TC Energy 6K TransCanada Reports Solid Second Quarter Results | TRP 31 Jul 14

EXHIBIT 13.1

Quarterly report to shareholders

Second quarter 2014

Financial highlights



	three months ended June 30						six months ended June 30
(unaudited - millions of $, except per share amounts)	2014			2013			2014			2013

Income
Revenue	2,234			2,009			5,118			4,261
Net income attributable to common shares	416			365			828			811
per common share - basic and diluted		$0.59			$0.52			$1.17			$1.15
Comparable EBITDA¹	1,217			1,143			2,613			2,311
Comparable earnings¹	332			357			754			727
per common share¹		$0.47			$0.51			$1.07			$1.03

Operating cash flow
Funds generated from operations¹	917			955			2,019			1,871
Decrease/(increase) in operating working capital	202			(114		)	79			(324		)
Net cash provided by operations	1,119			841			2,098			1,547
Investing activities
Capital expenditures	(967		)	(1,109		)	(1,745		)	(2,038		)
Equity investments	(40		)	(39		)	(129		)	(71		)
Acquisitions	—			(55		)	—			(55		)
Proceeds from sale of assets, net of transaction costs	187			—			187			—
Dividends paid
Per common share		$0.48			$0.46			$0.96			$0.92
Basic common shares outstanding (millions)
Average for the period	708			707			708			706
End of period	708			707			708			707


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

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SECOND QUARTER 2014

Management’s discussion and analysis

July 31, 2014

This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and six months ended June 30, 2014, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2014 which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2013 audited consolidated financial statements and notes and the MD&A in our 2013 Annual Report, which have been prepared in accordance with U.S. GAAP.

About this document

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

Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2013 Annual Report.

All information is as of July 31, 2014 and all amounts are in Canadian dollars, unless noted otherwise.

FORWARD-LOOKING INFORMATION

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

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

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


•	anticipated business prospects


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


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


•	expected cash flows and future financing options available to us


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


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


•	expected regulatory processes and outcomes


•	expected impact of regulatory outcomes


•	expected outcomes with respect to legal proceedings, including arbitration


•	expected capital expenditures and contractual obligations


•	expected operating and financial results


•	the expected impact of future accounting changes, commitments and contingent liabilities


•	expected industry, market and economic conditions.

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

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

Assumptions


•	inflation rates, commodity prices and capacity prices


•	timing of financings and hedging


•	regulatory decisions and outcomes


•	foreign exchange rates


•	interest rates


•	tax rates


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


•	integrity and reliability of our assets


•	access to capital markets


•	anticipated construction costs, schedules and completion dates


•	acquisitions and divestitures.

Risks and uncertainties


•	our ability to successfully implement our strategic initiatives


•	whether our strategic initiatives will yield the expected benefits


•	the operating performance of our pipeline and energy assets

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SECOND QUARTER 2014


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


•	the availability and price of energy commodities


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


•	regulatory decisions and outcomes


•	outcomes of legal proceedings, including arbitration


•	performance of our counterparties


•	changes in the political environment


•	changes in environmental and other laws and regulations


•	competitive factors in the pipeline and energy sectors


•	construction and completion of capital projects


•	costs for labour, equipment and materials


•	access to capital markets


•	interest and foreign exchange rates


•	weather


•	cyber security


•	technological developments


•	economic conditions in North America as well as globally.

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

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

FOR MORE INFORMATION

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

NON-GAAP MEASURES

We use the following non-GAAP measures:


•	EBITDA


•	EBIT


•	funds generated from operations


•	comparable earnings


•	comparable earnings per common share


•	comparable EBITDA


•	comparable EBIT


•	comparable depreciation and amortization


•	comparable interest expense


•	comparable interest income and other


•	comparable income tax expense.

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

EBITDA and EBIT

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

Funds generated from operations

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

Comparable measures

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

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SECOND QUARTER 2014



Comparable measure	Original measure

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

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


•	certain fair value adjustments relating to risk management activities


•	income tax refunds and adjustments


•	gains or losses on sales of assets


•	legal, contractual and bankruptcy settlements


•	impact of regulatory or arbitration decisions relating to prior year earnings


•	write-downs of assets and investments.

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

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SECOND QUARTER 2014

Consolidated results - second quarter 2014



	three months ended June 30				six months ended June 30
(unaudited - millions of $, except per share amounts)	2014		2013		2014		2013

Natural gas pipelines	496		399		1,082		947
Liquids pipelines¹	195		149		387		291
Energy	216		243		473		442
Corporate	(27	)	(22	)	(70	)	(59	)
Total segmented earnings	880		769		1,872		1,621
Interest expense	(297	)	(252	)	(571	)	(510	)
Interest income and other	54		(11	)	46		2
Income before income taxes	637		506		1,347		1,113
Income tax expense	(165	)	(98	)	(386	)	(213	)
Net income	472		408		961		900
Net income attributable to non-controlling interests	(31	)	(23	)	(85	)	(54	)
Net income attributable to controlling interests	441		385		876		846
Preferred share dividends	(25	)	(20	)	(48	)	(35	)
Net income attributable to common shares	416		365		828		811

Net income per common share - basic and diluted	$0.59		$0.52		$1.17		$1.15


1	Previously Oil Pipelines.

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


•	a gain on sale of Cancarb Limited and its related power generation business of $99 million after tax


•	a net loss resulting from the termination of a contract with Niska Gas Storage of $31 million after tax.

Second quarter 2013 results included a $25 million favourable income tax adjustment due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax in June 2013.

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


•	a gain on sale of Cancarb Limited and its related power generation business of $99 million after tax


•	a net loss resulting from a termination payment to Niska Gas Storage for contract restructuring of $31 million after tax.

