TC Energy 6K TransCanada Reports Solid Second Quarter 2016 Financial Results | TRP 28 Jul 16

EXHIBIT 13.1

Quarterly report to shareholders

Second quarter 2016

Financial highlights



	three months ended June 30					six months ended June 30
(unaudited - millions of $, except per share amounts)	2016		2015			2016		2015

Income
Revenues	2,751		2,631			5,254		5,505
Net income attributable to common shares	365		429			617		816
per common share - basic and diluted		$0.52		$0.60			$0.88		$1.15
Comparable EBITDA¹	1,369		1,367			2,871		2,898
Comparable earnings¹	366		397			860		862
per common share¹		$0.52		$0.56			$1.22		$1.22

Operating cash flow
Funds generated from operations¹	831		1,061			1,956		2,214
Decrease/(increase) in operating working capital	218		(92		)	138		(485		)
Net cash provided by operations	1,049		969			2,094		1,729

Comparable distributable cash flow¹	698		861			1,668		1,817
per common share¹		$0.99		$1.21			$2.37		$2.56

Investing activities
Capital spending - capital expenditures	982		966			1,818		1,772
- projects in development	90		172			157		335
Contributions to equity investments	114		105			284		198
Acquisitions, net of cash acquired	4		—			999		—
Proceeds from sale of assets, net of transaction costs	—		—			6		—

Dividends declared
Per common share		$0.565		$0.52			$1.13		$1.04
Basic common shares outstanding (millions)
Average for the period	703		709			703		709
End of period	703		709			703		709


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

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SECOND QUARTER 2016

Management’s discussion and analysis

July 27, 2016

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, 2016, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2016 which have been prepared in accordance with U.S. GAAP. For greater certainty, given our acquisition of Columbia Pipeline Group, Inc. (Columbia) was not completed until July 1, 2016, Columbia was not a subsidiary during the period ended June 30, 2016 and its results have not been reflected in our condensed consolidated financial statements for the three and six months ended June 30, 2016.

This MD&A should also be read in conjunction with our December 31, 2015 audited consolidated financial statements and notes and the MD&A in our 2015 Annual Report.

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 2015 Annual Report. All information is as of July 27, 2016 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:


•	planned changes in our business including the divestiture of certain assets


•	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 and insurance claims


•	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.

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SECOND QUARTER 2016

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

Assumptions


•	planned monetization of our U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline business


•	inflation rates, commodity prices and capacity prices


•	timing of financings and hedging


•	regulatory decisions and outcomes


•	termination of the Alberta PPAs


•	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 realize the anticipated benefits of the acquisition of Columbia


•	timing and execution of our planned asset sales


•	our ability to successfully implement our strategic initiatives


•	whether our strategic initiatives will yield the expected benefits


•	the operating performance of our pipeline and energy assets


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


•	the availability and price of energy commodities


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


•	regulatory decisions and outcomes


•	outcomes of legal proceedings, including arbitration and insurance claims


•	performance and credit risk of our counterparties


•	changes in market commodity prices


•	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, tax 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 2015 Annual Report.

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SECOND QUARTER 2016

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, except as required 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


•	distributable cash flow


•	distributable cash flow per common share


•	comparable earnings


•	comparable earnings per common share


•	comparable EBITDA


•	comparable EBIT


•	comparable distributable cash flow


•	comparable distributable cash flow per common share


•	comparable income from equity investments


•	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. Please see the Reconciliation of non-GAAP measures section in this MD&A for a reconciliation of the GAAP measures to the non-GAAP measures.

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 the Financial condition section for a reconciliation to net cash provided by operations.

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SECOND QUARTER 2016

Distributable cash flow

Distributable cash flow is defined as funds generated from operations plus distributions received from operating activities in excess of equity earnings equity-accounted for investments less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. We believe it is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. See the 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. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.



Comparable measure	Original measure

comparable earnings	net income attributable to common shares
comparable earnings per common share	net income per common share
comparable EBITDA	EBITDA
comparable EBIT	segmented earnings
comparable distributable cash flow	distributable cash flow
comparable distributable cash flow per common share	distributable cash flow per common share
comparable income from equity investments	income from equity investments
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 and changes to enacted rates


•	gains or losses on sales of assets


•	legal, contractual and bankruptcy settlements


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


•	restructuring costs


•	impairment of assets and investments including ongoing maintenance and liquidation costs


•	acquisition costs.

We calculate comparable earnings by excluding the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally 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 reflective of our underlying operations.

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SECOND QUARTER 2016

Consolidated results - second quarter 2016

Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.



	three months ended June 30				six months ended June 30
(unaudited - millions of $, except per share amounts)	2016		2015		2016		2015

Natural Gas Pipelines	592		517		1,199		1,105
Liquids Pipelines	204		247		422		489
Energy	378		262		256		471
Corporate	(58	)	(32	)	(118	)	(63		)
Total segmented earnings	1,116		994		1,759		2,002
Interest expense	(514	)	(331	)	(934	)	(649		)
Interest income and other	117		81		318		67
Income before income taxes	719		744		1,143		1,420
Income tax expense	(274	)	(250	)	(344	)	(457		)
Net income	445		494		799		963
Net income attributable to non-controlling interests	(52	)	(40	)	(132	)	(99		)
Net income attributable to controlling interests	393		454		667		864
Preferred share dividends	(28	)	(25	)	(50	)	(48		)
Net income attributable to common shares	365		429		617		816
Net income per common share - basic and diluted	$0.52		$0.60		$0.88			$1.15

Net income attributable to common shares decreased by $64 million and $199 million for the three and six months ended June 30, 2016 compared to the same periods in 2015. The 2016 results included:


•	a $176 million after-tax impairment charge in first quarter on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs

•

a charge of $113 million in second quarter and $139 million year-to-date related to costs associated with the acquisition of Columbia. In second quarter, $109 million related to the dividend equivalent payments on the subscription receipts issued as part of the permanent financing of the transaction, $10 million ($36 million year-to-date) related to acquisition costs and $6 million related to interest earned on the funds held in escrow


•	an after-tax charge of $9 million in second quarter and $15 million year-to-date related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project


•	an after-tax charge of $10 million in second quarter for restructuring charges mainly related to expected future losses under lease commitments. These charges form part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs


•	an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016.

The 2015 results included:


•	a $34 million adjustment to income tax expense due to the enactment of a two per cent increase in the Alberta corporate income tax rate in June 2015


•	an after-tax charge of $8 million for severance costs primarily as a result of the restructuring of our major projects group in response to delayed timelines on certain of our major projects, along with a continued focus on enhancing the efficiency and effectiveness of our operations.

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SECOND QUARTER 2016

Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings.

Comparable earnings decreased by $31 million and $2 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 as discussed below in the reconciliation of net income to comparable earnings.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS



	three months ended June 30				six months ended June 30
(unaudited - millions of $, except per share amounts)	2016		2015		2016		2015

Net income attributable to common shares	365		429		617		816
Specific items (net of tax):
Alberta PPA terminations	—		—		176		—
Acquisition costs - Columbia Pipeline Group	113		—		139		—
Keystone XL asset costs	9		—		15		—
Restructuring costs	10		8		10		8
TC Offshore loss on sale	—		—		3		—
Alberta corporate income tax rate increase	—		34		—		34
Risk management activities¹	(131	)	(74	)	(100	)	4
Comparable earnings	366		397		860		862

Net income per common share	$0.52		$0.60		$0.88		$1.15
Specific items (net of tax):
Alberta PPA terminations	—		—		0.25		—
Acquisition costs - Columbia Pipeline Group	0.16		—		0.20		—
Keystone XL asset costs	0.01		—		0.02		—
Restructuring costs	0.01		0.01		0.01		0.01
Alberta corporate income tax rate increase	—		0.05		—		0.05
Risk management activities	(0.18	)	(0.10	)	(0.14	)	0.01
Comparable earnings per share	$0.52		$0.56		$1.22		$1.22



¹	Risk management activities	three months ended June 30				six months ended June 30
	(unaudited - millions of $)	2016		2015		2016		2015

	Canadian Power	20		29		7		7
	U.S. Power	204		51		89		(17	)
	Liquids marketing	4		—		2		—
	Natural Gas Storage	—		(1	)	5		—
	Foreign exchange	(4	)	30		49		1
	Income tax attributable to risk management activities	(93	)	(35	)	(52	)	5
	Total gains/(losses) from risk management activities	131		74		100		(4	)

TRANSCANADA [8

SECOND QUARTER 2016

Comparable earnings decreased by $31 million for the three months ended June 30, 2016 compared to the same period in 2015. This was primarily the net effect of:


•	higher interest income and other due to increased AFUDC related to our rate-regulated projects and realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income


•	higher interest expense from debt issuances and lower capitalized interest


•	lower earnings from Bruce Power mainly due to higher planned outage days, partially offset by lower depreciation


•	higher earnings from U.S. and International Pipelines due to higher ANR Southeast Mainline transportation revenues and lower OM&A expenses


•	lower earnings from Liquids Pipelines due to lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink


•	higher earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant acquired February 1, 2016 and insurance recoveries related to an unplanned outage at Ravenswood


•	lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes following the termination of the PPAs.

