canadian dollars, unless noted otherwise.

FORWARD-LOOKING INFORMATION

We disclose forward-looking information to help current and potential investors understand management’s assessment of our future plans and financial outlook, and our future prospects overall.

Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements in this MD&A may include information about the following, among other things:

•	anticipated business prospects

•	our financial and operational performance, including the performance of our subsidiaries

•	expectations or projections about strategies and goals for growth and expansion

•	expected cash flows and future financing options available to us

•	expected costs for planned projects, including projects under construction and in development

•	expected schedules for planned projects (including anticipated construction and completion dates)

•	expected regulatory processes and outcomes

•	expected impact required as a result of regulatory outcomes

•	expected outcomes with respect to legal proceedings, including arbitration

•	expected capital expenditures and contractual obligations

•	expected operating and financial results

•	the expected impact of future commitments and contingent liabilities

•	expected industry, market and economic conditions.

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.

Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:

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SECOND QUARTER 2013

Assumptions

•	inflation rates, commodity prices and capacity prices

•	timing of financings and hedging

•	regulatory decisions and outcomes

•	foreign exchange rates

•	interest rates

•

tax rates

•	planned and unplanned outages and the use of our pipeline and energy assets

•	integrity and reliability of our assets

•	access to capital markets

•	anticipated construction costs, schedules and completion dates

•	acquisitions and divestitures.

Risks and uncertainties

•	our ability to successfully implement our strategic initiatives

•	whether our strategic initiatives will yield the expected benefits

•	the operating performance of our pipeline and energy assets

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

•	the availability and price of energy commodities

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

•	regulatory decisions and outcomes

•	outcomes of legal proceedings, including arbitration

•	performance of our counterparties

•	changes in the political environment

•	changes in environmental and other laws and regulations

•	competitive factors in the pipeline and energy sectors

•	construction and completion of capital projects

•	labour, equipment and material costs

•	access to capital markets

•	interest and foreign exchange rates

•

weather

•	cybersecurity

•	technological developments

•	economic conditions in North America as well as globally.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2012 Annual Report.

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

FOR MORE INFORMATION

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

NON-GAAP MEASURES

We use the following non-GAAP measures:

EBITDA

EBIT

·	comparable earnings

·	comparable earnings per common share

·	comparable EBITDA

·	comparable EBIT

·	comparable depreciation and amortization

·	comparable interest expense

·	comparable interest income and other

·	comparable income taxes

·	funds generated from operations.

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SECOND QUARTER 2013

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

EBITDA and EBIT

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

Funds generated from operations

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

Comparable measures

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

Comparable measure	Original measure

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 taxes	income tax expense/(recovery)

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

·	certain fair value adjustments relating to risk management activities

·	income tax refunds and adjustments

·	gains or losses on sales of assets

·	legal and bankruptcy settlements, and

·	write-downs of assets and investments.

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

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SECOND QUARTER 2013

Reconciliation of non-GAAP measures

	three months ended June 30						six months ended June 30
(unaudited - millions of $, except per share amounts)	2013			2012			2013			2012

Comparable EBITDA		1,143			997			2,311			2,110
Comparable depreciation and amortization		(356	)		(346	)		(710	)		(690	)
Comparable EBIT		787			651			1,601			1,420
Other income statement items
Comparable interest expense		(252	)		(239	)		(509	)		(481	)
Comparable interest income and other		(2	)		19			16			44
Comparable income taxes		(133	)		(91	)		(292	)		(231	)
Net income attributable to non-controlling interests		(23	)		(26	)		(54	)		(61	)
Preferred share dividends		(20	)		(14	)		(35	)		(28	)
Comparable earnings		357			300			727			663
Specific items (net of tax):
Canadian restructuring proposal - 2012		-			-			84			-
Income tax adjustment		25			-			25			-
Sundance A PPA arbitration decision - 2011		-			(15	)		-			(15	)
Risk management activities1		(17	)		(13	)		(25	)		(24	)
Net income attributable to common shares		365			272			811			624
Comparable depreciation and amortization		(356	)		(346	)		(710	)		(690	)
Specific item:
Canadian restructuring proposal - 2012		-			-			(13	)		-
Depreciation and amortization		(356	)		(346	)		(723	)		(690	)
Comparable interest expense		(252	)		(239	)		(509	)		(481	)
Specific item:
Canadian restructuring proposal - 2012		-			-			(1	)		-
Interest expense		(252	)		(239	)		(510	)		(481	)
Comparable interest income and other		(2	)		19			16			44
Specific items:
Canadian restructuring proposal - 2012		-			-			1			-
Risk management activities1		(9	)		(14	)		(15	)		(8	)
Interest income and other		(11	)		5			2			36
Comparable income taxes		(133	)		(91	)		(292	)		(231	)
Specific items:
Canadian restructuring proposal - 2012		-			-			42			-
Income tax adjustment		25			-			25			-
Income taxes attributable to Sundance A PPA arbitration decision - 2011		-			5			-			5
Risk management activities1		10			1			12			12
Income taxes expense		(98	)		(85	)		(213	)		(214	)
Comparable earnings per common share		$0.51			$0.43			$1.03			$0.94
Specific items (net of tax):
Canadian restructuring proposal - 2012		-			-			0.12			-
Income tax adjustment		0.04			-			0.04			-
Sundance A PPA arbitration decision - 2011		-			(0.02	)		-			(0.02	)
Risk management activities1		(0.03	)		(0.02	)		(0.04	)		(0.03	)
Net income per common share		$0.52			$0.39			$1.15			$0.89

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SECOND QUARTER 2013

		three months ended June 30					six months ended June 30
1	(unaudited - millions of $)		2013		2012			2013		2012

	Canadian Power		(4	)	1			(6	)	(1	)
	U.S. Power		(18	)	16			(17	)	(16	)
	Natural Gas Storage		4		(17	)		1		(11	)
	Foreign exchange		(9	)	(14	)		(15	)	(8	)
	Income taxes attributable to risk management activities		10		1			12		12
	Total losses from risk management activities		(17	)	(13	)		(25	)	(24	)

EBITDA and EBIT by business segment

three months ended June 30, 2013 (unaudited - millions of $)	Natural Gas Pipelines			Oil Pipelines			Energy			Corporate			Total

Comparable EBITDA		644			186			330			(17	)		1,143
Comparable depreciation and amortization		(245	)		(37	)		(69	)		(5	)		(356	)
Comparable EBIT		399			149			261			(22	)		787

three months ended June 30, 2012 (unaudited - millions of $)	Natural Gas Pipelines			Oil Pipelines			Energy			Corporate			Total

Comparable EBITDA		666			176			170			(15	)		997
Comparable depreciation and amortization		(234	)		(36	)		(72	)		(4	)		(346	)
Comparable EBIT		432			140			98			(19	)		651

six months ended June 30, 2013 (unaudited - millions of $)	Natural Gas Pipelines			Oil Pipelines			Energy			Corporate			Total

Comparable EBITDA		1,390			365			607			(51	)		2,311
Comparable depreciation and amortization		(485	)		(74	)		(143	)		(8	)		(710	)
Comparable EBIT		905			291			464			(59	)		1,601

six months ended June 30, 2012 (unaudited - millions of $)	Natural Gas Pipelines			Oil Pipelines			Energy			Corporate			Total

Comparable EBITDA		1,391			349			414			(44	)		2,110
Comparable depreciation and amortization		(466	)		(72	)		(145	)		(7	)		(690	)
Comparable EBIT		925			277			269			(51	)		1,420

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SECOND QUARTER 2013

Results - second quarter 2013

Net income attributable to common shares was $365 million this quarter compared to $272 million in second quarter 2012. Second quarter 2013 results included a $25 million favourable income tax adjustment due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax, in June 2013 and was excluded from comparable earnings. Second quarter 2012 included an after-tax charge of $37 million ($50 million pre-tax) related to the impact of the Sundance A PPA arbitration decision. Of this amount, $15 million ($20 million pre-tax) is excluded from 2012 comparable earnings as it related to 2011.

Net income attributable to common shares was $811 million for the six months ended June 30, 2013 compared to $624 million for the same period in 2012. The 2013 results included $84 million of net income related to 2012 from the NEB decision on the Canadian Restructuring Proposal. Also included was the $25 million of net income resulting from the favourable income tax adjustment noted above. These amounts were excluded from comparable earnings. The 2012 results included an after-tax charge of $15 million ($20 million pre-tax) that was excluded from 2012 comparable earnings as it related to 2011.

Comparable earnings this quarter were $357 million and $0.51 per share, $57 million and $0.08 per share higher than second quarter 2012.