The results for the first six months of 2013 included $84 million of Canadian Mainline net income related to 2012 from the NEB decision (RH-003-2011) as well as a $25 million favourable income tax adjustment due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax in June 2013.

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

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SECOND QUARTER 2014

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS



	three months ended June 30				six months ended June 30
(unaudited - millions of $, except per share amounts)	2014		2013		2014		2013

Net income attributable to common shares	416		365		828		811
Specific items (net of tax):
Energy - Cancarb gain on sale	(99	)	—		(99	)	—
Energy - Niska contract termination	31		—		31		—
Risk management activities¹	(16	)	17		(6	)	25
Natural gas pipelines - NEB decision - 2012	—		—		—		(84	)
Part VI.I income tax adjustment	—		(25	)	—		(25	)
Comparable earnings	332		357		754		727

Net income per common share	$0.59		$0.52		$1.17		$1.15
Specific items (net of tax):
Energy - Cancarb gain on sale	(0.14	)	—		(0.14	)	—
Energy - Niska contract termination	0.04		—		0.04		—
Risk management activities¹	(0.02	)	0.03		—		0.04
Natural gas pipeline - NEB decision - 2012	—		—		—		(0.12	)
Part VI.I income tax adjustment	—		(0.04	)	—		(0.04	)
Comparable earnings per share	$0.47		$0.51		$1.07		$1.03



1	Risk management activities	three months ended June 30				six months ended June 30
	(unaudited - millions of $)	2014		2013		2014		2013

	Canadian Power	(2	)	(4	)	(2	)	(6	)
	U.S. Power	(9	)	(18	)	(11	)	(17	)
	Natural gas Storage	6		4		(3	)	1
	Foreign exchange	25		(9	)	23		(15	)
	Income tax attributable to risk management activities	(4	)	10		(1	)	12
	Total gains/(losses) from risk management activities	16		(17	)	6		(25	)

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

This was primarily the net effect of the following:


•	incremental earnings from the Gulf Coast extension of the Keystone Pipeline System


•	lower earnings from Western Power as a result of lower realized power prices


•	lower equity income from Bruce Power mainly due to increased planned and unplanned outage days at Bruce A, partially offset by fewer outage days at Bruce B


•	higher earnings from Mexico pipelines resulting from contract revenues recognized from the Tamazunchale Extension.

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

This was primarily the net effect of:


•	incremental earnings from the Gulf Coast extension of the Keystone Pipeline System


•	lower earnings from Western Power as a result of lower realized power prices


•	higher earnings from U.S. Power mainly because of higher realized capacity and power prices


•	higher earnings from Mexico pipelines resulting from contract revenues recognized from the Tamazunchale Extension


•	higher earnings from U.S. natural gas pipelines due to higher transportation revenues at Great Lakes and higher contributions from TC PipeLines, LP reflecting colder winter weather and increased demand.

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

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CAPITAL PROGRAM

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

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



at June 30, 2014		Expected	Estimated
(unaudited - billions of $)	Segment	In-Service Date	Project Cost	Amount Spent

Small to medium-sized projects
Tamazunchale Extension¹	Natural Gas Pipelines	2014	US 0.6	US 0.5
Ontario Solar	Energy	2014-2015	0.5	0.2
Houston Lateral and Terminal	Liquids Pipelines	2015	US 0.4	US 0.3
Heartland and TC Terminals	Liquids Pipelines	2016	0.9	0.1
Keystone Hardisty Terminal	Liquids Pipelines	Approximately 2 years from date Keystone XL permit received	0.3	0.1
Topolobampo	Natural Gas Pipelines	2016	US 1.0	US 0.5
Mazatlan	Natural Gas Pipelines	2016	US 0.4	US 0.1
Grand Rapids²	Liquids Pipelines	2015-2017	1.5	0.1
Northern Courier	Liquids Pipelines	2017	0.8	0.1
NGTL System - North Montney	Natural Gas Pipelines	2016-2017	1.7	0.1
- Merrick	Natural Gas Pipelines	2020	1.9	—
- Other	Natural Gas Pipelines	2014-2016	0.5	0.2
Napanee	Energy	2017 or 2018	1.0	—
			11.5	2.3
Large scale projects³
Keystone XL⁴	Liquids Pipelines	Approximately 2 years from date permit received	US 5.4	US 2.4
Energy East⁵	Liquids Pipelines	2018	12.0	0.3
Prince Rupert Gas Transmission	Natural Gas Pipelines	2018	5.0	0.2
Coastal GasLink	Natural Gas Pipelines	2018+	4.0	0.2
			26.4	3.1
			37.9	5.4


1	A force majeure has delayed completion of construction, however, revenue has been recorded in second quarter 2014 as per the terms of the Transportation Service Agreement.


2	Represents our 50 per cent share.


3	Subject to cost adjustments due to market conditions, route refinement, permitting conditions and scheduling.


4	Estimated project cost will increase depending on the timing of the Presidential permit.


5	Excludes transfer of Canadian Mainline natural gas assets.

Outlook

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


•	the gain on sale of Cancarb Limited and its related power generation facility


•	the termination payment to Niksa Gas Storage for the contract restructuring


•	increased outage days at Bruce A.

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

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SECOND QUARTER 2014

Natural Gas Pipelines

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Comparable EBITDA	759		644		1,607		1,390
Comparable depreciation and amortization¹	(263	)	(245	)	(525	)	(485	)
Comparable EBIT	496		399		1,082		905
Specific item:
NEB decision - 2012	—		—		—		42
Segmented earnings	496		399		1,082		947


1	In 2014, comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization. In 2013, comparable depreciation is adjusted by $13 million relating to the impact from the NEB decision (RH-003-2011).