Comparable earnings decreased by $2 million for the six months ended June 30, 2016 compared to the same period in 2015. This was primarily the net effect of:


•	higher interest income and other due to increased AFUDC related to our rate-regulated projects and realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income


•	higher interest expense from debt issuances and lower capitalized interest


•	lower earnings from Liquids Pipelines due to lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink


•	higher earnings from our U.S. and International Pipelines due to higher ANR Southeast Mainline transportation revenues and lower OM&A expenses, offset by a first quarter 2015 non-recurring settlement


•	lower earnings from U.S. Power mainly due to decreased margins on sales to wholesale, commercial and industrial customers, the impact of lower capacity prices in New York and lower realized prices in both New England and New York, offset by incremental earnings from the Ironwood power plant and insurance recoveries related to an unplanned outage at Ravenswood


•	lower earnings from Eastern Power due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour


•	lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes following the termination of the PPAs.

The stronger U.S. dollar this quarter compared to the same period in 2015 positively impacted the translated results in our U.S. businesses, along with realized gains on foreign exchange hedges used to manage our exposure, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt.

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SECOND QUARTER 2016

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 cash flow.

Our capital program as of June 30, 2016, consists of $15 billion of near-term projects and $45 billion of commercially secured medium- to longer-term projects. Amounts presented exclude the impact of foreign exchange, capitalized interest and AFUDC.

All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.



at June 30, 2016	Estimated project cost	Carrying value
(unaudited - billions of $)	Estimated project cost	Carrying value
Summary
Near-term	14.6	5.0
Medium- to longer-term	45.2	2.3
Total capital program	59.8	7.3

Foreign exchange impact on Capital Program¹	3.9	0.7


¹	Reflects U.S./Canada foreign exchange rate of $1.30 at June 30, 2016.



at June 30, 2016	Segment	Expected in-service date	Estimated project cost	Carrying value
(unaudited - billions of $)	Segment	Expected in-service date	Estimated project cost	Carrying value

Houston Lateral and Terminal	Liquids Pipelines	2016	US 0.6	US 0.6
Topolobampo	Natural Gas Pipelines	2016	US 1.0	US 0.9
Mazatlan	Natural Gas Pipelines	2016	US 0.4	US 0.3
Canadian Mainline	Natural Gas Pipelines	2016-2017	0.7	0.2
NGTL - 2016/17 Facilities	Natural Gas Pipelines	2016-2020	2.7	0.7
- North Montney	Natural Gas Pipelines	2017	1.7	0.3
- 2018 Facilities	Natural Gas Pipelines	2018-2020	0.6	—
- Other	Natural Gas Pipelines	2016-2018	0.4	0.1
Grand Rapids¹	Liquids Pipelines	2017	0.9	0.7
Northern Courier	Liquids Pipelines	2017	1.0	0.7
Tuxpan-Tula	Natural Gas Pipelines	2017	US 0.5	US 0.1
Napanee	Energy	2018	1.0	0.4
Tula-Villa de Reyes	Natural Gas Pipelines	2018	US 0.6	—
Sur de Texas-Tuxpan¹	Natural Gas Pipelines	2018	US 1.3	—
Bruce Power - life extension¹	Energy	2016-2020	1.2	—
Total near-term projects			14.6	5.0


¹	Our proportionate share.

TRANSCANADA [10

SECOND QUARTER 2016



at June 30, 2016	Segment	Estimated project cost	Carrying value
(unaudited - billions of $)	Segment	Estimated project cost	Carrying value

Heartland and TC Terminals	Liquids Pipelines	0.9	0.1
Upland	Liquids Pipelines	US 0.6	—
Grand Rapids Phase 2¹	Liquids Pipelines	0.7	—
Bruce Power - life extension¹	Energy	5.3	—
Keystone projects
Keystone XL²	Liquids Pipelines	US 8.0	US 0.3
Keystone Hardisty Terminal²	Liquids Pipelines	0.3	0.1
Energy East projects
Energy East³	Liquids Pipelines	15.7	0.8
Eastern Mainline	Natural Gas Pipelines	2.0	0.1
BC west coast LNG-related projects
Coastal GasLink	Natural Gas Pipelines	4.8	0.4
Prince Rupert Gas Transmission	Natural Gas Pipelines	5.0	0.5
NGTL System - Merrick	Natural Gas Pipelines	1.9	—
Total medium to longer-term projects		45.2	2.3


¹	Our proportionate share.


²	Carrying value reflects amount remaining after impairment charge recorded in fourth quarter 2015.


³	Excludes transfer of Canadian Mainline natural gas assets.

Our capital program as of July 1, 2016, including Columbia projects, consists of $25 billion of near-term projects.



at July 1, 2016 (Acquisition date)	Segment	Expected in-service date	Estimated project cost
(unaudited - billions of US$)	Segment	Expected in-service date	Estimated project cost

Columbia Pipeline Group
Modernization I	Natural Gas Pipelines	2017-2018	US 0.6
Modernization II	Natural Gas Pipelines	2019-2021	US 1.1
Leach XPress	Natural Gas Pipelines	2017	US 1.4
WB XPress	Natural Gas Pipelines	2018	US 0.8
Mountaineer XPress	Natural Gas Pipelines	2018	US 2.0
Rayne XPress	Natural Gas Pipelines	2017	US 0.4
Cameron Access	Natural Gas Pipelines	2018	US 0.3
Gulf XPress	Natural Gas Pipelines	2018	US 0.7
Total Columbia projects			US 7.3

Total Columbia projects - Canadian $			9.5

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SECOND QUARTER 2016

Outlook

Our overall earnings outlook for our 2016 earnings, excluding specific items, will be modestly higher than what was previously included in the 2015 Annual Report due to the net impact of the acquisition of Columbia on July 1, 2016, changes in our Canadian Power business and lower than expected U.S. Power earnings, each of which are addressed within the relevant section of the MD&A.

Consolidated capital spending, equity investments and acquisition

On April 11, 2016, we announced that we were chosen to build, own and operate the US$550 million Tula-Villa de Reyes pipeline in Mexico. On June 13, 2016, we announced that our joint venture with IEnova, Infraestructura Marina del Golfo (IMG), was chosen to build, own and operate the US$2.1 billion Sur de Texas-Tuxpan natural gas pipeline in Mexico. On July 1, 2016, we acquired Columbia for US$10.3 billion. In addition to the capital expenditures outlined in the 2015 Annual Report, we expect to spend an estimated additional $1 billion on Columbia capital projects in 2016, approximately $300 million on the Tula-Villa de Reyes pipeline and $150 million on the Sur de Texas-Tuxpan natural gas pipeline.

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). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable EBITDA	880		799		1,778		1,666
Depreciation and amortization	(288	)	(282	)	(575	)	(561	)
Comparable EBIT	592		517		1,203		1,105
Specific item:
TC Offshore loss on sale	—		—		(4	)	—
Segmented earnings	592		517		1,199		1,105

Natural Gas Pipelines segmented earnings increased by $75 million and $94 million for the three and six months ended June 30, 2016 compared to the same periods in 2015. Segmented earnings for the six months ended June 30, 2016 included an additional $4 million pre-tax loss on the sale of TC Offshore. This amount has been excluded from our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below.