This was the result of:

·	higher earnings from Western Power because of higher realized power prices, higher purchased PPA volumes as well as the Sundance A PPA charge recorded in second quarter 2012

·	higher equity income from Bruce Power because of incremental earnings from Units 1 and 2, which were returned to service in October 2012, and the completion of the Unit 3 West Shift Plus planned outage in June 2012, partially offset by higher planned outage days in second quarter 2013

·	higher realized power prices from U.S. Power

·	higher earnings from the Canadian Mainline because of the higher ROE of 11.50 per cent in 2013 compared to 8.08 per cent in 2012.

These increases were partly offset by:

·	lower contribution from U.S. natural gas pipelines

·	higher comparable interest expense reflecting lower capitalized interest primarily as a result of the return to service of Bruce Power Units 1 and 2

·	lower comparable interest income and other because we had realized losses in 2013 compared to realized gains in 2012 on derivatives used to manage our exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

·	higher comparable income taxes because of higher pre-tax earnings.

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

This was the result of:

·	higher equity income from Bruce Power because of incremental earnings from Units 1, 2 and 3 and the recognition of an insurance recovery in first quarter 2013 partly offset by an increase in planned outage days

·	higher realized power prices in Western Power and U.S. Power

·	higher earnings from the Canadian Mainline because of the higher ROE of 11.50 per cent in 2013 compared to 8.08 per cent in 2012.

These increases were partly offset by:

·	lower contribution from U.S. natural gas pipelines

·	lower comparable interest income and other because we had realized losses in 2013 compared to realized gains in 2012 on derivatives used to manage our exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

·	higher comparable income taxes because of higher pre-tax earnings.

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SECOND QUARTER 2013

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

·	$17 million ($27 million before tax) for the three months ended June 30, 2013 compared to $13 million ($14 million before tax) for the same period in 2012

·	$25 million ($37 million before tax) for the six months ended June 30, 2013 compared to $24 million ($36 million before tax) for the same period in 2012.

Outlook

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

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SECOND QUARTER 2013

Natural Gas Pipelines

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

	three months ended June 30						six months ended June 30
(unaudited - millions of $)	2013			2012			2013			2012

Canadian Pipelines
Canadian Mainline		263			247			543			497
NGTL System		193			183			375			360
Foothills		28			30			57			61
Other Canadian (TQM1, Ventures LP)		7			7			13			15
Canadian Pipelines - comparable EBITDA		491			467			988			933
Comparable depreciation and amortization2		(190	)		(177	)		(374	)		(354	)
Canadian Pipelines - comparable EBIT		301			290			614			579

U.S. and International (US$)
ANR		32			53			122			150
GTN3		26			26			54			56
Great Lakes4		8			17			18			35
TC PipeLines, LP1,5		13			18			30			38
Other U.S. pipelines (Iroquois1, Bison3, Portland6)		23			23			66			57
International (Gas Pacifico/INNERGY1, Guadalajara, Tamazunchale, TransGas1)		25			30			51			58
General, administrative and support costs		(3	)		(2	)		(5	)		(4	)
Non-controlling interests7		31			38			74			83
U.S. Pipelines and International - comparable EBITDA		155			203			410			473
Comparable depreciation and amortization2		(54	)		(56	)		(109	)		(111	)
U.S. Pipelines and International - comparable EBIT		101			147			301			362
Foreign exchange		2			2			4			2
U.S. Pipelines and International - comparable EBIT (Cdn$)		103			149			305			364

Business Development comparable EBITDA and EBIT		(5	)		(7	)		(14	)		(18	)
Natural Gas Pipelines - comparable EBIT		399			432			905			925

Summary
Natural Gas Pipelines - comparable EBITDA		644			666			1,390			1,391
Comparable depreciation and amortization2		(245	)		(234	)		(485	)		(466	)
Natural Gas Pipelines - comparable EBIT		399			432			905			925

1	Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments.

2	Does not include depreciation and amortization from equity investments.

3	Represents our 75 per cent direct ownership interest.

4	Represents our 53.6 per cent direct ownership interest.

Effective May 22, 2013, our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent. Results reflect our 28.9 per cent ownership interest effective May 22, 2013 and 33.3 per cent from January 1 to May 22, 2013. Our effective ownership through TC PipeLines, LP prior to May 22, 2013 was 8.3 per cent of each of GTN and Bison, 16.7 per cent of Northern Border and an additional effective ownership of 15.4 per cent of Great Lakes. Our effective ownership through TC PipeLines, LP effective May 22, 2013 was 7.2 per cent of each of GTN and Bison, 14.4 per cent of Northern Border and an additional effective ownership of 13.4 per cent of Great Lakes.

6	Represents our 61.7 per cent ownership interest.

7	Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

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SECOND QUARTER 2013

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES

	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2013		2012		2013		2012

Canadian Mainline - net income		67		46		218		93
Canadian Mainline - comparable earnings		67		46		134		93
NGTL System		58		52		114		100
Foothills		5		4		9		9

OPERATING STATISTICS - WHOLLY OWNED PIPELINES

six months ended June 30	Canadian Mainline1				NGTL System2				ANR3
(unaudited)	2013		2012		2013		2012		2013		2012

Average investment base (millions of $)		5,871		5,775		5,882		5,359		n/a		n/a
Delivery volumes (Bcf)
Total		704		804		1,832		1,844		823		844
Average per day		3.9		4.4		10.1		10.1		4.6		4.6

1	Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the six months ended June 30, 2013 were 397 Bcf (2012 – 455 Bcf). Average per day was 2.2 Bcf (2012 – 2.5 Bcf).

2	Field receipt volumes for the NGTL System for the six months ended June 30, 2013 were 1,840 Bcf (2012 – 1,856 Bcf). Average per day was 10.2 Bcf (2012 – 10.2 Bcf).

3	Under its current rates, which are approved by the FERC, changes in average investment base do not affect results.

CANADIAN PIPELINES

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

Canadian Mainline’s comparable earnings increased by $21 million for the three months ended June 30, 2013 and $41 million for the six months ended June 30, 2013 compared to the same periods in 2012 because of the impact of the NEB’s March 2013 decision (the NEB decision) on the Canadian Restructuring Proposal. Among other items, the NEB approved an ROE of 11.50 per cent on a 40 per cent deemed common equity for the years 2012 through to 2017 compared to the last approved ROE of 8.08 per cent on a deemed common equity of 40 per cent that was used to record earnings in 2012. Net income of $218 million for the six months ended June 30, 2013 included $84 million related to the 2012 impact of the NEB decision.

Net income for the NGTL System (formerly known as the Alberta System) increased by $6 million for the three months ended June 30, 2013 and $14 million for the six months ended June 30, 2013, compared to the same periods in 2012 because of a higher average investment base and termination of the annual fixed OM&A costs component included in the 2010 - 2012 Revenue Requirement Settlement which expired at the end of 2012. Results for 2013 reflect the last approved ROE of 9.70 per cent on deemed common equity of 40 per cent and no incentive earnings.

U.S. PIPELINES AND INTERNATIONAL

EBITDA for our U.S. operations is generally affected by contracted volume levels, volumes delivered and the rates charged, as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.

Comparable EBITDA for the U.S. and international pipelines was US$155 million for the three months ended June 30, 2013 and US$410 million for the six months ended June 30, 2013 compared to US$203 million and US$473 million for the same periods in 2012. This was the net effect of:

·	higher costs at ANR relating to services provided by other pipelines as well as lower second quarter revenues

·	lower revenues at Great Lakes because of lower rates and uncontracted capacity

·	lower contributions from TransGas and Gas Pacifico/INNERGY

·	higher short term and interruptible revenues at Portland.

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SECOND QUARTER 2013

·	lower contributions from TransGas and Gas Pacifico/INNERGY

·	higher short term and interruptible revenues at Portland.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization was $245 million for the three months ended June 30, 2013 and $485 million for the six months ended June 30, 2013 compared to $234 million and $466 million for the same periods in 2012 mainly because of a higher investment base on the NGTL System and the impact of the NEB decision on the Canadian Mainline.

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SECOND QUARTER 2013

Oil Pipelines

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

	three months ended June 30						six months ended June 30
(unaudited - millions of $)	2013			2012			2013			2012

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

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

·	higher contracted volumes

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

BUSINESS DEVELOPMENT

Business development expenses in the first six months of 2013 were $5 million higher than the same period in 2012 because of increased activity on various development projects.