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Canadian Pipelines
Canadian Mainline	312		263		627		543
NGTL System	205		193		424		375
Foothills	27		28		54		57
Other Canadian pipelines (TQM¹, Ventures LP)	5		7		10		13
Canadian Pipelines - comparable EBITDA	549		491		1,115		988
Comparable depreciation and amortization	(204	)	(190	)	(407	)	(374	)
Canadian Pipelines - comparable EBIT	345		301		708		614

U.S. and International Pipelines (US$)
ANR	33		32		111		122
TC PipeLines, LP^1,2	21		13		47		30
Great Lakes³	9		8		28		18
Other U.S. pipelines (Bison⁴, Iroquois¹,GTN⁴, Portland⁵)	29		49		74		120
Mexico (Guadalajara, Tamazunchale)	49		26		74		52
International and other⁶	(1	)	(4	)	(2	)	(6	)
Non-controlling interests⁷	54		31		127		74
U.S. and International Pipelines - comparable EBITDA	194		155		459		410
Comparable depreciation and amortization	(54	)	(54	)	(108	)	(109	)
U.S. and International Pipelines - comparable EBIT	140		101		351		301
Foreign exchange impact	13		2		34		4
U.S. and International Pipelines - comparable EBIT(Cdn$)	153		103		385		305
Business Development comparable EBITDA and EBIT	(2	)	(5	)	(11	)	(14	)
Natural Gas Pipelines - comparable EBIT	496		399		1,082		905


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

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SECOND QUARTER 2014


2	Effective May 22, 2013, our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent. On July 1, 2013, we sold 45 per cent of GTN and Bison to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership of GTN, Bison, and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.



	Ownership percentage as of
	July 1, 2013	May 22, 2013	January 1, 2013

TC PipeLines, LP	28.9	28.9	33.3
Effective ownership through TC PipeLines, LP:
GTN/Bison	20.2	7.2	8.3
Great Lakes	13.4	13.4	15.5


3	Represents our 53.6 per cent direct ownership interest.


4	Effective July 1, 2013, represents our 30 per cent direct ownership interest. Prior to July 1, 2013, our direct ownership interest was 75 per cent.


5	Represents our 61.7 per cent ownership interest.


6	Includes our share of the equity income from Gas Pacifico/INNERGY and TransGas as well as general and administration costs relating to our U.S. and International pipelines.


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

CANADIAN PIPELINES

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

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES



	three months ended June 30		six months ended June 30
(unaudited - millions of $)	2014	2013	2014	2013

Canadian Mainline - net income	58	67	124	218
Canadian Mainline - comparable earnings	58	67	124	134
NGTL System	58	58	121	114
Foothills	4	5	8	9

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

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

U.S. AND INTERNATIONAL PIPELINES

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

Comparable EBITDA for the U.S. and international pipelines increased by US$39 million and US$49 million for the three and six months ended June 30, 2014 compared to the same periods in 2013. This was the net effect of:

•

contract revenues recognized from the Tamazunchale Extension in the three months ended June 30, 2014. The Tamazunchale Extension project has experienced delays in completing the construction due to archeological findings along the pipeline route. The CFE agreed that, under the terms of the TSA, these delays constitute force majeure and, as a result, collection and recognition of revenue commenced on March 9, 2014.


•	higher transportation revenues at Great Lakes and higher contributions from TC PipeLines, LP reflecting colder winter weather and increased demand


•	higher OM&A costs at ANR as well as lower storage revenues in first quarter 2014.

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SECOND QUARTER 2014

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

COMPARABLE DEPRECIATION AND AMORTIZATION

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

OPERATING STATISTICS - WHOLLY OWNED PIPELINES



six months ended June 30	Canadian Mainline¹		NGTL System²		ANR³
(unaudited)	2014	2013	2014	2013	2014	2013

Average investment base (millions of $)	5,667	5,871	6,179	5,882	n/a	n/a
Delivery volumes (Bcf)
Total	842	704	1,996	1,832	863	823
Average per day	4.7	3.9	11.0	10.1	4.8	4.6


1	Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the six months ended June 30, 2014 were 599 Bcf (2013 – 397 Bcf). Average per day was 3.3 Bcf (2013 – 2.2 Bcf).


2	Field receipt volumes for the NGTL System for the six months ended June 30, 2014 were 1,879 Bcf (2013 – 1,840 Bcf). Average per day was 10.4 Bcf (2013 – 10.2 Bcf).


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

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SECOND QUARTER 2014

Liquids Pipelines¹

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Comparable EBITDA	249		186		490		365
Comparable depreciation and amortization²	(54	)	(37	)	(103	)	(74	)
Comparable EBIT	195		149		387		291
Specific items	—		—		—		—
Segmented earnings	195		149		387		291


1	Previously Oil Pipelines.


2	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Keystone Pipeline System	256		187		504		373
Liquids Pipelines Business Development	(7	)	(1	)	(14	)	(8	)
Liquids Pipelines - comparable EBITDA	249		186		490		365
Comparable depreciation and amortization	(54	)	(37	)	(103	)	(74	)
Liquids Pipelines - comparable EBIT	195		149		387		291

Comparable EBIT denominated as follows:
Canadian dollars	50		52		99		99
U.S. dollars	133		95		262		189
Foreign exchange impact	12		2		26		3
	195		149		387		291

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

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


•	incremental earnings from the Gulf Coast extension which was placed in service in January 2014


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

BUSINESS DEVELOPMENT

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

COMPARABLE DEPRECIATION AND AMORTIZATION

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

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Energy

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Comparable EBITDA	231		330		576		607
Comparable depreciation and amortization¹	(77	)	(69	)	(154	)	(143	)
Comparable EBIT	154		261		422		464
Specific items (pre-tax):
Cancarb gain on sale	108		—		108		—
Niska contract termination	(41	)	—		(41	)	—
Risk management activities	(5	)	(18	)	(16	)	(22	)
Segmented earnings	216		243		473		442