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SECOND QUARTER 2016



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Canadian Pipelines
Canadian Mainline	300		317		540		580
NGTL System	249		224		483		443
Foothills	26		27		52		53
Other Canadian pipelines¹	6		8		13		14
Canadian Pipelines - comparable EBITDA	581		576		1,088		1,090
Depreciation and amortization	(218	)	(211	)	(434	)	(420	)
Canadian Pipelines - comparable EBIT	363		365		654		670

U.S. and International Pipelines (US$)
ANR	71		33		159		119
TC PipeLines, LP^1,2	27		25		58		51
Great Lakes³	11		7		36		27
Other U.S. pipelines (Iroquois¹,GTN^2,4, PNGTS^2,5)	9		11		23		52
Mexico (Guadalajara, Tamazunchale)	42		47		83		94
International and other^1,6	2		2		4		4
Non-controlling interests⁷	75		66		170		140
U.S. and International Pipelines - comparable EBITDA	237		191		533		487
Depreciation and amortization	(54	)	(57	)	(107	)	(114	)
U.S. and International Pipelines - comparable EBIT	183		134		426		373
Foreign exchange impact	49		29		133		88
U.S. and International Pipelines - comparable EBIT(Cdn$)	232		163		559		461
Business Development comparable EBITDA and EBIT	(3	)	(11	)	(10	)	(26	)
Natural Gas Pipelines - comparable EBIT	592		517		1,203		1,105


¹	Results from TQM, Northern Border, Iroquois and TransGas reflect our share of equity income from these investments. We closed the purchase of an additional 4.87 per cent interest in Iroquois on March 31, 2016 and an additional 0.65 per cent interest on May 1, 2016.

²On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TC PipeLines, LP. On January 1, 2016, we sold a 49.9 per cent interest in PNGTS to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of GTN, Great Lakes and PNGTS through our ownership interest in TC PipeLines, LP for the periods presented.



	Ownership percentage as of
	June 30, 2016	March 31, 2016	December 31, 2015	April 1, 2015

TC PipeLines, LP	27.4	27.9	28.0	28.3
Effective ownership through TC PipeLines, LP:
GTN	27.4	27.9	28.0	28.3
Great Lakes	12.7	13.0	13.0	13.1
PNGTS	13.7	13.9	—	—


³	Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TC PipeLines, LP.


⁴	Effective April 1, 2015, we have no direct ownership in GTN. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.


⁵	Represents our 61.7 per cent ownership interest in 2015. Effective January 1, 2016, our direct ownership interest in PNGTS was 11.8 per cent as a result of the dropdown transaction between us and TC PipeLines, LP.


⁶	Includes our share of the equity income from 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 PNGTS we do not own.

TRANSCANADA [13

SECOND QUARTER 2016

CANADIAN PIPELINES

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

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES



	three months ended June 30		six months ended June 30
(unaudited - millions of $)	2016	2015	2016	2015

Canadian Mainline	52	67	102	114
NGTL System	79	66	152	130
Foothills	3	4	7	8

Net income for the Canadian Mainline decreased by $15 million for the three months ended June 30, 2016 compared to the same period in 2015 primarily due to lower incentive earnings and average investment base. Higher incentive earnings were recorded in the second quarter of 2015 because NEB approval of the 2015 - 2020 compliance tolls for the NEB 2014 Decision was received in June 2015 and second quarter 2015 results included the year-to-date impact. The NEB 2014 Decision included an approved ROE of 10.1 per cent with a possible range of achieved ROE outcomes between 8.7 to 11.5 per cent. Net Income for the Canadian Mainline decreased by $12 million for the six months ended June 30, 2016 compared to the same period in 2015 mainly due to a lower average investment base in 2016.

Net income for the NGTL System increased by $13 million and $22 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 mainly due to a higher average investment base and OM&A incentives recorded in 2016.

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. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.

Comparable EBITDA for U.S. and International Pipelines increased by US$46 million in both the three and six months ended June 30, 2016 compared to the same periods in 2015. This was the net effect of:


•	higher ANR Southeast Mainline transportation revenues and lower OM&A expenses, offset by a first quarter 2015 non-recurring settlement


•	lower contributions from Mexican Pipelines primarily due to lower revenue


•	higher transportation revenues from Great Lakes


•	higher contribution from TC PipeLines, LP.

As well, a stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $6 million and $14 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 mainly because of a higher investment base on the NGTL System and the effect of a stronger U.S. dollar.

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SECOND QUARTER 2016

BUSINESS DEVELOPMENT

Business development expenses were lower by $8 million and $16 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 mainly due to capitalization of business development expenses, a focus on the Columbia acquisition and decreased business development activity.

OUTLOOK

The 2016 earnings outlook for the Canadian regulated and Mexican pipelines remain consistent with what we disclosed in the 2015 Annual Report. Earnings for the existing U.S. Pipelines are expected to be slightly higher this year as a result of higher revenues and lower costs. We are also expecting an increase in 2016 earnings as a result of the acquisition of Columbia on July 1, 2016 although the impact of the related financing will be reflected in our Corporate segment.

OPERATING STATISTICS - WHOLLY OWNED PIPELINES



six months ended June 30	Canadian Mainline¹		NGTL System²		ANR³
(unaudited)	2016	2015	2016	2015	2016	2015

Average investment base (millions of $)	4,398	4,925	7,357	6,505	n/a	n/a
Delivery volumes (Bcf):
Total	849	864	1,994	1,948	822	862
Average per day	4.7	4.8	11.0	10.8	4.5	4.8


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, 2016 were 530 Bcf (2015 – 564 Bcf). Average per day was 2.9 Bcf (2015 – 3.1 Bcf).


²	Field receipt volumes for the NGTL System for the six months ended June 30, 2016 were 2,075 Bcf (2015 – 2,006 Bcf). Average per day was 11.4 Bcf (2015 – 11.1 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 2016

Liquids Pipelines



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable EBITDA	280		313		580		618
Depreciation and amortization	(67	)	(66	)	(137	)	(129	)
Comparable EBIT	213		247		443		489
Specific items:
Keystone XL asset costs	(13	)	—		(23	)	—
Risk management activities	4		—		2		—
Segmented earnings	204		247		422		489

Liquids Pipelines segmented earnings decreased by $43 million and $67 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and included a pre-tax charge related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project, and unrealized gains from changes in the fair value of derivatives related to our liquids marketing business. These amounts have been excluded from our calculation of comparable EBIT. The remainder of the Liquids Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below.



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Keystone Pipeline System	279		317		586		628
Liquids Pipelines Business Development and Other	1		(4	)	(6	)	(10	)
Liquids Pipelines - comparable EBITDA	280		313		580		618
Depreciation and amortization	(67	)	(66	)	(137	)	(129	)
Liquids Pipelines - comparable EBIT	213		247		443		489

Comparable EBIT denominated as follows:
Canadian dollars	57		55		112		115
U.S. dollars	120		156		250		303
Foreign exchange impact	36		36		81		71
	213		247		443		489

Comparable EBITDA for the 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 decreased by $38 million and $42 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and was the net effect of:


•	lower uncontracted volumes on Keystone Pipeline


•	lower volumes on Marketlink

TRANSCANADA [16

SECOND QUARTER 2016


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

BUSINESS DEVELOPMENT AND OTHER

Business development and other, which primarily includes business development activity and our marketing business, increased by $5 million and $4 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and was the net effect of:


•	lower business development spending


•	growing contribution of Liquids Marketing.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $1 million and $8 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to the effect of a stronger U.S. dollar.

OUTLOOK

Following our Keystone XL impairment charge in 2015, future expenditures on the project for the maintenance and liquidation of project assets, expected to be approximately $55 million before tax ($36 million after tax) in 2016, are being expensed pending further advancement of this project. These costs will be excluded from comparable earnings.

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SECOND QUARTER 2016

Energy



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable EBITDA	236		267		565		650
Depreciation and amortization	(82	)	(84	)	(170	)	(169	)
Comparable EBIT	154		183		395		481
Specific items:
Alberta PPA terminations	—		—		(240	)	—
Risk management activities	224		79		101		(10	)
Segmented earnings	378		262		256		471

Energy segmented earnings increased by $116 million and decreased by $215 million for the three and six months ended June 30, 2016 compared to the same periods in 2015.

Energy segmented earnings included the following specific items that have been excluded from comparable EBIT:


•	a $240 million pre-tax charge, which included a $29 million impairment of our equity investment in ASTC Power Partnership, on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs in March 2016


•	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)	2016	2015		2016	2015

Canadian Power	20	29		7	7
U.S. Power	204	51		89	(17	)
Natural Gas Storage	—	(1	)	5	—
Total gains/(losses) from risk management activities	224	79		101	(10	)

The variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time; however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impact of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations.

Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast power assets, we were required to discontinue hedge accounting for certain cash flow hedges. This, along with the increased volume of our risk management activities associated with the expansion of our customer base in the PJM market, contributed to higher volatility in U.S. Power risk management activities. This increased level of volatility is reflected in the $204 million unrealized gain in second quarter 2016 and the $115 million unrealized loss in first quarter 2016.

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SECOND QUARTER 2016

The remainder of the Energy segmented earnings are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Canadian Power
Western Power¹	19		34		23		49
Eastern Power	85		90		188		220
Bruce Power	20		66		134		145
Canadian Power - comparable EBITDA^1,2	124		190		345		414
Depreciation and amortization	(36	)	(46	)	(82	)	(94	)
Canadian Power - comparable EBIT^1,2	88		144		263		320
U.S. Power (US$)
U.S. Power - comparable EBITDA	83		63		159		195
Depreciation and amortization	(32	)	(28	)	(62	)	(55	)
U.S. Power - comparable EBIT	51		35		97		140
Foreign exchange impact	13		8		30		32
U.S. Power - comparable EBIT (Cdn$)	64		43		127		172

Natural Gas Storage and other - comparable EBITDA	10		6		19		9
Depreciation and amortization	(3	)	(3	)	(6	)	(6	)
Natural Gas Storage and other - comparable EBIT	7		3		13		3

Business Development comparable EBITDA and EBIT	(5	)	(7	)	(8	)	(14	)
Energy - comparable EBIT^1,2	154		183		395		481

Summary
Energy - comparable EBITDA^1,2	236		267		565		650
Comparable depreciation and amortization	(82	)	(84	)	(170	)	(169	)
Energy - comparable EBIT^1,2	154		183		395		481


¹	Included Sundance A and Sheerness PPAs, and the Sundance B PPA held through our investment in ASTC Power Partnership up to March 7, 2016.


²	Included our share of equity income from our investments in ASTC Power Partnership up to March 7, 2016, Portlands Energy and Bruce Power.

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SECOND QUARTER 2016

Comparable EBITDA for Energy decreased by $31 million for the three months ended June 30, 2016 compared to the same period in 2015 due to the net effect of:


•	lower earnings from Bruce Power mainly due to higher planned outage days, partially offset by lower depreciation


•	higher earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant in Lebanon, Pennsylvania acquired February 1, 2016 and insurance recoveries related to an unplanned outage at Ravenswood


•	lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes following the termination of the PPAs


•	lower earnings from Eastern Power due to lower contractual earnings at Bécancour.

Comparable EBITDA for Energy decreased by $85 million for the six months ended June 30, 2016 compared to the same period in 2015 due to the net effect of:


•	lower earnings from U.S. Power mainly due to decreased margins on sales to wholesale, commercial and industrial customers, the impact of lower capacity prices in New York and lower realized prices in both New England and New York, offset by incremental earnings from the Ironwood power plant and insurance recoveries related to an unplanned outage at Ravenswood


•	lower earnings from Eastern Power due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour


•	lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes following the termination of the PPAs


•	lower earnings from Bruce Power mainly due to higher planned outage days, partially offset by lower depreciation and higher gains from contracting activities


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

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SECOND QUARTER 2016

CANADIAN POWER

Western and Eastern Power



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Revenue¹
Western Power	56		178		131		286
Eastern Power	108		114		203		239
Other²	—		3		29		48
	164		295		363		573
Comparable income from equity investments³	7		10		7		15
Commodity purchases resold	—		(93	)	(59	)	(183	)
Plant operating costs and other	(47	)	(59	)	(93	)	(129	)
Exclude risk management activities¹	(20	)	(29	)	(7	)	(7	)
Comparable EBITDA⁴	104		124		211		269
Depreciation and amortization	(36	)	(46	)	(82	)	(94	)
Comparable EBIT⁴	68		78		129		175

Breakdown of comparable EBITDA
Western Power⁴	19		34		23		49
Eastern Power	85		90		188		220
Comparable EBITDA⁴	104		124		211		269


¹	The realized and unrealized gains and losses from financial derivatives used to manage Canadian Power’s assets are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives included in revenue are excluded to arrive at Comparable EBITDA.


²	Includes revenues from the sale of unused natural gas transportation and sale of excess natural gas purchased for generation.


³	Includes our share of equity income from our investments in ASTC Power Partnership, which held the Sundance B PPA, and Portlands Energy. Comparable equity income excludes a $29 million charge related to the Sundance B PPA termination which was held in ASTC Power Partnership and does not include any gains or losses related to our risk management activities.


⁴	Includes Sundance A, Sundance B and Sheerness PPAs up to March 7, 2016.

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SECOND QUARTER 2016

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)	2016		2015		2016		2015

Sales volumes (GWh)
Supply
Generation
Western Power	528		650		1,218		1,287
Eastern Power	858		739		1,615		2,062
Purchased
Sundance A & B and Sheerness PPAs¹	—		2,299		1,620		4,492
Other purchases	177		193		388		396
	1,563		3,881		4,841		8,237
Sales
Contracted
Western Power	705		1,794		2,125		3,439
Eastern Power	858		739		1,615		2,062
Spot
Western Power	—		1,348		1,101		2,736
	1,563		3,881		4,841		8,237
Plant availability²
Western Power^3,4	83	%	97	%	91	%	97	%
Eastern Power⁵	97	%	98	%	92	%	98	%


¹	Includes volumes from Sundance A and Sheerness PPAs and our 50 per cent ownership interest of the Sundance B PPA held through the ASTC Power Partnership up to March 7, 2016.


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


³	Does not include facilities that provided power to us under PPAs.


⁴	Plant availability was lower in the three and six months ended June 30, 2016 than the same periods in 2015 due to an unplanned outage at the Mackay River facility as a result of the Northern Alberta wildfires.


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

Western Power

Comparable EBITDA for Western Power decreased by $15 million and $26 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to lower realized power prices and lower PPA volumes following the termination of the PPAs.

Results from the Alberta PPAs are included up to March 7, 2016 when we sent notice to the Balancing Pool to terminate the PPAs for the Sundance A, Sundance B and Sheerness facilities. Comparable income from equity investments included earnings from the ASTC Power Partnership which held our 50 per cent ownership in the Sundance B PPA. See the Recent developments section for more information on the PPA terminations.

Average spot market power prices in Alberta decreased 74 per cent from $57/MWh to $15/MWh for the three months ended June 30, 2016 and decreased 60 per cent from $43/MWh to $17/MWh for the six months ended June 30, 2016, compared to the same periods in 2015. The Alberta power market remained well supplied and power consumption was down due to a weak economy, warm weather and the Northern Alberta wildfires. 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.

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SECOND QUARTER 2016

One hundred per cent of Western Power sales volumes were sold under contract in second quarter 2016 compared to 57 per cent in second quarter 2015.

Depreciation and amortization decreased by $10 million in second quarter 2016 compared to second quarter 2015 following the termination of the PPAs.

We continue to expect Western Power 2016 earnings to be consistent with 2015 earnings. Although Alberta power prices are expected to remain low in 2016, the natural gas-fired cogeneration assets are expected to perform well in the lower gas price environment and the March 2016 decision to exercise the right to terminate the PPAs is expected to result in savings from the otherwise increased costs related to carbon emissions.

Eastern Power

Comparable EBITDA for Eastern Power decreased by $5 million and $32 million for the three and six months ended June 30, 2016 compared to the same periods in 2015. These decreases were mainly due to lower contractual earnings at Bécancour. In addition, Eastern Power had lower earnings on the sale of unused natural gas transportation for the six months ended June 30, 2016 compared to the same period in 2015.

Our 2016 earnings outlook provided in the 2015 Annual Report will be unfavourably impacted as a result of a delay in the implementation of amendments to the Bécancour electricity supply contract. See the Recent developments section for more information about the Bécancour tolling agreement.