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SECOND QUARTER 2013

Energy

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

	three months ended June 30						six months ended June 30
(unaudited - millions of $)	2013			2012			2013			2012

Canadian Power
Western Power1		123			27			202			158
Eastern Power1,2		75			73			170			166
Bruce Power1		59			31			90			18
General, administrative and support costs		(12	)		(11	)		(22	)		(22	)
Canadian Power - comparable EBITDA1		245			120			440			320
Comparable depreciation and amortization3		(43	)		(39	)		(86	)		(79	)
Canadian Power - comparable EBIT1		202			81			354			241
U.S. Power (US$)
Northeast Power		92			49			169			95
General, administrative and support costs		(12	)		(11	)		(22	)		(21	)
U.S. Power - comparable EBITDA		80			38			147			74
Comparable depreciation and amortization		(23	)		(30	)		(51	)		(60	)
U.S. Power - comparable EBIT		57			8			96			14
Foreign exchange		1			1			2			1
U.S. Power - comparable EBIT (Cdn$)		58			9			98			15
Natural Gas Storage
Alberta Storage		11			19			31			34
General, administrative and support costs		(2	)		(2	)		(4	)		(4	)
Natural Gas Storage - comparable EBITDA1		9			17			27			30
Comparable depreciation and amortization3		(2	)		(3	)		(5	)		(6	)
Natural Gas Storage - comparable EBIT1		7			14			22			24
Business Development comparable EBITDA and EBIT		(6	)		(6	)		(10	)		(11	)
Energy - comparable EBIT1		261			98			464			269

Summary
Energy - comparable EBITDA1		330			170			607			414
Comparable depreciation and amortization3		(69	)		(72	)		(143	)		(145	)
Energy - comparable EBIT1		261			98			464			269

1	Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, Portlands Energy, Bruce Power and, in 2012, CrossAlta. In December 2012, we acquired the remaining 40 per cent interest in CrossAlta, bringing our ownership interest to 100 per cent.

2	Includes phase two of Cartier Wind Gros-Morne starting in November 2012 and the acquisition of the first Ontario Solar project in June 2013.

3	Does not include depreciation and amortization of equity investments.

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

·	higher earnings from Western Power primarily due to higher realized power prices, the Sundance A PPA charge recorded in second quarter 2012 earnings and higher purchased PPA volumes

·	higher earnings from U.S. Power mainly because of higher realized power and capacity prices in New York

higher equity income from Bruce Power because of incremental earnings from Units 1 and 2, which were returned to service in October 2012, and higher earnings from Unit 3, due to an outage during first and second quarter 2012, partially offset by lower Bruce B volumes due to higher planned outage days.

TRANSCANADA [14

SECOND QUARTER 2013

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

·	higher earnings from U.S. Power mainly because of higher realized power prices and higher capacity prices in New York

higher equity income from Bruce Power because of incremental earnings from Units 1 and 2, which were returned to service in October 2012, the recognition of a business interruption insurance recovery in first quarter 2013, and higher earnings from Unit 3 due to the first and second quarter 2012 outage partially offset by the extended outage of Unit 4 in first quarter 2013 and lower Bruce B volumes due to higher planned outage days

·	higher earnings from Western Power primarily due to higher realized power prices and higher purchased PPA volumes.

CANADIAN POWER

Western and Eastern Power1

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

	three months ended June 30						six months ended June 30
(unaudited - millions of $)	2013			2012			2013			2012

Revenue
Western Power		161			106			303			330
Eastern Power1		91			98			200			201
Other2		22			22			53			47
		274			226			556			578
Income from equity investments3		66			(6	)		88			17
Commodity purchases resold
Western power		(82	)		(43	)		(147	)		(137	)
Other4		(1	)		-			(3	)		(2	)
		(83	)		(43	)		(150	)		(139	)
Plant operating costs and other		(59	)		(47	)		(122	)		(102	)
Sundance A PPA arbitration decision - 2012		-			(30	)		-			(30	)
General, administrative and support costs		(12	)		(11	)		(22	)		(22	)
Comparable EBITDA		186			89			350			302
Comparable depreciation and amortization5		(43	)		(39	)		(86	)		(79	)
Comparable EBIT		143			50			264			223

1	Includes phase two of Cartier Wind Gros-Morne starting in November 2012 and the acquisition of the first Ontario Solar project in June 2013.

2	Includes sale of excess natural gas purchased for generation and sales of thermal carbon black.

3	Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy.

4	Includes the cost of excess natural gas not used in operations.

5	Does not include depreciation and amortization of equity investments.

TRANSCANADA [15

SECOND QUARTER 2013

Sales volumes and plant availability

Includes our share of volumes from our equity investments.

	three months ended June 30						six months ended June 30
(unaudited)	2013			2012			2013			2012

Sales volumes (GWh)
Supply
Generation
Western Power		687			654			1,357			1,325
Eastern Power1		750			907			2,096			2,050
Purchased
Sundance A & B and Sheerness PPAs2		1,788			1,295			3,495			3,334
Other purchases		-			1			-			46
		3,225			2,857			6,948			6,755
Sales
Contracted
Western Power		1,939			1,741			3,646			4,036
Eastern Power1		750			907			2,096			2,050
Spot
Western Power		536			209			1,206			669
		3,225			2,857			6,948			6,755
Plant availability3
Western Power4		92	%		97	%		94	%		98	%
Eastern Power1,5		80	%		76	%		88	%		84	%

1	Includes phase two of Cartier Wind Gros-Morne starting in November 2012 and the acquisition of the first Ontario Solar project in June 2013.

2	Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership. No volumes were delivered under the Sundance A PPA in 2012 and 2013.

3	The percentage of time the plant was available to generate power, regardless of whether it was running.

4	Does not include facilities that provide power to TransCanada under PPAs.

5	Does not include Bécancour because power generation has been suspended since 2008.

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

·	increased equity income from the ASTC Power Partnership mainly due to higher power prices

·	the Sundance A PPA force majeure arbitration charge recorded in second quarter 2012

·	higher purchased PPA volumes due to fewer outage days

·	higher realized power prices.

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

·	increased equity income from the ASTC Power Partnership mainly due to higher power prices

·	higher purchased PPA volumes due to fewer outage days

·	higher realized power prices.

In first quarter 2012, we recorded revenues and costs related to the Sundance A PPA as though the outages of Units 1 and 2 were interruptions of supply in accordance with the terms of the PPA. In July 2012, we received the Sundance A PPA arbitration decision which determined the units were in force majeure in first quarter 2012. In response, we recorded a charge of $30 million in second quarter 2012 equivalent to the pre-tax income we had recorded in first quarter 2012. Because the plant continues to be in force majeure, we will not record further revenues and costs until the units are returned to service. See Recent Developments - Energy in this MD&A for more information about the expected return to service of Units 1 and 2.

Average spot market power prices in Alberta increased by 207 per cent to $123 per MWh for the three months ended June 30, 2013 and 88 per cent to $94 per MWh for the six months ended June 30, 2013, compared to the same periods in 2012. These increases were mainly the result of plant outages and increased power demand.

TRANSCANADA [16

SECOND QUARTER 2013

Western Power’s revenue increased by $55 million for the three months ended June 30, 2013 compared to the same period in 2012 because of higher purchased PPA volumes and higher realized power prices.

Western Power’s revenue decreased by $27 million for the six months ended June 30, 2013 compared to the same period in 2012 because of the Sundance A PPA revenue recorded in first quarter 2012 offset by higher purchased PPA volumes.

Western Power’s commodity purchases resold increased by $39 million for the three months ended June 30, 2013 compared to the same period in 2012 because of higher purchased PPA volumes. Western Power’s commodity purchases resold increased by $10 million for the six months ended June 30, 2013 compared to the same period in 2012 due to higher purchased PPA volumes offset by the Sundance A PPA costs recorded in first quarter 2012.

Income from Equity Investments increased by $72 million for the three months ended June 30, 2013 and $71 million for the six months ended June 30, 2013 compared to the same periods in 2012, respectively. Higher earnings from ASTC Power Partnership, which holds the Sundance B PPA, reflected higher Alberta spot power prices and higher earnings from Portlands Energy were the result of an unplanned outage in second quarter 2012.

Plant operating costs and other, which includes natural gas fuel consumed in power generation, increased by $12 million for the three months ended June 30, 2013 and $20 million for the six months ended June 30, 2013 compared to the same periods in 2012, respectively. The increases were mainly due to higher natural gas fuel prices in 2013.