1	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

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

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


•	a gain of $108 million ($99 million after tax) on the sale of Cancarb Limited and its related power generation business, which closed on April 15, 2014


•	a net loss resulting from the contract termination payment to Niska Gas Storage of $41 million ($31 million after-tax) effective April 30, 2014


•	unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain commodity price risks as follows:



Risk management activities	three months ended June 30				six months ended June 30
(unaudited - millions of $, pre-tax)	2014		2013		2014		2013

Canadian Power	(2	)	(4	)	(2	)	(6	)
U.S. Power	(9	)	(18	)	(11	)	(17	)
Natural Gas Storage	6		4		(3	)	1
Total losses from risk management activities	(5	)	(18	)	(16	)	(22	)

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Canadian Power
Western Power	46		117		118		191
Eastern Power¹	70		69		163		159
Bruce Power	24		59		88		90
Canadian Power - comparable EBITDA²	140		245		369		440
Comparable depreciation and amortization	(45	)	(43	)	(89	)	(86	)
Canadian Power - comparable EBIT²	95		202		280		354
U.S. Power (US$)
U.S. Power - comparable EBITDA	88		80		174		147
Comparable depreciation and amortization	(27	)	(23	)	(54	)	(51	)
U.S. Power - comparable EBIT	61		57		120		96
Foreign exchange impact	6		1		11		2
U.S. Power - comparable EBIT (Cdn$)	67		58		131		98
Natural Gas Storage and other
Natural Gas Storage and other - comparable EBITDA	2		9		29		27
Comparable depreciation and amortization	(3	)	(2	)	(6	)	(5	)
Natural Gas Storage and other - comparable EBIT	(1	)	7		23		22
Business Development comparable EBITDA and EBIT	(7	)	(6	)	(12	)	(10	)
Energy - comparable EBIT²	154		261		422		464


1	Includes four Ontario solar facilities acquired between June and December 2013.


2	Includes our share of equity income from our investments in ASTC Power Partnership, Portlands Energy and Bruce Power.

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


•	lower earnings from Western Power as a result of lower realized power prices


•	lower equity income from Bruce Power mainly due to increased planned and unplanned outage days at Bruce A, partially offset by fewer outage days at Bruce B


•	higher earnings from U.S. Power mainly because of higher realized capacity prices


•	lower earnings from Natural Gas Storage due to lower realized natural gas storage spreads.

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


•	lower earnings from Western Power as a result of lower realized power prices


•	higher earnings from U.S. Power mainly because of higher realized capacity and power prices


•	higher earnings from Eastern Power due to the incremental earnings from the Ontario solar facilities acquired in 2013.

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

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CANADIAN POWER

Western and Eastern Power



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Revenue
Western Power	160		157		341		297
Eastern Power¹	88		91		230		200
Other²	6		22		57		53
	254		270		628		550
Income from equity investments³	8		66		28		88
Commodity purchases resold	(90	)	(83	)	(191	)	(150	)
Plant operating costs and other	(58	)	(71	)	(186	)	(144	)
Exclude risk management activities	2		4		2		6
Comparable EBITDA	116		186		281		350
Comparable depreciation and amortization	(45	)	(43	)	(89	)	(86	)
Comparable EBIT	71		143		192		264

Breakdown of comparable EBITDA
Western Power	46		117		118		191
Eastern Power	70		69		163		159
Comparable EBITDA	116		186		281		350


1	Includes four Ontario solar facilities acquired between June and December 2013.


2	Includes sale of excess natural gas purchased for generation and Cancarb sales of thermal carbon black. Sale of Cancarb closed April 15, 2014.


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

Sales volumes and plant availability

Includes our share of volumes from our equity investments.



	three months ended June 30				six months ended June 30
(unaudited)	2014		2013		2014		2013

Sales volumes (GWh)
Supply
Generation
Western Power	611		687		1,220		1,357
Eastern Power¹	596		750		1,873		2,096
Purchased
Sundance A & B and Sheerness PPAs²	2,598		1,788		5,398		3,495
Other purchases	2		—		7		—
	3,807		3,225		8,498		6,948
Sales
Contracted
Western Power	2,434		1,939		4,895		3,646
Eastern Power¹	596		750		1,873		2,096
Spot
Western Power	777		536		1,730		1,206
	3,807		3,225		8,498		6,948
Plant availability³
Western Power⁴	94	%	92	%	95	%	94	%
Eastern Power^1,5	73	%	80	%	86	%	88	%


1	Includes four Ontario solar facilities acquired between June and December 2013.


2	Sundance A Unit 1 returned to service in September 2013 and Unit 2 returned to service in October 2013.


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


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


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

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Western Power

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


•	lower realized power prices


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

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

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

Eastern Power

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

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

BRUCE POWER

Our proportionate share



	three months ended June 30						six months ended June 30
(unaudited - millions of $, unless noted otherwise)	2014			2013			2014			2013

Income/(loss) from equity investments¹
Bruce A	(2		)	51			47			87
Bruce B	26			8			41			3
	24			59			88			90
Comprised of:
Revenues	265			306			565			593
Operating expenses	(164		)	(172		)	(321		)	(344		)
Depreciation and other	(77		)	(75		)	(156		)	(159		)
	24			59			88			90
Bruce Power - Other information
Plant availability²
Bruce A	64		%	88		%	72		%	77		%
Bruce B	93		%	80		%	89		%	79		%
Combined Bruce Power	79		%	84		%	82		%	78		%
Planned outage days
Bruce A	84			33			84			123
Bruce B	25			70			74			140
Unplanned outage days
Bruce A	45			—			105			8
Bruce B	—			3			—			12
Sales volumes (GWh)¹
Bruce A	2,037			2,464			4,564			4,561
Bruce B	2,048			1,726			3,972			3,460
	4,085			4,190			8,536			8,021
Realized sales price per MWh³
Bruce A		$72			$71			$71			$70
Bruce B		$55			$54			$55			$53
Combined Bruce Power		$62			$63			$62			$61

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SECOND QUARTER 2014


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


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


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

Equity income from Bruce A decreased by $53 million and $40 million for the three and six months ended June 30, 2014 compared to the same periods in 2013. The decrease was mainly due to:


•	lower earnings from Unit 3 due to a planned outage which began in April 2014


•	lower volumes due to increased unplanned outage days, primarily on Units 1 and 2.