BRUCE POWER

Results reflect our proportionate share. Bruce A and B were merged in December 2015 and comparative information for 2015 is reported on a combined basis to reflect the merged entity.



	three months ended June 30						six months ended June 30
(unaudited - millions of $, unless noted otherwise)	2016			2015			2016			2015

Income from equity investments¹	20			66			134			145

Comprised of:
Revenues	318			316			729			647
Operating expenses	(218		)	(167		)	(439		)	(339		)
Depreciation and other	(80		)	(83		)	(156		)	(163		)
	20			66			134			145
Bruce Power - Other information
Plant availability²	71		%	75		%	80		%	84		%
Planned outage days	209			160			285			199
Unplanned outage days	4			13			12			22
Sales volumes (GWh)¹	4,700			4,365			10,534			9,349
Realized sales price per MWh^3,4		$68			$68			$66			$66


¹	Represents our 48.5 per cent ownership interest in Bruce Power after the merger on December 4, 2015 and our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B up to December 3, 2015. Sales volumes include deemed generation.


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


³	Calculation based on actual and deemed generation. Realized sales prices per MWh includes revenues from contract settlements and cost flow-through items.


⁴	Excludes unrealized gains and losses on contracting activities and revenues from cobalt sales.

Equity income from Bruce Power decreased by $46 million and $11 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 mainly due to lower volumes resulting from higher planned outage days

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SECOND QUARTER 2016

partially offset by lower depreciation as a result of the Bruce Power facility's operating life extension. In addition, Bruce Power had higher gains from contracting activities for the six months ended June 30, 2016 compared to the same period in 2015.

In December 2015, Bruce Power entered into an agreement with the IESO to extend the operating life of the Bruce Power facility to 2064. As part of this agreement, Bruce Power began receiving a uniform price of $65.73 per MWh for all units, which includes certain flow-through items such as fuel and lease expenses recovery. Over time, the price will be subject to adjustments for the return of and on capital invested under the Asset Management and Major Component Replacement capital programs, along with various other pricing adjustments that allow for a better matching of revenues and costs over the long term.



Bruce Power contract price¹	per MWh

January 1, 2016 - March 31, 2016	$65.73
April 1, 2016 - March 31, 2017	$66.38


¹	Includes fuel and lease expenses recovery on a flow-through basis estimated at approximately $8.00 per MWh.

Prior to the amended agreement with the IESO, all of the output from Bruce Units 1 to 4 was sold at a fixed price/MWh which was adjusted annually on April 1 for inflation and other provisions under the contract.



Bruce Units 1 to 4 contract price¹	per MWh

April 1, 2014 - March 31, 2015	$76.70
April 1, 2015 - December 31, 2015	$78.42


¹	Includes fuel expense recovery on flow-through basis estimated at approximately $5.00 per MWh.

Prior to the amended agreement with the IESO, all output from Bruce Units 5 to 8 was subject to a floor price adjusted annually for inflation on April 1.



Bruce Units 5 to 8 floor price	per MWh

April 1, 2014 - March 31, 2015	$52.86
April 1, 2015 - December 31, 2015	$54.13

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

The contract with the IESO provides for payment if the IESO reduces Bruce Power’s generation to balance the supply of and demand for electricity and/or manage other operating conditions of the Ontario power grid. The amount of the reduction is considered deemed generation for which Bruce Power is paid the contract price.

During second quarter 2016, Bruce units 1 to 4 were removed from service for approximately three weeks to facilitate a station containment outage. The station containment outage involved inspecting and maintaining key safety systems including containment structures and is required to be completed approximately once every decade. Planned maintenance on unit 8 and unit 2 was also completed in second quarter 2016, while planned maintenance activities on unit 3 will continue into third quarter 2016. Additional planned maintenance is scheduled in fourth quarter 2016. The overall average plant availability percentage in 2016 is expected to be in the low 80s.

We expect 2016 equity income from Bruce Power to be slightly higher than our 2016 Outlook in the 2015 Annual Report.

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SECOND QUARTER 2016

U.S. POWER



	three months ended June 30				six months ended June 30
(unaudited - millions of US$)	2016		2015		2016		2015

Revenue
Power¹	571		379		902		984
Capacity	77		88		139		155
	648		467		1,041		1,139
Commodity purchases resold	(289	)	(271	)	(594	)	(747	)
Plant operating costs and other²	(116	)	(92	)	(215	)	(210	)
Exclude risk management activities¹	(160	)	(41	)	(73	)	13
Comparable EBITDA	83		63		159		195
Depreciation and amortization	(32	)	(28	)	(62	)	(55	)
Comparable EBIT	51		35		97		140


¹	The realized and unrealized gains and losses from financial derivatives used to manage U.S. Power’s assets are presented on a net basis in Power revenues. The unrealized gains and losses from financial derivatives included in revenue are excluded to arrive at Comparable EBITDA.


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)	2016		2015		2016		2015

Physical sales volumes (GWh)
Supply
Generation¹	3,376		2,135		5,656		3,049
Purchased	5,062		4,456		9,810		8,881
	8,438		6,591		15,466		11,930

Plant availability^2,3	86	%	77	%	79	%	69	%


¹	Increase primarily due to Ironwood acquisition.


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


³	Plant availability was lower in the three and six months ended June 30, 2015 compared to the same periods in 2016 due to an unplanned outage at the Ravenswood facility from September 2014 to May 2015.

U.S. Power - other information



	three months ended June 30		six months ended June 30
(unaudited)	2016	2015	2016	2015

Average Spot Power Prices (US$ per MWh)
New England¹	24	25	27	55
New York²	26	28	27	51
PJM³	22	n/a	23	n/a
Average New York² Spot Capacity Prices (US$ per KW-M)	10.12	12.92	7.98	10.63


¹	New England ISO all hours Mass Hub price.


²	Zone J market in New York City where the Ravenswood plant operates.


³	The METED Zone price in Pennsylvania where the Ironwood plant operates. Average price for the six months ended June 30, 2016 is from the Ironwood acquisition date of February 1 to June 30, 2016.

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SECOND QUARTER 2016

Comparable EBITDA for U.S. Power increased US$20 million for the three months ended June 30, 2016 compared to the same period in 2015 primarily due to the net effect of:


•	higher earnings due to our acquisition of the Ironwood power plant on February 1, 2016


•	higher earnings resulting from the timing of recognizing earnings on certain contracts in our power marketing business due to different power pricing profiles between the prices we charge our customers and the prices we pay for volumes purchased


•	insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008


•	lower capacity revenues due to lower realized capacity prices in New York and the impact of lower availability as a result of a unit outage from September 2014 to May 2015, partially offset by insurance recoveries, net of deductibles at Ravenswood.

Comparable EBITDA for U.S. Power decreased US$36 million for the six months ended June 30, 2016 compared to the same period in 2015 primarily due to the net effect of:


•	lower margins on sales to wholesale, commercial and industrial customers offset by higher sales to customers in the PJM market


•	lower capacity revenues due to lower realized capacity prices in New York and the impact of lower availability as a result of a unit outage from September 2014 to May 2015, partially offset by insurance recoveries, net of deductibles at Ravenswood


•	lower realized power prices at our facilities in New York and New England, partially offset by lower fuel costs


•	higher earnings due to our acquisition of the Ironwood power plant


•	insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008.

The timing of recognizing earnings on certain contracts in our U.S. power marketing business is impacted by different power pricing profiles between the prices we charge our customers and the prices we pay for volumes purchased to fulfill our sales obligations over the term of the contracts. The costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers include the impact of certain contracts to purchase power over multiple periods at a flat price. Because the price we charge our customers is typically shaped to the market, the impact of these two contract pricing profiles has generally resulted in higher earnings in January to March, offset by lower earnings between April and December with overall positive margins realized over

the term of the contracts.

Average New York Zone J spot capacity prices were approximately 22 per cent and 25 per cent lower for the three and six months ended June 30, 2016 compared to the same periods in 2015. The decrease in spot prices and the offsetting impact of hedging activities resulted in lower realized capacity prices in New York. This was primarily due to an increase in demonstrated capability from existing resources in New York City's Zone J market. The impact of lower capacity prices was partially offset by capacity revenues earned by our Ironwood power plant acquired in February 2016.