Approximately 78 per cent of Western Power sales volumes were sold under contract this quarter compared to 89 per cent in second quarter 2012. To reduce exposure to spot market prices in Alberta, Western Power enters into fixed price forward sales to secure future revenue and a portion of our power is retained to be sold in the spot market or under shorter-term forward arrangements. The amount sold forward will vary depending on market conditions and market liquidity and has historically ranged between 25 to 75 per cent of expected future production with a higher proportion being hedged in the near term periods. Such forward sales may be completed with medium and large industrial and commercial companies and other market participants and will affect our average realized price (versus spot price) in future periods.

TRANSCANADA [17

SECOND QUARTER 2013

BRUCE POWER

Our proportionate share

	three months ended June 30						six months ended June 30
(unaudited - millions of $ unless noted otherwise)	2013			2012			2013			2012

Income/(loss) from equity investments1
Bruce A		51			(23	)		87			(56	)
Bruce B		8			54			3			74
		59			31			90			18
Comprised of:
Revenues		306			185			593			347
Operating expenses		(172	)		(125	)		(344	)		(260	)
Depreciation and other		(75	)		(29	)		(159	)		(69	)
		59			31			90			18
Bruce Power - Other information
Plant availability2
Bruce A3		88	%		57	%		77	%		53	%
Bruce B		80	%		95	%		79	%		91	%
Combined Bruce Power		84	%		84	%		78	%		72	%
Planned outage days
Bruce A		33			62			123			153
Bruce B		70			-			140			46
Unplanned outage days
Bruce A		-			-			8			-
Bruce B		3			19			12			23
Sales volumes (GWh)1
Bruce A3		2,464			895			4,561			1,642
Bruce B		1,726			2,047			3,460			3,956
		4,190			2,942			8,021			5,598
Realized sales price per MWh4
Bruce A		$71			$68			$70			$67
Bruce B		$54			$56			$53			$55
Combined Bruce Power		$63			$58			$61			$58

1	Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. Sales volumes exclude deemed generation.

2	The percentage of time the plant was available to generate power, regardless of whether it was running.

3	Plant availability and sales volumes for 2013 include the incremental impact of Units 1 and 2 which were returned to service in October 2012.

4	Calculated based on actual and deemed generation. Bruce B realized sales prices per MWh includes revenues under the floor price mechanism and revenues from contract settlements.

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

·	incremental earnings from Units 1 and 2 which returned to service in October 2012

·	higher earnings from Unit 3 due to the West Shift Plus planned outage during first and second quarter 2012

·	recognition in first quarter 2013 of an insurance recovery of approximately $40 million related to the May 2012 Unit 2 electrical generator failure and the impact the event had on Bruce A in 2012 and 2013.

These increases were partially offset by the impact of the Unit 4 life extension planned outage which began in August 2012 and was completed in April 2013.

Equity income from Bruce B decreased by $46 million for the three months ended June 30, 2013 and $71 million for the six months ended June 30, 2013 compared to the same periods in 2012. These decreases were mainly due to lower volumes and higher operating costs resulting from higher planned outage days and higher lease expense.

TRANSCANADA [18

SECOND QUARTER 2013

Provisions in the Bruce B lease agreement with Ontario Power Generation provide for a reduction in annual lease expense if the annual average Ontario spot price for electricity is less than $30 per MWh. Lease expense recognized in the three and six months ended June 30, 2012 reflected an annual average spot price below $30 per MWh. At this time, it is uncertain if the annual average spot price will be below $30 per MWh in 2013 and therefore no reduction to 2013 rent expense was recorded in second quarter 2013.

Under the contract with the OPA, all of the output from Bruce A is sold at a fixed price per MWh. The fixed price is adjusted annually on April 1 for inflation and other provisions under the OPA contract. Bruce A also recovers fuel costs from the OPA.

Bruce A Fixed price	Per MWh

April 1, 2013 - March 31, 2014	$70.96
April 1, 2012 - March 31, 2013	$68.23
April 1, 2011 - March 31, 2012	$66.33

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

Bruce B Floor price	Per MWh

April 1, 2013 - March 31, 2014	$52.34
April 1, 2012 - March 31, 2013	$51.62
April 1, 2011 - March 31, 2012	$50.18

Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. We currently expect 2013 spot prices to be less than the floor price for the year and therefore no amounts received under the floor price mechanism in 2013 are expected to be repaid.

Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.

The overall plant availability percentage in 2013 is expected to be in the mid 80s for Bruce A and the high 80s for Bruce B. No further planned maintenance is scheduled for the remainder of 2013.

U.S. POWER

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

	three months ended June 30						six months ended June 30
(unaudited - millions of US $)	2013			2012			2013			2012

Revenue
Power1		317			233			750			428
Capacity		77			66			124			106
Other2		17			5			46			24
		411			304			920			558
Commodity purchases resold		(197	)		(163	)		(503	)		(280	)
Plant operating costs and other2		(122	)		(92	)		(248	)		(183	)
General, administrative and support costs		(12	)		(11	)		(22	)		(21	)
Comparable EBITDA		80			38			147			74
Comparable depreciation and amortization		(23	)		(30	)		(51	)		(60	)
Comparable EBIT		57			8			96			14

TRANSCANADA [19

SECOND QUARTER 2013

1	The realized gains and losses from financial derivatives used to buy and sell power, natural gas and fuel oil to manage U.S. Power’s assets are presented on a net basis in power revenues.

2	Includes revenues and costs related to a third party service agreement at Ravenswood, the activity level of which increased in 2013.

Sales volumes and plant availability

	three months ended June 30						six months ended June 30
(unaudited)	2013			2012			2013			2012

Physical sales volumes (GWh)
Supply
Generation		1,761			1,787			2,812			2,941
Purchased		1,878			1,687			4,357			3,257
		3,639			3,474			7,169			6,198
Plant availability1		91	%		82	%		85	%		81	%

1	The percentage of time the plant was available to generate power, regardless of whether it was running.

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

·	higher realized power prices

·	higher realized capacity prices in New York

·	higher revenues on sales to wholesale, commercial and industrial customers

·	higher operating costs due to higher fuel prices.

Commodity prices were higher for the three and six months ended June 30, 2013 compared to the same periods in 2012. In 2012, oversupply conditions in the North American natural gas market reduced these prices. In 2013, natural gas prices recovered and storage levels fell primarily due to colder first quarter weather. The increase in gas prices has translated into higher spot power prices in the predominantly gas-fired New England and New York power markets in the first half of 2013.

Physical sales volumes for the three and six months ended June 30, 2013 were higher than the same periods in 2012 due to higher purchased volumes to serve increased sales to wholesale, commercial and industrial customers in the New England and PJM markets. Generation volumes were slightly lower, mainly due to lower generation in our natural gas fueled facilities in both New York and New England partly offset by a higher generation at our hydro facilities.

Power revenue was US$317 million for the three months ended June 30, 2013 and US$750 million for the six months ended June 30, 2013 compared to US$233 million and US$428 million for the same periods in 2012. This was mainly due to the combination of higher realized power prices and higher sales volumes to wholesale, commercial and industrial customers.

Capacity revenue was US$77 million for the three months ended June 30, 2013 and US$124 million for the six months ended June 30, 2013 compared to US$66 million and US$106 million for the same periods in 2012. New York Zone J spot capacity prices are approximately 10 per cent higher than last year on a year to date basis. This increase in spot capacity prices and the impact of hedging activities resulted in higher realized prices in New York, partially offset by lower capacity prices in New England.

Commodity purchases resold were US$197 million for the three months ended June 30, 2013 and US$503 million for the six months ended June 30, 2013 compared to US$163 million and US$280 million for the same periods in 2012 because we purchased higher volumes of power at higher prices to fulfill increased power sales commitments to wholesale, commercial and industrial customers at higher realized power prices.

Plant operating costs and other, which includes fuel gas consumed in generation, increased by US$30 million for the three months ended June 30, 2013 and US$65 million for the six months ended June 30, 2013 compared to the same periods in 2012 because of higher natural gas fuel prices.

TRANSCANADA [20

SECOND QUARTER 2013

As at June 30, 2013, approximately 2,200 GWh or 44 per cent of U.S. Power’s planned generation is contracted for the remainder of 2013, and 2,500 GWh or 28 per cent for 2014. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.

NATURAL GAS STORAGE

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

	three months ended June 30						six months ended June 30
(unaudited - millions of $)	2013			2012			2013			2012

Alberta Storage1		11			19			31			34
General, administrative and support costs		(2	)		(2	)		(4	)		(4	)
Comparable EBITDA		9			17			27			30
Comparable depreciation and amortization		(2	)		(3	)		(5	)		(6	)
Comparable EBIT		7			14			22			24

1	Includes our share of equity income from our investment in CrossAlta up to December 18, 2012. On December 18, 2012, we acquired the remaining 40 per cent interest in CrossAlta, bringing our ownership interest to 100 per cent.