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

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

Under the contract with the OPA, all of the output from Bruce A Units 1 to 4 is sold at a fixed price per MWh. The fixed price is adjusted annually on April 1 for inflation and other provisions under the OPA contract. Bruce A also recovers fuel costs from the OPA.



Bruce A fixed price	per MWh

April 1, 2014 - March 31, 2015	$71.70
April 1, 2013 - March 31, 2014	$70.99
April 1, 2012 - March 31, 2013	$68.23

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



Bruce B floor price	per MWh

April 1, 2014 - March 31, 2015	$52.86
April 1, 2013 - March 31, 2014	$52.34
April 1, 2012 - March 31, 2013	$51.62

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

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

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

U.S. POWER



	three months ended June 30				six months ended June 30
(unaudited - millions of US$)	2014		2013		2014		2013

Revenue
Power¹	311		316		1,054		779
Capacity	96		77		166		124
	407		393		1,220		903
Commodity purchases resold	(218	)	(197	)	(767	)	(503	)
Plant operating costs and other²	(109	)	(134	)	(289	)	(270	)
Exclude risk management activities	8		18		10		17
Comparable EBITDA	88		80		174		147
Comparable depreciation and amortization	(27	)	(23	)	(54	)	(51	)
Comparable EBIT	61		57		120		96

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


2	Includes the cost of fuel consumed in generation.

Sales volumes and plant availability



	three months ended June 30				six months ended June 30
(unaudited)	2014		2013		2014		2013

Physical sales volumes (GWh)
Supply
Generation	2,006		1,761		3,244		2,812
Purchased	1,865		1,878		4,694		4,357
	3,871		3,639		7,938		7,169

Plant availability¹	89	%	91	%	87	%	85	%


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

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


•	higher realized capacity prices in New York


•	higher generation at our hydro facilities


•	higher prices and related costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers.

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


•	higher realized capacity prices in New York


•	higher realized power prices and higher generation in New England


•	higher realized power prices and higher generation in New York offset by higher plant operating costs due to higher fuel prices


•	higher prices and related costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers.

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

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

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

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

As at June 30, 2014, approximately 3,500 GWh or 60 per cent of U.S. Power’s planned generation is contracted for the remainder of 2014, and 3,100 GWh or 35 per cent for 2015. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.

NATURAL GAS STORAGE AND OTHER

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

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Recent developments

NATURAL GAS PIPELINES

Canadian Regulated Pipelines

NGTL System

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

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

Merrick Mainline Pipeline Project

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

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

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

North Montney Mainline Project

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

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

Canadian Mainline

LDC Settlement

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

Eastern Mainline Project

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

U.S. Pipelines

ANR Pipeline

We have secured almost 2.0 Bcf/d of firm natural gas transportation commitments on the ANR Pipeline's Southeast Main Line at maximum rates for an average term of 23 years. Approximately 1.25 Bcf/d of new contracts will commence in late 2014 including volume commitments from the ANR Lebanon Lateral Reversal project, with the remaining volume commencing in 2015. These

TRANSCANADA [19

SECOND QUARTER 2014

contracts will enable growing Utica and Marcellus shale gas supply to move to both northern delivery points and southbound to the U.S. Gulf Coast. As a result, approximately US$100 million of capital investment will be required to bring this additional supply to market. We are also assessing further demand which could result in incremental opportunities to enhance and expand the ANR Pipeline system.

Mexican Pipelines

Tamazunchale Pipeline Extension Project

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

LNG Pipeline Projects

Coastal GasLink

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

Prince Rupert Gas Transmission

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

Alaska

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

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

LIQUIDS PIPELINES

Keystone Pipeline System

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

Keystone XL

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

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

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SECOND QUARTER 2014

Cushing Marketlink

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

Energy East Pipeline

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

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

Heartland Pipeline and TC Terminals

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

Northern Courier Pipeline

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

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

ENERGY

Cancarb Limited and Cancarb Waste Heat Facility

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

Natural Gas Storage

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

Ontario Solar

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

Bécancour

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

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SECOND QUARTER 2014

Other income statement items

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

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

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


•	higher interest expense due to debt issues of:


◦	US$1.25 billion in February 2014


◦	US$1.25 billion in October 2013


◦	US$500 million in July 2013


◦	$750 million in July 2013


◦	US$500 million in July 2013 by TC PipeLines, LP


•	higher foreign exchange on interest expense related to U.S. denominated debt, partially offset by Canadian and U.S. dollar-denominated debt maturities.