Capacity revenues were also negatively impacted by a unit outage from September 2014 to May 2015 at Ravenswood. The calculation used by the NYISO to determine the capacity volume for which a generator is compensated utilizes a rolling average forced outage rate. As a result of this methodology, outages impact capacity volumes and associated revenues on a lagged basis. Accordingly, capacity revenues for the three and six months ended June 30, 2016 were negatively impacted compared to the same periods in 2015. The outage continues to be included in the rolling average forced outage rate. All insurance recoveries for this event have been received and are being recognized in capacity revenues to offset amounts lost during the periods impacted by the lower forced outage rate. As a result of these insurance recoveries, the Unit 30 unplanned outage has not had a significant impact on our earnings although the recording of earnings has not coincided with lost revenues due to timing of the insurance proceeds. In addition, insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008 were received in June 2016 and a portion of the proceeds were recognized in Power Revenue.

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SECOND QUARTER 2016

Wholesale electricity prices in New York and New England were lower for the three and six months ended June 30, 2016 compared to the same periods in 2015 primarily due to unseasonably warm weather in winter 2016. In New England, spot power prices for the three and six months ended June 30, 2016 were four per cent and 51 per cent lower compared to the same periods in 2015. In New York City, spot power prices for the three and six months ended June 30, 2016 were seven per cent and 47 per cent lower compared to the same periods in 2015. Both markets have also experienced lower natural gas commodity prices during 2016 compared to the same period in 2015.

Lower margins to wholesale, commercial and industrial customers in both PJM and New England markets resulted in lower earnings for the six months ended June 30, 2016 compared to the same period in 2015, the impact of which was primarily seen in first quarter earnings. Although we have expanded our customer base in the PJM market, significantly lower realized power prices and mild winter weather have resulted in lower margins in our wholesale business.

Physical generation volumes in 2016 were higher compared to the same period in 2015 due to our acquisition of the Ironwood power plant and higher generation at our Ravenswood facilities. Physical purchased volumes sold to wholesale, commercial and industrial customers were higher for the three and six month months ended June 30, 2016 than the same periods in 2015 as we have expanded our customer base in the PJM market.

As at June 30, 2016, approximately 4,700 GWh, or 60 per cent, of U.S. Power’s planned generation was contracted for the remainder of 2016 and 4,200 GWh, or 34 per cent, for 2017. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.

U.S. Power results for 2016 will be dependent on the timing of the previously announced monetization of the U.S. Northeast power assets. See the Recent developments section for more information about the Columbia acquisition and related financing. Nevertheless, operating results for the full year in 2016 are expected to be lower than our Outlook in our 2015 Annual Report due to lower commodity prices experienced in the first half of 2016 and forecast for the remainder of the year.

NATURAL GAS STORAGE AND OTHER

Comparable EBITDA increased by $4 million and $10 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 mainly due to increased storage revenues as a result of higher realized natural gas storage price spreads.

The full year 2016 results are expected to be higher compared to 2015 due to the lack of seasonal winter weather conditions, excess natural gas supply and resulting increase in natural gas storage price spreads which have provided the opportunity to hedge available storage capacity at higher values than originally expected in the Outlook in our 2015 Annual Report.

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SECOND QUARTER 2016

Corporate

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable EBITDA	(27	)	(12	)	(52	)	(36	)
Depreciation and amortization	(7	)	(8	)	(16	)	(15	)
Comparable EBIT	(34	)	(20	)	(68	)	(51	)
Specific items:
Acquisition costs - Columbia Pipeline Group	(10	)	—		(36	)	—
Restructuring costs	(14	)	(12	)	(14	)	(12	)
Segmented losses	(58	)	(32	)	(118	)	(63	)

Corporate segmented losses in 2016 increased by $26 million and $55 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT:


•	costs associated with the acquisition of Columbia


•	restructuring costs related to expected future losses under lease commitments.

Interest Expense



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable interest on long-term debt (including interest on junior subordinated notes)
Canadian-dollar denominated	(110	)	(106	)	(221	)	(215	)
U.S. dollar-denominated (US$)	(250	)	(228	)	(496	)	(446	)
Foreign exchange impact	(73	)	(57	)	(158	)	(105	)
	(433	)	(391	)	(875	)	(766	)
Other interest and amortization expense	(18	)	(11	)	(37	)	(24	)
Capitalized interest	46		71		87		141
Comparable interest expense	(405	)	(331	)	(825	)	(649	)
Specific item:
Acquisition costs - Columbia Pipeline Group¹	(109	)	—		(109	)	—
Interest expense	(514	)	(331	)	(934	)	(649	)


¹	This amount represents the dividend equivalent payments on the subscription receipts. See the Financial condition section for more information on the subscription receipts.

Comparable interest expense increased by $74 million and $176 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to the net effect of:


•	higher interest expense as a result of long-term debt issuances in 2015 and 2016, partially offset by Canadian and U.S. dollar-denominated debt maturities

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SECOND QUARTER 2016


•	a stronger U.S. dollar and its effect on the foreign exchange impact on interest expense related to U.S. dollar-denominated debt


•	lower capitalized interest on Keystone XL and related projects following the November 6, 2015 denial of a U.S. Presidential Permit, partially offset by higher capitalized interest on liquids projects, LNG projects and the Napanee power generating facility.

Interest income and other



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016	2015

Comparable interest income and other
AFUDC	111		68		212	126
Other	4		(17	)	51	(60	)
	115		51		263	66
Specific items:
Acquisition costs - Columbia Pipeline Group¹	6		—		6	—
Risk management activities	(4	)	30		49	1
Interest income and other	117		81		318	67


¹	This amount represents interest income on the gross proceeds of the subscriptions receipts held in escrow. See the Financial condition section for more information on the subscription receipts.

Comparable interest income and other increased by $64 million and $197 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to the net effect of:


•	increased AFUDC related to our rate-regulated projects including Mexico pipelines, expansions on the NGTL System and the ANR Southeast Mainline


•	realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income.

Income tax expense



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable income tax expense	(189	)	(185	)	(369	)	(432	)
Specific items:
Alberta PPA terminations	—		—		64		—
Acquisition costs - Columbia Pipeline Group	—		—		—		—
Keystone XL asset costs	4		—		8		—
Restructuring costs	4		4		4		4
TC Offshore loss on sale	—		—		1		—
Alberta corporate income tax rate increase	—		(34	)	—		(34	)
Risk management activities	(93	)	(35	)	(52	)	5
Income tax expense	(274	)	(250	)	(344	)	(457	)

Comparable income tax expense increased by $4 million and decreased by $63 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and was mainly the result of lower pre-tax earnings in 2016 compared to 2015, changes in the proportion of income earned between Canadian and foreign jurisdictions and lower flow-through taxes in 2016 on Canadian regulated pipelines.

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SECOND QUARTER 2016

Net income attributable to non-controlling interests



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Net income attributable to non-controlling interests	(52	)	(40	)	(132	)	(99	)

Net income attributable to non-controlling interests increased by $12 million and $33 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 primarily due to the sale of our 30 per cent direct interest in GTN in April 2015 and 49.9 per cent direct interest in PNGTS in January 2016 to TC PipeLines, LP and the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP.

Preferred share dividends



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Preferred share dividends	(28	)	(25	)	(50	)	(48	)

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SECOND QUARTER 2016

Recent developments

ACQUISITION OF COLUMBIA PIPELINE GROUP, INC.

Acquisition

On July 1, 2016, we closed the acquisition of Columbia valued at US$13 billion comprised of a purchase price of approximately US$10.3 billion and Columbia debt of approximately US$2.7 billion. The acquisition was financed through proceeds of $4.4 billion from the sale of subscription receipts, bridge term loan credit facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and following the closing of the acquisition, were exchanged into 96.6 million TransCanada common shares and delisted from the TSX. See Financial condition section for additional information on the bridge term loan credit facilities and the subscription receipts.

Columbia operates a portfolio of 24,250 km (15,100 miles) of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets. We acquired Columbia to expand our natural gas business in the U.S. market, positioning ourselves for long-term growth opportunities. The acquisition also includes a large portfolio of new capital growth projects totalling approximately US$7.3 billion which includes six pipeline expansion projects designed to transport growing supply from the Marcellus / Utica production basins to markets as well as a scheduled program for modernization of existing infrastructure out to 2021 to ensure a safe, reliable and efficient system. We have plans in place to ensure an effective transition to integrate Columbia into the TransCanada organization.

Acquisition-related expenses were $10 million and $36 million for the three and six months ended June 30, 2016 and have been excluded from comparable earnings. The dividend equivalent payments on the subscription receipts of $109 million were included in interest expense in the three and six months ended June 30, 2016 and the interest earned on the funds received from the subscription receipts held in escrow of $6 million have also been excluded from comparable earnings.