Comparable EBITDA decreased by $8 million for the three months ended June 30, 2013 and $3 million for the six months ended June 30, 2013 compared to the same periods in 2012 because of lower realized natural gas storage spreads partially offset by incremental earnings from CrossAlta resulting from the acquisition of the remaining 40 per cent interest in December 2012.

TRANSCANADA [21

SECOND QUARTER 2013

Recent developments

NATURAL GAS PIPELINES

NEB decision on the Canadian Restructuring Proposal

On March 27, 2013, the NEB issued its decision on our application to change the business structure and the terms and conditions of service for the Canadian Mainline, including tolls for 2012 and 2013. The decision significantly alters the regulatory framework that has formed the basis for more than $10 billion of regulated pipeline investment over the last sixty years.

On May 1, 2013, we filed an application for a review and variance of the decision and order. The NEB dismissed the review and variance application on June 11, 2013, and released its reasons for the dismissal on July 22, 2013. The NEB did however recognize that changes proposed by us to the Canadian Mainline’s Tariff would be considered as a separate application through an oral hearing process to be heard in September.

We are effectively operating under the new decision environment as of July 1. We have submitted the tariff change application and will manage that process through the oral hearing and await a decision on those changes.

NGTL System expansion projects

We continued to expand the NGTL System (formerly known as the Alberta System) and have placed $700 million of new facilities in service in 2013. We have applied and received approval from the NEB for an additional $130 million of new facilities. To date in 2013, we have applied for an additional $145 million of facilities that remain subject to NEB approval. We are planning regulatory applications for further expansion into B.C. and estimate the cost of the facilities to be between $1.0 billion and $1.5 billion to connect and transport new gas supply that will be delivered to the Prince Rupert Gas Transmission Project (PRGT) as well as other markets served by the NGTL System. In third quarter 2013, we expect to begin an open season to provide delivery service through a transportation by others arrangement on Coastal GasLink to Vanderhoof, B.C.

Prince Rupert Gas Transmission Project

The British Columbia Environmental Assessment Office issued its Section 10 Order in June 2013 indicating that the project is reviewable and requires an environmental assessment certificate. The Canadian Environmental Assessment Agency (CEAA) initiated the public comment period with respect to the project in June 2013.

Coastal GasLink Pipeline Project

We are currently focused on community, landowner, government and First Nations engagement as the Coastal GasLink pipeline project advances through the regulatory process with the B.C. Environmental Assessment Office and the CEAA.

Portland Natural Gas Transmission System

We concluded an open season in June 2013 with certain markets throughout the Northeast U.S. and Atlantic Canada expressing interest and others indicating an interest in turning back portions of our capacity. The interest generated for incremental capacity did not meet the threshold level required to go forward with an increase in capacity at this time. PNGTS continues to look for market opportunities to further develop growth of the system.

Sale of U.S. Pipeline assets to TC PipeLines, LP

In July 2013, we closed the sale of a 45 per cent interest in each of Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC (Bison LLC) to TC PipeLines, LP for an aggregate purchase price of US$1.05 billion, which included US$146 million representing 45 per cent of GTN's debt, plus closing adjustments for working capital of $17 million.

Through our subsidiaries, we continue to hold a 30 per cent direct ownership interest in both pipelines. We also hold 28.9 per cent interest in TC PipeLines, LP and are the General Partner.

TRANSCANADA [22

SECOND QUARTER 2013

Mexican Pipelines

The construction of the Tamazunchale Pipeline Extension project and related compression facilities is proceeding. The Topolobampo and Mazatlan projects in northwest Mexico are advancing as planned with engineering and permitting activities.

OIL PIPELINES

Gulf Coast Project

We are constructing a 36-inch pipeline from Cushing, Oklahoma to the U.S. Gulf Coast and expect to begin delivering crude oil to Port Arthur, Texas at the end of 2013. Construction is approximately 85 per cent complete and we estimate the cost of the Cushing to Port Arthur facilities to be US$2.3 billion.

Construction of the 76 km (47 mile) Houston Lateral pipeline to transport crude oil to Houston refineries is expected to be complete in 2014 at a cost of US$300 million.

The Gulf Coast Project will have a capacity of up to 700,000 barrels per day.

Keystone XL Pipeline

In January 2013, the Governor of Nebraska approved our proposed re-route after the Nebraska Department of Environmental Quality issued its final evaluation report noting that construction and operation of Keystone XL is expected to have minimal environmental impacts in Nebraska.

On March 1, 2013, the U.S. DOS released its Draft Supplemental Environmental Impact Statement for the Keystone XL Pipeline. The impact statement reaffirmed that construction of the proposed pipeline from the U.S./Canada border in Montana to Steele City, Nebraska would not result in any significant impact to the environment. The DOS continues to review comments on the impact statement that it received during a public comment period that ended on April 22, 2013. Once the DOS has completed its review, it is anticipated it will issue a Final Supplemental Environmental Impact Statement and then consult with other governmental agencies and provide an additional opportunity for the public comment during a National Interest Determination period of up to 90 days, before making a decision on our Presidential Permit application.

We now anticipate the pipeline to be in service approximately two years following the receipt of the Presidential Permit. The US$5.3 billion cost estimate will increase depending on the timing of the permit. As of June 30, 2013, we had invested US$1.9 billion in the project.

Energy East Pipeline

On June 17, 2013, we concluded an open season to obtain firm commitments for a pipeline to transport up to 850,000 Bbl/d of crude oil from western receipt points to eastern Canadian markets and are currently reviewing the results.

The Energy East Pipeline project involves converting natural gas pipeline capacity in approximately 3,000 km (1,870 miles) of our existing Canadian Mainline to crude oil service and constructing up to approximately 1,400 km (870 miles) of new pipeline.

We have begun Aboriginal and stakeholder engagement and associated field work as part of our initial design and planning. If we determine that there is sufficient commercial support for the project, we will apply for regulatory approval to build and operate the facilities, with a potential in-service date of late 2017.

Northern Courier Pipeline

On April 25, 2013, we filed a permit application with the Alberta Energy Regulator after completing the required Aboriginal and stakeholder engagement and associated field work. We continue to work with the Fort Hills Energy Limited Partnership on the development of this project.

Heartland Pipeline and TC Terminals

On May 2, 2013, we announced we had reached binding long-term shipping agreements to build, own and operate the proposed Heartland Pipeline and TC Terminals projects.

The proposed projects will include a 200 km (125 mile) crude oil pipeline connecting the Edmonton region to facilities in Hardisty, Alberta, and a terminal facility in the Heartland industrial area north of Edmonton. We anticipate the pipeline could transport up to 900,000 Bbl/d, while the terminal is expected to have storage capacity for up to 1.9 million barrels of crude oil. These projects together have a combined cost estimated at $900 million and are expected to come into service during the second half of 2015.

TRANSCANADA [23

SECOND QUARTER 2013

On May 30, 2013, we filed a permit application for the terminal facility with the Alberta Energy Regulator and expect to file an application for the pipeline later in 2013.

Grand Rapids Pipeline

On May 23, 2013, we filed a permit application with the Alberta Energy Regulator after completing the required Aboriginal and stakeholder engagement and associated field work.

ENERGY

Ontario Solar

In late 2011, we agreed to buy nine Ontario solar projects (combined capacity of 86 MW) from Canadian Solar Solutions Inc. for approximately $470 million. On June 28, 2013, we completed the acquisition of the first project for $55 million. We expect to close the acquisition of the remaining projects in 2013 and 2014, subject to satisfactory completion of the related construction activities and regulatory approvals. All power produced will be sold under 20-year PPAs with the OPA.

Sundance A

TransAlta previously announced that it expected Sundance A Units 1 and 2 to be returned to service in the fall of 2013. They subsequently reported an earlier return to service date for Unit 1 of July 31, 2013. TransAlta has not announced any change in the return to service date for Unit 2.

Bruce Power

Bruce Power returned Unit 4 to service on April 13, 2013 after completing an expanded life extension outage investment program which began in August 2012. It is anticipated that this investment will allow Unit 4 to operate until at least 2021.

On April 5, 2013, Bruce Power announced that it had reached an agreement with the OPA to extend the Bruce B floor price through to the end of the decade which is expected to coincide with the 2019 and 2020 end of life dates for the Bruce B units.

Bécancour

In June 2013, Hydro-Québec notified us that it would exercise its option to extend the agreement to suspend all electricity generation from the Bécancour power plant through 2014. Under the suspension agreement, Hydro-Québec has the option (subject to certain conditions) to extend the suspension every year until regional electricity demand levels recover. We continue to receive capacity payments while generation is suspended.