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



	three months ended June 30			six months ended June 30
(unaudited - millions of $)	2014	2013		2014	2013

Comparable interest income and other	29	(2	)	23	16
Specific items (pre-tax):
NEB decision - 2012	—	—		—	1
Risk management activities	25	(9	)	23	(15	)
Interest income and other	54	(11	)	46	2

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

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

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	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Comparable income tax expense	(162	)	(133	)	(386	)	(292	)
Specific items:
Cancarb gain on sale	(9	)	—		(9	)	—
Niska contract termination	10		—		10		—
NEB decision - 2012	—		—		—		42
Part VI.I income tax adjustment	—		25		—		25
Risk management activities	(4	)	10		(1	)	12
Income tax expense	(165	)	(98	)	(386	)	(213	)

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Net income attributable to non-controlling interests	(31	)	(23	)	(85	)	(54	)
Preferred share dividends	(25	)	(20	)	(48	)	(35	)

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

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

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SECOND QUARTER 2014

Financial condition

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

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

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

CASH PROVIDED BY OPERATING ACTIVITIES



	three months ended June 30			six months ended June 30
(unaudited - millions of $)	2014	2013		2014	2013

Funds generated from operations¹	917	955		2,019	1,871
Decrease/(increase) in operating working capital	202	(114	)	79	(324	)
Net cash provided by operations	1,119	841		2,098	1,547


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

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

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

CASH (USED IN)/PROVIDED BY INVESTING ACTIVITIES



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Capital expenditures	(967	)	(1,109	)	(1,745	)	(2,038	)
Equity investments	(40	)	(39	)	(129	)	(71	)
Acquisitions	—		(55	)	—		(55	)
Proceeds from sale of assets, net of transaction costs	187		—		187		—

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

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

CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2014		2013		2014		2013

Long-term debt issued, net of issue costs	16		10		1,380		744
Long-term debt repaid	(205	)	(695	)	(982	)	(709	)
Notes payable issued/(repaid), net	225		1,388		(522	)	559
Dividends and distributions paid	(412	)	(386	)	(802	)	(736	)
Partnership units of subsidiary issued, net of issue costs	—		384		—		384
Preferred shares issued, net of issue costs	—		(1	)	440		585
Preferred shares of subsidiary redeemed	—		—		(200	)	—

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SECOND QUARTER 2014

LONG-TERM DEBT ISSUED



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

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

LONG-TERM DEBT RETIRED



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

$450	Medium term notes	January 2014	5.65	%
$300	Medium term notes	February 2014	5.05	%
$125	Debenture	June 2014	11.10	%
$53	Debenture	June 2014	11.20	%

PREFERRED SHARE ISSUANCE AND REDEMPTION

In January, 2014, we completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $450 million. Investors are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly. The preferred shares are redeemable by us on or after October 30, 2019 and on October 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends. Investors will have the right to convert their shares into Series 10 cumulative redeemable first preferred shares on October 30, 2019 and on October 30 of every fifth year thereafter. The holders of Series 10 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annualized rate equal to the then 90-day Government of Canada treasury bill rate and 2.35 per cent.

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

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

DIVIDENDS

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



Quarterly dividend on our common shares

$0.48 per share
Payable on October 31, 2014 to shareholders of record at the close of business on September 30, 2014

Quarterly dividends on our preferred shares

Series 1	$0.2875
Series 3	$0.25
Payable on September 30, 2014 to shareholders of record at the close of business on September 2, 2014
Series 5	$0.275
Series 7	$0.25
Series 9	$0.265625
Payable on October 30, 2014 to shareholders of record at the close of business on September 30, 2014

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SECOND QUARTER 2014

SHARE INFORMATION



July 28, 2014

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

Options to buy common shares	Outstanding	Exercisable
	9 million	5 million

CREDIT FACILITIES

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

At June 30, 2014, we had $6.5 billion in unsecured credit facilities, including:



Amount	Unused capacity	Subsidiary	Description and Use	Matures

$3.0 billion	$3.0 billion	TCPL	Committed, syndicated, revolving, extendible credit facility that supports TCPL’s Canadian commercial paper program	December 2018
US$1.0 billion	US$1.0 billion	TCPL USA	Committed, syndicated, revolving, extendible credit facility that is used for TCPL USA general corporate purposes	November 2014
US$1.0 billion	US$1.0 billion	TransCanada American Investments Ltd. (TAIL)	Committed, syndicated, revolving, extendible credit facility that supports the TAIL U.S. commercial paper program.	November 2014
$1.3 billion	$0.3 billion	TCPL, TCPL USA	Demand lines for issuing letters of credit and as a source of additional liquidity. At June 30, 2014, we had $1.0 billion outstanding in letters of credit under these lines	Demand

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

CONTRACTUAL OBLIGATIONS

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

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SECOND QUARTER 2014

Financial risks and financial instruments

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

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

LIQUIDITY RISK

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

COUNTERPARTY CREDIT RISK

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


•	accounts receivable


•	the fair value of derivative assets


•	notes receivable.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At June 30, 2014 we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration of $211 million with one counterparty at June 30, 2014 (December 31, 2013 - $240 million). This amount is secured by a guarantee from the counterparty’s parent company and we anticipate collecting the full amount.

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

FOREIGN EXCHANGE AND INTEREST RATE RISK

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

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

Average exchange rate - U.S. to Canadian dollars



second quarter 2014	1.09
second quarter 2013	1.03

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

Significant U.S. dollar-denominated amounts



	three months ended June 30				six months ended June 30
(unaudited - millions of US$)	2014		2013		2014		2013

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

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NET INVESTMENT IN FOREIGN OPERATIONS

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



	June 30, 2014			December 31, 2013
(unaudited - millions of $)	Fair value¹		Notional or principal amount	Fair value¹		Notional or principal amount

Asset/(liability)
U.S. dollar cross-currency swaps
(maturing 2014 to 2019)²	(186	)	US 3,250	(201	)	US 3,800
U.S. dollar foreign exchange forward contracts
(maturing 2014)	(14	)	US 300	(11	)	US 850
	(200	)	US 3,550	(212	)	US 4,650


1	Fair values equal carrying values.


2	Net income in the three and six months ended June 30, 2014 included net realized gains of $5 million and $11 million, respectively, (2013 - gains of $7 million and $14 million, respectively) related to the interest component of cross-currency swaps.