Monetization of U.S. Northeast power assets and a minority interest in Mexican pipelines

The permanent financing for the acquisition of the Columbia Pipeline Group involves portfolio management that includes the monetization of our U.S. Northeast power assets and a minority interest in our Mexico gas pipeline business.

The process of engaging advisors has been completed and the initial stages of soliciting interested parties is well underway. We expect to provide an update as to the outcome of that process by the end of 2016. Proceeds from these monetizations will be used to retire draws under the bridge term loan credit facilities.

Master Limited Partnership strategy review

On July 1, 2016, we announced that a financial advisor has been retained to assist us in developing a master limited partnership (MLP) strategy. A decision on the MLP strategy is expected to be communicated by the end of 2016.

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SECOND QUARTER 2016

NATURAL GAS PIPELINES

Canadian Regulated Pipelines

NGTL System

In second quarter 2016, we placed approximately $450 million of facilities in service with another $400 million of facilities approved and currently under construction, while approximately $2.9 billion of commercially secured expansion projects have not yet been filed with the regulators.

We continue to work closely with our shippers to ensure that new proposed facilities meet our shippers and market demands. We recently added new long term delivery contracts on the NGTL System to meet demand in the Pacific Northwest and California. These contracts will require the construction of a new approximately $135 million facility (the Sundre Crossover Project) that was not previously included in our 2018 Facilities program. The open season process followed for the development of these new contracts identified further demand for service to this market that we are currently assessing.

We have also seen some cancellation or deferral of our customer’s specific projects, contract non-renewals, and contract transfers. As a result, we have re-evaluated planned facility requirements to meet future aggregate system service requirements and expect some changes in the spending profile of our programs to match revised facility in-service dates. The projected capital for the NGTL System remains at approximately $7.3 billion, including the new Sundre Crossover project, the North Montney and Merrick pipelines and the cancellation of a $66 million project. We are however, deferring approximately $225 million of spending for facilities in the 2016/17 Facilities program with revised service dates of 2018 through 2020. We are also deferring $210 million of spending for facilities in the 2018 Facilities program with revised service dates of 2019 and 2020.

North Montney Mainline

In March 2016, we filed a request with the NEB for a one year extension to the June 10, 2016 sunset clause in the North Montney Mainline (NMML) project Certificate of Public Convenience and Necessity (CPCN). The NEB has extended the sunset clause until the end of the year to allow time to further review the request and make a final decision subject to Governor-In-Council approval. A pre-construction CPCN condition requires that Petronas make a positive FID on the proposed Pacific Northwest LNG (PNW LNG) Project. Petronas is waiting on completion of the federal environmental assessment process for the LNG Project before it makes an FID. The environmental review process is currently scheduled to conclude this fall. NGTL continues to work with our customers and stakeholders to be ready to initiate construction of the NMML facilities for an in-service date as early as 2017, however, the in-service date will be finalized once a FID has been made.

2016-2017 NGTL Revenue Requirement Settlement

On April 7, 2016, the NEB approved the NGTL revenue requirement settlement application that was filed in December 2015, subject to certain reporting requirements. The settlement includes a ROE of 10.1 per cent on a deemed common equity of 40 per cent, continuation of 2015 depreciation rates, a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration cost amount and flow-through treatment of all other costs.

U.S. Pipelines

Iroquois Gas Transmission System

On March 31, 2016, we closed the acquisition of an additional 4.87 per cent interest in Iroquois Gas Transmission System, L.P. (Iroquois) from one of our partners for US$54 million. Following this acquisition, our ownership interest in Iroquois increased to 49.35 per cent. On May 1, 2016, we acquired an additional 0.65 per cent interest from the remaining partner equalizing our overall ownership interests to 50 per cent each.

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SECOND QUARTER 2016

ANR Section 4 Rate Case

In January 2016, ANR filed a Section 4 Rate Case with the FERC that requests an increase to ANR's maximum transportation rates. In February 2016, the FERC issued an order that accepted and suspended ANR’s rate and tariff changes to become effective August 1, 2016, subject to refund and the outcome of a hearing. In addition, in March 2016, the FERC established a procedural schedule for the hearing and appointed a settlement judge to assist the parties in their settlement negotiations. The hearing is currently scheduled for early February 2017.

TC Offshore

Effective March 31, 2016, we completed the sale of TC Offshore LLC to a third party. The sale includes 860 km (535 miles) of natural gas gathering and transmission pipeline, seven offshore platforms and other facilities.

Mexico

Tula-Villa de Reyes Pipeline

On April 11, 2016, we announced we were awarded the contract to build, own and operate the Tula-Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 million cubic feet per day with the CFE. We expect to invest approximately US$550 million to construct a 36-inch diameter, 420 km (261 mile) pipeline with an anticipated in-service date of early 2018. The pipeline will begin in Tula, in the state of Hidalgo, and terminate in Villa de Reyes, in the state of San Luis Potosí, transporting natural gas to power generation facilities in the central region of the country. The project will interconnect with our Tamazunchale and Tuxpan-Tula pipelines as well as with other transporters in the region.

Sur de Texas-Tuxpan Pipeline

On June 13, 2016, we announced that our joint venture with IEnova had been chosen to build, own and operate the

US$2.1 billion Sur de Texas to Tuxpan pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 2.6 billion cubic feet per day with the CFE. We expect to invest approximately

US$1.3 billion in the partnership to construct the 42-inch diameter, approximately 800 km (497 mile) pipeline with an anticipated in-service date of late 2018. The pipeline will start offshore in the Gulf of Mexico, at the border point near Brownsville, Texas, and end in Tuxpan, Mexico in the state of Veracruz.

LNG Pipeline Projects

Prince Rupert Gas Transmission

PRGT continues to engage with Aboriginal groups and other stakeholders along the route in preparation for a FID by PNW LNG.

Coastal GasLink

On July 11th, 2016, the LNG Canada joint venture participants announced a delay to their FID for the proposed liquefied natural gas facility in Kitimat, BC. At this time a future FID date has not been determined. In light of this announcement, we are working with LNG Canada to determine the appropriate pacing of the Coastal GasLink development schedule and work activities.

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SECOND QUARTER 2016

LIQUIDS PIPELINES

Keystone Pipeline

On April 2, 2016, we shut down the Keystone pipeline after a leak was detected along the pipeline right-of-way in Hutchinson County, South Dakota. We reported the total volume of the release of 400 barrels to the National Response Center and the Pipeline and Hazardous Materials Safety and Administration (PHMSA). Temporary repairs were completed on April 9, 2016, and the Keystone pipeline was restarted on April 10, 2016. On May 5, 2016, permanent pipeline repairs were completed and restoration work was completed on July 3, 2016. Further investigative activities and corrective measures required by PHMSA are planned for 2016.

This shutdown is not expected to have a significant impact on our 2016 earnings.

Houston Lateral and Terminal

We commenced commercial transactions in July 2016 for August 2016 deliveries on the Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline System to Houston, Texas. The terminal has an initial storage capacity for 700,000 barrels of crude oil.

Energy East Pipeline

On March 1, 2016, the Province of Québec filed a court action seeking an injunction to compel the Energy East Pipeline to comply with the province’s environmental regulations. On March 30, 2016, the Québec Superior Court joined the injunction action led by the Province of Québec with the prior action led by Québec Environmental Law Centre / Centre québécois du droit de l’environnement (CQDE), which sought a declaration to compel Energy East to submit to the mandatory provincial environmental review process. As a result of communication with the Ministère du Développement durable, Environnement et la Lutte contre les changements climatiques, on April 22, 2016, we filed a project review engaging an environmental assessment under the Environmental Quality Act (Québec) according to an agreed upon schedule for key steps in that process. This process is in addition to environmental assessment required under the NEB Act and the Canadian Environmental Assessment Act, 2012. The Attorney General for Québec has agreed to suspend its litigation against TransCanada and Energy East and to withdraw it once the provincial environmental assessment process has been completed. The CQDE has similarly agreed to suspend the action. We do not anticipate this will result in a delay with regard to the NEB's review process.

On March 17, 2016, the first phase of Energy East public hearings for the voluntary Québec le Bureau d’audiences publiques sur l’environnement (BAPE) process was completed. The voluntary BAPE hearing process is intended to inform the Province of Québec in its participation in the federal process and provides project information to the public. A second phase, consisting of a series of public input sessions, has been suspended as it has been replaced with the environmental assessment as described above.