TRANSCANADA [24

SECOND QUARTER 2013

Other income statement items

	three months ended June 30						six months ended June 30
(unaudited - millions of $)	2013			2012			2013			2012

Comparable interest expense		(252	)		(239	)		(509	)		(481	)
Comparable interest income and other		(2	)		19			16			44
Comparable income taxes		(133	)		(91	)		(292	)		(231	)
Net income attributable to non-controlling interests		(23	)		(26	)		(54	)		(61	)

	three months ended June 30						six months ended June 30
(unaudited - millions of $)	2013			2012			2013			2012

Comparable interest on long-term debt (including interest on junior subordinated notes)
Canadian dollar-denominated		123			127			245			255
U.S. dollar-denominated (US$)		185			183			373			369
Foreign exchange		5			-			6			-
		313			310			624			624
Other interest and amortization expense		(1	)		5			-			7
Capitalized interest		(60	)		(76	)		(115	)		(150	)
Comparable interest expense		252			239			509			481

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

·	lower capitalized interest as a result of placing the refurbished units at Bruce Power in service, partially offset by increased capitalized interest for the Gulf Coast Project

·	lower interest expense due to Canadian and U.S. dollar-denominated debt maturities, partially offset by debt issues of US$750 million in January 2013, US$1 billion in August 2012 and US$500 million in March 2012.

Comparable interest income and other was a loss of $2 million for the three months ended June 30, 2013 and a gain of $16 million for the six months ended June 30, 2013 compared to gains of $19 million and $44 million for the same periods in 2012 because we had realized losses in 2013 compared to realized gains in 2012 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Comparable income taxes were $133 million for the three months ended June 30, 2013 and $292 million for the six months ended June 30, 2013 compared to $91 million and $231 million for the same periods in 2012. The increase was mainly the result of higher pre-tax earnings in 2013 compared to 2012 combined with changes in the proportion of income earned between Canadian and foreign jurisdictions.

TRANSCANADA [25

SECOND QUARTER 2013

Financial condition

We strive to maintain financial strength and flexibility in all parts of an economic cycle, and rely on our operating cash flows to sustain our business, pay dividends and fund a portion of our growth.

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

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

CASH FROM OPERATING ACTIVITIES

	three months ended June 30					six months ended June 30
(unaudited - millions of $)	2013			2012		2013			2012

Funds generated from operations1		955			729		1,871			1,600
(Increase)/decrease in operating working capital		(114	)		14		(324	)		(155	)
Net cash provided by operations		841			743		1,547			1,445

1	See the non-GAAP measures section in this MD&A for further discussion of funds generated from operations.

Net cash provided by operations was $841 million for the three months ended June 30, 2013 and $1,547 million for the six months ended June 30, 2013 compared to $743 million and $1,445 million for the same periods in 2012, respectively, as a result of our increase in earnings, partly offset by increases in operating working capital.

At June 30, 2013, our current assets were $2.8 billion and current liabilities were $6.7 billion, leaving us with a working capital deficit of $3.9 billion compared to $3.1 billion at the end of 2012. This working capital deficiency is considered to be in the normal course of business and is managed through our ability to generate cash flow and our ongoing access to the capital markets.

CASH USED IN INVESTING ACTIVITIES

	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2013		2012		2013		2012

Capital expenditures		1,109		397		2,038		861
Equity investments		39		197		71		413
Acquisition		55		-		55		-

Our capital expenditures this quarter were primarily related to the Gulf Coast Project, expansion of the NGTL System and construction of the Mexican pipelines.

On June 28, 2013, we completed the acquisition of the first Ontario Solar project for $55 million.

TRANSCANADA [26

SECOND QUARTER 2013

CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES

	three months ended June 30						six months ended June 30
(unaudited - millions of $)	2013			2012			2013			2012

Long-term debt issued, net of issue costs		10			1			744			493
Long-term debt repaid		(695	)		(222	)		(709	)		(770	)
Notes payable issued, net		1,388			635			559			589
Dividends and distributions paid		(386	)		(359	)		(736	)		(702	)
Equity financing activities		406			4			1,024			18

In January 2013, we issued US$750 million of senior notes, maturing on January 15, 2016 and bearing interest at 0.75 per cent. These notes were issued under the US$4.0 billion debt shelf prospectus filed in November 2011.

In March 2013, we completed a public offering of 24 million Series 7 cumulative redeemable first preferred shares at a price of $25 per share for aggregate gross proceeds of $600 million. Investors will be entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly. Investors will have the right to convert their shares into cumulative redeemable first preferred shares, Series 8, every fifth year beginning on April 30, 2019. The holders of Series 8 shares will be entitled to receive quarterly floating rate cumulative dividends at an annualized rate equal to the then 90 day Government of Canada treasury bill rate plus 2.38 per cent.

In June 2013, we retired $350 million of 4.00 per cent senior notes.

In July 2013, we issued US$500 million of three-year London Interbank Offered Rate-based floating rate notes maturing on June 30, 2016, bearing interest at an initial annual rate of 0.95 per cent.

Also in July 2013, we issued $450 million of ten-year and $300 million of 30-year medium term notes maturing on July 19, 2023 and November 15, 2041, bearing interest rates of 3.69 and 4.55 per cent per annum, respectively. The net proceeds of these offerings are intended to be used for general corporate purposes and to reduce short-term indebtedness, which was used to fund a portion of our capital program.

In May 2013, TC PipeLines, LP completed a public offering of 8,855,000 common units at US$43.85 per common unit for gross proceeds of US$388 million. We contributed an additional approximate US$8 million to maintain our general partnership interest and did not purchase any other units. Upon completion of this offering, our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent.

In July 2013, TC PipeLines, LP entered into a five-year, US$500 million term loan, maturing July 2018. The proceeds from the public offering, term loan and partner contribution were used to finance the acquisition of the 45 per cent interest in GTN and Bison from us.

TRANSCANADA [27

SECOND QUARTER 2013

DIVIDENDS

On July 25, 2013 we declared quarterly dividends as follows:

Quarterly dividend on our common shares

$0.46 per share (for the quarter ending September 30, 2013)

Payable on October 31, 2013 to shareholders of record at the close of business on September 30, 2013

Quarterly dividends on our preferred shares

Series 1 $0.2875 (for the quarter ending September 30, 2013)

Series 3 $0.25 (for the quarter ending September 30, 2013)

Payable on September 30, 2013 to shareholders of record at the close of business on September 3, 2013

Series 5 $0.275 (for the three month period ending October 30, 2013)

Series 7 $0.25 (for the three month period ending October 30, 2013)

Payable on October 30, 2013 to shareholders of record at the close of business on September 30, 2013

SHARE INFORMATION

at July 22, 2013

Common shares	Issued and outstanding
	707 million
Preferred shares	Issued and outstanding	Convertible to
Series 1	22 million	22 million Series 2 preferred shares
Series 3	14 million	14 million Series 4 preferred shares
Series 5	14 million	14 million Series 6 preferred shares
Series 7	24 million	24 million Series 8 preferred shares
Options to buy common shares	Outstanding	Exercisable
	8 million	4 million

CREDIT FACILITIES

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

At June 30, 2013, we had $5 billion in unsecured credit facilities, including:

Amount	Unused capacity	Subsidiary	For	Matures

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

TRANSCANADA [28

SECOND QUARTER 2013

See Risks and financial instruments for more information about liquidity, market and other risks.

CONTRACTUAL OBLIGATIONS

Our capital commitments have decreased by $600 million primarily due to the completion or advancement of capital projects. Our other purchase commitments decreased by $180 million. There were no other material changes to our contractual obligations in second quarter 2013 or to payments due in the next five years or after. See the MD&A in our 2012 Annual Report for more information about our contractual obligations.

TRANSCANADA [29

SECOND QUARTER 2013

Financial risks and financial instruments

We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and ultimately shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance.

Please see our 2012 Annual Report for more information about the risks we face in our business. In addition to those disclosed risks, in the NEB’s March 2013 decision on our Canadian Restructuring Proposal, the NEB found that the fundamental business risk facing the Canadian Mainline has increased. The tolling framework created by the NEB decision results in higher variability in cash flows and greater uncertainty about the ultimate recovery of the Canadian Mainline’s cost of service. Otherwise, our risks have not changed substantially since December 31, 2012.

LIQUIDITY RISK

We manage our liquidity risk by continuously forecasting our cash requirements for a 12 month period and making sure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.