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



(unaudited - millions of $)	June 30, 2014	December 31, 2013

Carrying value	15,600 (US 14,600)	14,200 (US 13,400)
Fair value	18,200 (US 17,100)	16,000 (US 15,000)

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



(unaudited - millions of $)	June 30, 2014		December 31, 2013

Other current assets	5		5
Intangible and other assets	1		—
Accounts payable and other	(57	)	(50	)
Other long-term liabilities	(149	)	(167	)
	(200	)	(212	)

FINANCIAL INSTRUMENTS

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

Non-derivative financial instruments

Fair value of non-derivative financial instruments

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

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

Derivative instruments

We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify. The effective portion of the change in the fair value of hedging derivatives for cash flow hedges and hedges of our net investment in foreign operations are recorded in OCI in

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SECOND QUARTER 2014

the period of change. Any ineffective portion is recognized in net income in the same financial category as the underlying transaction. The change in the fair value of derivative instruments that have been designated as fair value hedges are recorded in net income in interest income and other and interest expense.

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

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

Fair value of derivative instruments

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

Balance sheet presentation of derivative instruments

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



(unaudited - millions of $)	June 30, 2014		December 31, 2013

Other current assets	354		395
Intangible and other assets	127		112
Accounts payable and other	(404	)	(357	)
Other long-term liabilities	(236	)	(255	)
	(159	)	(105	)

The effect of derivative instruments on the consolidated statement of income

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $, pre-tax)	2014		2013		2014		2013

Derivative instruments held for trading¹
Amount of unrealized gains/(losses) in the period
Power	6		5		15		(3	)
Natural gas	(14	)	(21	)	(21	)	(12	)
Foreign exchange	25		(10	)	23		(16	)
Amount of realized (losses)/gains in the period
Power	(3	)	(29	)	(31	)	(36	)
Natural gas	(4	)	(5	)	46		(7	)
Foreign exchange	(1	)	(6	)	(18	)	(7	)
Derivative instruments in hedging relationships^2,3
Amount of realized gains/(losses) in the period
Power	(4	)	(84	)	188		(11	)
Natural gas	—		(1	)	—		(1	)
Interest	1		2		2		4


1	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in energy revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held for trading derivative instruments are included net in interest expense and interest income and other, respectively.

At June 30, 2014, all hedging relationships were designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $5 million (2013 - $7 million) and a notional amount of US$300 million (2013 - US$200 million). For the three and six months ended June 30, 2014, net realized gains on fair value hedges were $2 million and $3 million, respectively (2013 - $2 million and $4 million, respectively) and were included in interest expense. For the three and six months ended June 30, 2014 and 2013, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

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SECOND QUARTER 2014

The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other, as appropriate, as the original hedged item settles. For the three and six months ended June 30, 2014 and 2013, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

Derivatives in cash flow hedging relationships

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



	three months ended June 30				six months ended June 30
(unaudited - millions of $, pre-tax)	2014		2013		2014		2013

Change in fair value of derivative instruments recognized in OCI (effective portion)
Power	(7	)	(70	)	34		(34	)
Natural gas	(1	)	—		(1	)	—
Foreign exchange	—		2		10		4
Interest	(1	)	—		(1	)	—
	(9	)	(68	)	42		(30	)
Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)¹
Power²	(1	)	12		(109	)	1
Natural gas	2		2		2		2
Interest	3		4		8		8
	4		18		(99	)	11
Gains/(losses) on derivative instruments recognized in earnings (ineffective portion)
Power	3		(2	)	(10	)	(7	)
	3		(2	)	(10	)	(7	)


1	No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.


2	Reported within Energy revenues on the condensed consolidated statement of income.

Credit risk related contingent features of derivative instruments

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

Based on contracts in place and market prices at June 30, 2014, the aggregate fair value of all derivative contracts with credit risk related contingent features that were in a net liability position was $17 million (December 31, 2013 - $16 million), with collateral provided in the normal course of business of nil (December 31, 2013 – nil). If the credit risk related contingent features in these agreements had been triggered on June 30, 2014, we would have been required to provide collateral of $17 million (December 31, 2013 - $16 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

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

Other information

CONTROLS AND PROCEDURES

Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at June 30, 2014, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

There were no changes in second quarter 2014 that had or are likely to have a material impact on our internal control over financial reporting, other than noted below.

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

CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES

When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected

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SECOND QUARTER 2014

by future events. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. You can find a summary of our critical accounting estimates in our 2013 Annual Report.

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

Changes in accounting policies for 2014

Obligations resulting from joint and several liability arrangements

In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This new guidance was effective January 1, 2014. There was no material impact on our consolidated financial statements as a result of applying this new standard.

Foreign currency matters - cumulative translation adjustment

In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This new guidance was effective prospectively from January 1, 2014 and will be applied for all applicable transactions after that date.

Unrecognized tax benefit

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

Future accounting changes

Reporting discontinued operations

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

Revenue from contracts with customers

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

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Reconciliation of non-GAAP measures



	three months ended June 30				six months ended June 30
(unaudited - millions of $, except per share amounts)	2014		2013		2014		2013

EBITDA	1,279		1,125		2,664		2,344
Cancarb gain on sale	(108	)	—		(108	)	—
Niska contract termination	41		—		41		—
NEB decision - 2012	—		—		—		(55	)
Non-comparable risk management activities affecting EBITDA	5		18		16		22
Comparable EBITDA	1,217		1,143		2,613		2,311
Comparable depreciation and amortization	(399	)	(356	)	(792	)	(710	)
Comparable EBIT	818		787		1,821		1,601
Other income statement items
Comparable interest expense	(297	)	(252	)	(571	)	(509	)
Comparable interest income and other	29		(2	)	23		16
Comparable income tax expense	(162	)	(133	)	(386	)	(292	)
Net income attributable to non-controlling interests	(31	)	(23	)	(85	)	(54	)
Preferred share dividends	(25	)	(20	)	(48	)	(35	)
Comparable earnings	332		357		754		727
Specific items (net of tax):
Cancarb gain on sale	99		—		99		—
Niska contract termination	(31	)	—		(31	)	—
NEB decision - 2012	—		—		—		84
Part VI.I income tax adjustment	—		25		—		25
Risk management activities¹	16		(17	)	6		(25	)
Net income attributable to common shares	416		365		828		811