COUNTERPARTY CREDIT RISK

We have exposure to counterparty credit risk in the following areas:

·	accounts receivable

·	portfolio investments

·	the fair value of derivative assets

·	notes, loans and advances receivable.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At June 30, 2013, we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration of $263 million with one counterparty at June 30, 2013 (December 31, 2012 - $259 million). This amount is secured by a guarantee from the counterparty’s parent company and we anticipate collecting the full amount.

We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.

FOREIGN EXCHANGE RISK

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

We use foreign exchange derivatives to manage other foreign exchange transactions, including foreign exchange exposures that arise on some of our regulated assets. We defer some of the realized gains and losses on these derivatives as regulatory assets and liabilities until we recover or pay them to shippers according to the terms of the shipping agreements.

AVERAGE EXCHANGE RATE - U.S. TO CANADIAN DOLLARS

Second quarter 2013	1.03
Second quarter 2012	1.01

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

TRANSCANADA [30

SECOND QUARTER 2013

SIGNIFICANT U.S. DOLLAR-DENOMINATED AMOUNTS

	three months ended June 30						six months ended June 30
(unaudited - millions of US$)	2013			2012			2013			2012

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

NET INVESTMENT IN FOREIGN OPERATIONS

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

	June 30, 2013				December 31, 2012
Asset/(liability) (unaudited - millions of $)	Fair value1			Notional amount	Fair value1		Notional amount

U.S. dollar cross-currency swaps
(maturing 2013 to 2019)2		(137	)	US 3,900		82	US 3,800
U.S. dollar forward foreign exchange contracts
(maturing 2013 to 2014)		(29	)	US 1,050		-	US 250
		(166	)	US 4,950		82	US 4,050

1	Fair values equal carrying values.

2	Net Income in the three and six months ended June 30, 2013 included net realized gains of $7 million and $14 million, respectively, (2012 - gains of $7 million and $14 million, respectively) related to the interest component of cross-currency swap settlements.

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

(unaudited - billions of $)	June 30, 2013	December 31, 2012

Carrying value	12.2 (US 11.7)	11.1 (US 11.2)
Fair value	14.2 (US 13.5)	14.3 (US 14.4)

FAIR VALUE OF DERIVATIVES USED TO HEDGE OUR

U.S. DOLLAR INVESTMENT IN FOREIGN OPERATIONS

The classification of the fair value of derivatives to hedge our net investments on the balance sheet.

(unaudited - millions of $)	June 30, 2013		December 31, 2012

Other current assets		30		71
Intangible and other assets		2		47
Accounts payable and other		52		6
Other long-term liabilities		146		30

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SECOND QUARTER 2013

NON-DERIVATIVE FINANCIAL INSTRUMENTS SUMMARY

	June 30, 2013				December 31, 2012
(unaudited - millions of $)	Carrying amount1		Fair value2		Carrying amount1		Fair value2

Financial assets
Cash and cash equivalents		674		674		551		551
Accounts receivable and other3		1,301		1,350		1,288		1,337
Available for sale assets		47		47		44		44
		2,022		2,071		1,883		1,932
Financial liabilities4
Notes payable		2,900		2,900		2,275		2,275
Accounts payable and other long-term liabilities5		1,114		1,114		1,535		1,535
Accrued interest		380		380		368		368
Long-term debt		19,699		23,474		18,913		24,573
Junior subordinated notes		1,050		1,105		994		1,054
		25,143		28,973		24,085		29,805

Recorded at amortized cost, except for US$200 million (December 31, 2012 - US$350 million) of long-term debt that is attributed to hedged risk and recorded at fair value. This debt, which is recorded at fair value on a recurring basis, is classified in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers.

2	The fair value measurement of financial assets and liabilities recorded at amortized cost for which the fair value is not equal to the carrying value would be included in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers.

3	At June 30, 2013, financial assets of $1.1 billion (December 31, 2012 - $1.1 billion) are included in accounts receivable, $72 million (December 31, 2012 - $40 million) in other current assets and $225 million (December 31, 2012 - $240 million) in intangible and other assets.

Condensed consolidated statement of income in the three and six months ended June 30, 2013 included gains of $3 million and losses of $7 million, respectively, (2012 - gains of $3 million and losses of $12 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$200 million of long-term debt at June 30, 2013 (December 31, 2012 - US$350 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

5	At June 30, 2013, financial liabilities of $1.1 billion (December 31, 2012 - $1.5 billion) are included in accounts payable and $36 million (December 31, 2012 - $38 million) in other long-term liabilities.

TRANSCANADA [32

SECOND QUARTER 2013

DERIVATIVE INSTRUMENTS SUMMARY

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

2013 (unaudited - millions of $ unless noted otherwise)	Power			Natural gas			Foreign exchange			Interest

Derivative instruments held for trading1
Fair values2
Assets		$141			$70			$-			$11
Liabilities		$(183	)		$(99	)		$(17	)		$(11	)
Notional values
Volumes3
Sales		35,445			64			-			-
Purchases		34,750			102			-			-
Canadian dollars		-			-			-			620
U.S. dollars		-			-		US 1,274			US 200
Net unrealized gains/(losses) in the period4
three months ended June 30, 2013		$5			$(21	)		$(10	)		$-
six months ended June 30, 2013		$(3	)		$(12	)		$(16	)		$-
Net realized losses in the period4
three months ended June 30, 2013		$(29	)		$(5	)		$(6	)		$-
six months ended June 30, 2013		$(36	)		$(7	)		$(7	)		$-
Maturity dates		2013-2017			2013-2016			2013-2014			2013-2016
Derivative instruments in hedging relationships5, 6
Fair values2
Assets		$37			$-			$-			$7
Liabilities		$(103	)		$(1	)		$(1	)		$-
Notional values
Volumes3
Sales		6,283			-			-			-
Purchases		13,206			-			-			-
U.S. dollars		-			-		US 15			US 200
Cross-currency		-			-			-			-
Net realized (losses)/gains in the period4
three months ended June 30, 2013		$(84	)		$(1	)		$-			$2
six months ended June 30, 2013		$(11	)		$(1	)		$-			$4
Maturity dates		2013-2018			2013			2014			2015

All derivative instruments held for trading have been entered into for risk management purposes and are subject to our risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage our exposure to market risk.

2	Fair values equal carrying values.

3	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

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.

All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $7 million and a notional amount of US$200 million. For the three and six months ended June 30, 2013, net realized gains on fair value hedges were $2 million and $4 million, respectively, and were included in interest expense. For the three and six months ended June 30, 2013, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

6	For the three and six months ended June 30, 2013, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

TRANSCANADA [33

SECOND QUARTER 2013

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

2012 (unaudited - millions of $ unless noted otherwise)	Power			Natural gas			Foreign exchange			Interest

Derivative instruments held for trading1
Fair values2,3
Assets		$139			$88			$1			$14
Liabilities		$(176	)		$(104	)		$(2	)		$(14	)
Notional values3
Volumes4
Sales		31,066			65			-			-
Purchases		31,135			83			-			-
Canadian dollars		-			-			-			620
U.S. dollars		-			-		US 1,408			US 200
Net unrealized (losses)/gains in the period5
three months ended June 30, 2012		$(12	)		$4			$(14	)		$-
six months ended June 30, 2012		$(19	)		$(10	)		$(8	)		$-
Net realized (losses)/gains in the period5
three months ended June 30, 2012		$(6	)		$(5	)		$6			$-
six months ended June 30, 2012		$9			$(15	)		$15			$-
Maturity dates		2013 -2017			2013-2016			2013			2013-2016
Derivative instruments in hedging relationships 6,7
Fair values2,3
Assets		$76			$-			$-			$10
Liabilities		$(97	)		$(2	)		$(38	)		$-
Notional values3
Volumes4
Sales		7,200			-			-			-
Purchases		15,184			1			-			-
U.S. dollars		-			-		US 12			US 350
Cross-currency		-			-		136/US 100				-
Net realized (losses)/gains in the period5
three months ended June 30, 2012		$(26	)		$(8	)		$-			$2
six months ended June 30, 2012		$(58	)		$(14	)		$-			$3
Maturity dates		2013-2018			2013			2013-2014			2013-2015

All derivative instruments held for trading have been entered into for risk management purposes and are subject to our risk management strategies, policies and limits. This includes derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage our exposure to market risk.

2	Fair values equal carrying values.

3	As at December 31, 2012.

4	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $10 million and a notional amount of US$350 million. Net realized gains on fair value hedges for the three and six months ended June 30, 2012 were $2 million and $4 million, respectively, and were included in Interest expense. In the three and six months ended June 30, 2012, we did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

7	For the three and six months ended June 30, 2012, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

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SECOND QUARTER 2013

BALANCE SHEET PRESENTATION OF DERIVATIVE INSTRUMENTS

The fair value of the derivative instruments on the balance sheet.