Comparable depreciation and amortization	(399	)	(356	)	(792	)	(710	)
Specific item:
NEB decision - 2012	—		—		—		(13	)
Depreciation and amortization	(399	)	(356	)	(792	)	(723	)

Comparable interest expense	(297	)	(252	)	(571	)	(509	)
Specific item:
NEB decision - 2012	—		—		—		(1	)
Interest expense	(297	)	(252	)	(571	)	(510	)

Comparable interest income and other	29		(2	)	23		16
Specific items:
NEB decision - 2012	—		—		—		1
Risk management activities¹	25		(9	)	23		(15	)
Interest income and other	54		(11	)	46		2

Comparable income tax expense	(162	)	(133	)	(386	)	(292	)
Specific items:
Cancarb gain on sale	(9	)	—		(9	)	—
Niska contract termination	10		—		10		—
Canadian restructuring proposal - 2012	—		—		—		42
Part VI.I income tax adjustment	—		25		—		25
NEB decision - 2012	—		—		—		—
Risk management activities¹	(4	)	10		(1	)	12
Income tax expense	(165	)	(98	)	(386	)	(213	)

TRANSCANADA [32

SECOND QUARTER 2014




	three months ended June 30						six months ended June 30
(unaudited - millions of $, except per share amounts)	2014			2013			2014			2013

Comparable earnings per common share		$0.47			$0.51			$1.07			$1.03
Specific items (net of tax):
Cancarb gain on sale	0.14			—			0.14			—
Niska contract termination	(0.04		)	—			(0.04		)	—
NEB decision - 2012	—			—			—			0.12
Part VI.I income tax adjustment	—			0.04						0.04
Risk management activities¹	0.02			(0.03		)	—			(0.04		)
Net income per common share		$0.59			$0.52			$1.17			$1.15



1	Risk management activities	three months ended June 30				six months ended June 30
	(unaudited - millions of $)	2014		2013		2014		2013

	Canadian Power	(2	)	(4	)	(2	)	(6	)
	U.S. Power	(9	)	(18	)	(11	)	(17	)
	Natural Gas Storage	6		4		(3	)	1
	Foreign exchange	25		(9	)	23		(15	)
	Income tax attributable to risk management activities	(4	)	10		(1	)	12
	Total gains/(losses) from risk management activities	16		(17	)	6		(25	)

Comparable EBITDA and EBIT by business segment



three months ended June 30, 2014	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines¹		Energy		Corporate		Total

EBITDA	759		249		293		(22	)	1,279
Cancarb gain on sale	—		—		(108	)	—		(108	)
Niska contract termination	—		—		41		—		41
Non-comparable risk management activities affecting EBITDA	—		—		5		—		5
Comparable EBITDA	759		249		231		(22	)	1,217
Comparable depreciation and amortization	(263	)	(54	)	(77	)	(5	)	(399	)
Comparable EBIT	496		195		154		(27	)	818



three months ended June 30, 2013	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines¹		Energy		Corporate		Total

EBITDA	644		186		312		(17	)	1,125
Non-comparable risk management activities affecting EBITDA	—		—		18		—		18
Comparable EBITDA	644		186		330		(17	)	1,143
Comparable depreciation and amortization	(245	)	(37	)	(69	)	(5	)	(356	)
Comparable EBIT	399		149		261		(22	)	787

TRANSCANADA [33

SECOND QUARTER 2014



six months ended June 30, 2014	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines¹		Energy		Corporate		Total

EBITDA	1,607		490		627		(60	)	2,664
Cancarb gain on sale	—		—		(108	)	—		(108	)
Niska contract termination	—		—		41		—		41
Non-comparable risk management activities affecting EBITDA	—		—		16		—		16
Comparable EBITDA	1,607		490		576		(60	)	2,613
Comparable depreciation and amortization	(525	)	(103	)	(154	)	(10	)	(792	)
Comparable EBIT	1,082		387		422		(70	)	1,821



six months ended June 30, 2013	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines¹		Energy		Corporate		Total

EBITDA	1,445		365		585		(51	)	2,344
NEB decision - 2012	(55	)	—		—		—		(55	)
Non-comparable risk management activities affecting EBITDA	—		—		22		—		22
Comparable EBITDA	1,390		365		607		(51	)	2,311
Comparable depreciation and amortization	(485	)	(74	)	(143	)	(8	)	(710	)
Comparable EBIT	905		291		464		(59	)	1,601


1	Previously Oil Pipelines.

TRANSCANADA [34

SECOND QUARTER 2014

QUARTERLY RESULTS

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA



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

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

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT

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

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


•	regulatory decisions


•	negotiated settlements with shippers


•	acquisitions and divestitures


•	developments outside of the normal course of operations


•	newly constructed assets being placed in service.

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

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


•	weather


•	customer demand


•	market prices


•	capacity prices and payments


•	planned and unplanned plant outages


•	acquisitions and divestitures


•	certain fair value adjustments


•	developments outside of the normal course of operations


•	newly constructed assets being placed in service


•	regulatory decisions.

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER

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

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

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

In second quarter 2013, comparable earnings excluded a $25 million favourable income tax adjustment due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax in June 2013.

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

TC Energy (TRP) 6-KTransCanada Reports Solid Second Quarter Results