(unaudited - millions of $)	June 30, 2013	December 31, 2012

Current
Other current assets	187	259
Accounts payable and other	(341)	(283)
Long term
Intangible and other assets	111	187
Other long-term liabilities	(272)	(186)

DERIVATIVES IN CASH FLOW HEDGING RELATIONSHIPS

The components of other comprehensive income (OCI) related to derivatives in cash flow hedging relationships.

Cash flow hedges1 three months ended June 30	Power					Natural gas					Foreign exchange				Interest
(unaudited – millions of $, pre-tax)	2013			2012		2013		2012			2013		2012		2013		2012

Change in fair value of derivative instruments recognized in OCI (effective portion)		(70	)		44		-		(4	)		2		4		-		-
Reclassification of gains and losses on derivative instruments from AOCI to net income (effective portion)		12			28		2		15			-		-		4		4
Gains and losses on derivative instruments recognized in earnings (ineffective portion)		(2	)		7		-		1			-		-		-		-

1	No amounts have been excluded from the assessment of hedge effectiveness.

Cash flow hedges1 six months ended June 30	Power						Natural gas					Foreign exchange				Interest
(unaudited – millions of $, pre-tax)	2013			2012			2013		2012			2013		2012		2013		2012

Change in fair value of derivative instruments recognized in OCI (effective portion)		(34	)		(22	)		-		(14	)		4		1		-		-
Reclassification of gains and losses on derivative instruments from AOCI to net income (effective portion)		1			75			2		28			-		-		8		10
Gains and losses on derivative instruments recognized in earnings (ineffective portion)		(7	)		1			-		(1	)		-		-		-		-

1	No amounts have been excluded from the assessment of hedge effectiveness.

CREDIT RISK RELATED CONTINGENT FEATURES

Derivatives contracts often contain financial assurance provisions that may require us to provide collateral if a credit risk-related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade).

Based on contracts in place and market prices at June 30, 2013, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $36 million (December 31, 2012 - $37 million), with collateral provided in the normal course of business of nil (December 31, 2012 – nil). If the credit-risk-related contingent features in these agreements had been triggered on June 30, 2013, we would have been required to provide collateral of $36 million (December 31, 2012 - $37 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

TRANSCANADA [35

SECOND QUARTER 2013

We feel we have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

FAIR VALUE HIERARCHY

Assets and liabilities that are recorded at fair value are required to be categorized into three levels based on the fair value hierarchy.

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

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

	Quoted prices in active markets (Level I)1						Significant other observable inputs (Level II)1,2						Significant unobservable inputs (Level III)2						Total
(unaudited – millions of $, pre-tax)	Jun 30, 2013			Dec 31, 2012			Jun 30, 2013			Dec 31, 2012			Jun 30, 2013			Dec 31, 2012			Jun 30, 2013			Dec 31, 2012

Derivative instrument assets:
Power commodity contracts		-			-			171			213			7			2			178			215
Natural gas commodity contracts		65			75			5			13			-			-			70			88
Foreign exchange contracts		-			-			32			119			-			-			32			119
Interest rate contracts		-			-			18			24			-			-			18			24
Derivative instrument liabilities:
Power commodity contracts		-			-			(279	)		(269	)		(7	)		(4	)		(286	)		(273	)
Natural gas commodity contracts		(85	)		(95	)		(15	)		(11	)		-			-			(100	)		(106	)
Foreign exchange contracts		-			-			(216	)		(76	)		-			-			(216	)		(76	)
Interest rate contracts		-			-			(11	)		(14	)		-			-			(11	)		(14	)
Non-derivative financial instruments:
Available for sale assets		-			-			47			44			-			-			47			44
		(20	)		(20	)		(248	)		43			-			(2	)		(268	)		21

1	There were no transfers between Level I and Level II for the six months ended June 30, 2013 and 2012.

2	There were no transfers between Level II and Level III for the six months ended June 30, 2013 and 2012.

TRANSCANADA [36

SECOND QUARTER 2013

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

	Derivatives1
	three months ended June 30						six months ended June 30
(unaudited - millions of $, pre-tax)	2013			2012			2013			2012

Balance at beginning of period		1			(11	)		(2	)		(15	)
Settlements		1			(1	)		1			(1	)
Transfers out of Level III		(1	)		1			(1	)		1
Total (losses)/gains included in OCI		(1	)		18			2			22
Balance at end of period		-			7			-			7

1	For the three and six months ended June 30, 2013, the unrealized gains or losses included in net income attributed to derivatives in the level III category that were still held at the reporting date was nil (2012 - nil).

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

TRANSCANADA [37

SECOND QUARTER 2013

Other information

CONTROLS AND PROCEDURES

Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at June 30, 2013, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

There were no changes in second quarter 2013 that had or are likely to have a material impact on our internal control over financial reporting.

Management is in the process of implementing an Enterprise Resource Planning (ERP) system that will likely affect some processes supporting internal control over financial reporting. The phased implementation period, originally planned to begin July 1, 2013, has been deferred to January 2014.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, AND ACCOUNTING CHANGES

When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgment. We also regularly assess the assets and liabilities themselves.

Our significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2012 other than described below. You can find a summary of our significant accounting policies and critical accounting estimates in our 2012 Annual Report.

Changes in accounting policies for 2013

Balance sheet offsetting/netting

Effective January 1, 2013, we adopted the ASU on disclosures about balance sheet offsetting as issued by the FASB to enable understanding of the effects of netting arrangements on our financial position. Adoption of the ASU has resulted in increased qualitative and quantitative disclosures about certain derivative instruments that are either offset in accordance with current U.S. GAAP or are subject to a master netting arrangement or similar agreement.

Accumulated other comprehensive income

Effective January 1, 2013, we adopted the ASU on reporting of amounts reclassified out of AOCI as issued by the FASB. Adoption of the ASU has resulted in providing additional qualitative and quantitative disclosures about significant amounts reclassified out of AOCI into net income.

Future accounting changes

Obligations resulting from joint and several liability arrangements

In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This ASU is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013. We are evaluating the impact that adopting the ASU would have on our consolidated financial statements, but do not expect it to be material.

Foreign currency matters - cumulative translation adjustment

In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This ASU is effective prospectively for fiscal years, and interim reporting periods within those years, beginning after December 15, 2013. Early adoption is allowed as of the beginning of the entity's fiscal year. We are evaluating the impact that adopting this ASU would have on our consolidated financial statements, but do not expect it to be material.

TRANSCANADA [38

SECOND QUARTER 2013

QUARTERLY RESULTS

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA

	2013				2012								2011
(unaudited - millions of $, except per share amounts)	Second		First		Fourth		Third		Second		First		Fourth		Third

Revenues		2,009		2,252		2,089		2,126		1,847		1,945		2,015		2,043
Net income attributable to common shares		365		446		306		369		272		352		376		386
Share Statistics
Net Income per common share - basic and diluted		$0.52		$0.63		$0.43		$0.52		$0.39		$0.50		$0.53		$0.55
Dividend declared per common share		$0.46		$0.46		$0.44		$0.44		$0.44		$0.44		$0.42		$0.42

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT

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

In Natural Gas Pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:

·	regulators' decisions

·	negotiated settlements with shippers

·	seasonal fluctuations in short-term throughput volumes on U.S. pipelines

·	acquisitions and divestitures

·	developments outside of the normal course of operations

·	newly constructed assets being placed in service.

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

In Energy, quarter-over-quarter revenues and net income are affected by:

weather

·	customer demand

·	market prices

·	capacity prices and payments

·	planned and unplanned plant outages

·	acquisitions and divestitures

·	certain fair value adjustments

·	developments outside of the normal course of operations

·	newly constructed assets being placed in service.

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER

Second quarter 2013

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

First quarter 2013

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

Fourth quarter 2012

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

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SECOND QUARTER 2013

Third quarter 2012

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

Second quarter 2012

·	EBIT included a $20 million pre-tax charge ($15 million after-tax) related to 2011 from the Sundance A PPA arbitration decision and net unrealized losses of $14 million pre-tax ($13 million after-tax) from certain risk management activities.

First quarter 2012

·	EBIT included net unrealized losses of $22 million pre-tax ($11 million after-tax) from certain risk management activities.

Fourth quarter 2011

·	EBIT included net unrealized gains of $13 million pre-tax ($11 million after-tax) from certain risk management activities.

Third quarter 2011

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