On May 17, 2016, we filed a consolidated application with the NEB for Energy East. On June 16, 2016, Energy East achieved a major milestone with the NEB’s announcement determining the Energy East application is sufficiently complete to initiate the formal regulatory review process. This determination of completeness also marks the start of the mandated 21 month NEB review process which culminates in a formal recommendation to the Governor in Council (Federal Cabinet). The Governor in Council will then have six months to decide whether to approve the project and if so, on what conditions. The NEB also noted, that starting on August 8, 2016, there will be a series of community panel sessions held along the pipeline route. On July 20, 2016, the NEB issued the hearing order which provides further detail on the regulatory process. We are currently reviewing the contents.

Keystone XL NAFTA challenge

On June 24, 2016, we filed a Request for Arbitration in a dispute against the U.S. Government pursuant to the Convention on Settlement of Investment Disputes between States and Nationals of Other States, the Rules of Procedure

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SECOND QUARTER 2016

for the Institution of Conciliation and Arbitration Proceedings and Chapter 11 of the North American Free Trade Agreement (NAFTA). The claim arises out of the November 6, 2015 denial of our application for a Presidential Permit to construct the Keystone XL Pipeline. We have requested an award of damages arising from the U.S. Government’s breaches of its NAFTA obligations in an amount of more than US$15 billion, together with applicable interest and the costs of arbitration.

ENERGY

Alberta PPAs

On March 7, 2016, we issued notice to the Balancing Pool to terminate our Alberta PPAs. The arrangements contain a provision that permits the PPA buyers to terminate the PPAs if there is a change in the law that makes the arrangements unprofitable or more unprofitable. This termination affects the Sheerness, Sundance A and Sundance B PPAs. On July 22, 2016, we, along with the ASTC Power Partnership, referred the matter to be resolved by binding arbitration pursuant to the dispute resolution provisions of the PPAs. On July 25, 2016, the Government of Alberta brought an application in the Court of Queen’s Bench to prevent the Balancing Pool from allowing termination of a PPA held by another party which contains identically worded termination provisions to our PPAs. The outcome of this court application may affect resolution of the arbitration of the Sheerness, Sundance A and Sundance B PPAs. Unprofitable market conditions are expected to continue as costs related to carbon emissions have increased and are forecast to continue to increase over the remaining term of the PPA agreements. We expect the termination will improve cash flow and comparable earnings in the near term.

As a result of our decision to terminate the PPAs, we recorded a non-cash impairment charge of $240 million before tax ($176 million after tax) comprised of $211 million before tax ($155 million after tax) related to the carrying value of our Sundance A and Sheerness PPAs and $29 million before tax ($21 million after tax) on our equity investment in the ASTC Power Partnership which holds the Sundance B PPA.

Ontario carbon tax

In May 2016, legislation enabling Ontario’s cap and trade program was signed into law with the new regulation taking effect July 1, 2016. This regulation will set a limit on annual province-wide greenhouse gas emissions beginning in January 2017 and will introduce a market to administer the purchase and trading of emissions allowances. The regulation places the compliance obligation for emissions from our natural gas fired power facilities on local gas distributors, with the latter flowing the associated costs to the assets.

The IESO is continuing to develop proposed contract amendments for eligible contract holders to address costs and other issues associated with this change in law. Impacted contracts have varying provisions with respect to amendment entitlement and management is reviewing each of our contracts to assess potential impacts.

Bécancour tolling agreement

In August 2015, we executed an agreement with Hydro Québec (HQ) allowing HQ to dispatch up to 570 MW of peak winter capacity from our Bécancour facility for a term of 20 years commencing in December 2016. The regulator in Québec, Régie de l'énergie (the Régie), initially accepted this agreement for implementation but in July 2016, the Régie reversed this initial decision. HQ is considering its regulatory options in light of this development, as the need for winter peaking capacity remains.

Bruce Power financing

In second quarter 2016, Bruce Power issued bonds and borrowed under its bank credit facility as part of a financing program to fund its capital program and make distributions to its partners. Distributions received from Bruce Power in second quarter 2016 included $725 million from this financing program.

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SECOND QUARTER 2016

Financial condition

We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash flow to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings.

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

CASH PROVIDED BY OPERATING ACTIVITIES



	three months ended June 30			six months ended June 30
(unaudited - millions of $)	2016	2015		2016	2015

Funds generated from operations¹	831	1,061		1,956	2,214
Decrease/(increase) in operating working capital	218	(92	)	138	(485	)
Net cash provided by operations	1,049	969		2,094	1,729


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

Funds generated from operations decreased $230 million and $258 million for the three and six months ended June 30, 2016 compared to the same periods in 2015. These decreases were primarily due to $109 million of dividend equivalent payments on the subscription receipts issued to partially finance the Columbia acquisition.

At June 30, 2016, our current assets were $4.6 billion and current liabilities were $9.9 billion, leaving us with a working capital deficit of $5.3 billion compared to a deficit of $3.4 billion at December 31, 2015. The increase was mainly due to subscription receipts held in preparation for the closing of the Columbia acquisition on July 1, 2016. Our 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


•	our access to capital markets


•	approximately $8.7 billion of unutilized, unsecured committed credit facilities.

COMPARABLE DISTRIBUTABLE CASH FLOW



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016			2015

Net cash provided by operations	1,049		969		2,094			1,729
(Decrease)/increase in operating working capital	(218	)	92		(138		)	485
Funds generated from operations	831		1,061		1,956			2,214
Dividends on preferred shares	(23	)	(24	)	(46		)	(46		)
Distributions paid to non-controlling interests	(62	)	(54	)	(124		)	(108		)
Distributions received in excess of equity earnings¹	99		64		187			110
Maintenance capital expenditures including equity investments	(269	)	(194	)	(459		)	(361		)
Distributable cash flow	576		853		1,514			1,809
Specific items (net of tax):
Acquisition costs - Columbia Pipeline Group	113		—		139			—
Keystone XL asset costs	9		—		15			—
Restructuring costs	—		8		—			8
Comparable distributable cash flow	698		861		1,668			1,817
Comparable distributable cash flow per common share	$0.99		$1.21			$2.37			$2.56


¹	Reflects distributions received from operating activities and excludes additional distributions of $725 million following Bruce Power's financing program.

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SECOND QUARTER 2016

Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation. See our non-GAAP measures section for more information.

Maintenance capital expenditures on our Canadian regulated natural gas pipelines were $42 million and $97 million for the three and six months ended June 30, 2016 compared to $61 million and $114 million for the same periods in 2015, which contributed to their respective rate bases and net income.

CASH USED IN INVESTING ACTIVITIES



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Capital spending
Capital expenditures	(982	)	(966	)	(1,818	)	(1,772	)
Capital projects in development	(90	)	(172	)	(157	)	(335	)
	(1,072	)	(1,138	)	(1,975	)	(2,107	)
Contributions to equity investments	(114	)	(105	)	(284	)	(198	)
Restricted cash	(13,113	)	—		(13,113	)	—
Acquisitions, net of cash acquired	(4	)	—		(999	)	—
Proceeds from sale of assets, net of transaction costs	—		—		6		—
Distributions received in excess of equity earnings	824		64		912		110
Deferred amounts and other	(20	)	25		(20	)	204
Net cash used in investing activities	(13,499	)	(1,154	)	(15,473	)	(1,991	)

Capital expenditures in 2016 were primarily related to:


•	expansion of the NGTL System


•	construction of Mexico pipelines


•	expansion of the ANR pipeline


•	construction of the Northern Courier pipeline


•	expansion of the Canadian Mainline


•	construction of the Napanee power generating facility.

Costs incurred on capital projects under development primarily relate to the Energy East and LNG pipeline projects.

Contributions to equity investments have increased in 2016 compared to 2015 primarily due to our investments in Grand Rapids and Bruce Power.

Restricted cash represents the amount held in escrow at June 30, 2016 for the purchase of Columbia on July 1, 2016 and includes the proceeds from the sale of subscription receipts, net of dividend equivalent payments, and draws on the committed bridge loan credit facilities.

On February 1, 2016, we acquired the Ironwood natural gas fired, combined cycle power plant with a capacity of

778 MW, for US$657 million in cash before post-acquisition adjustments.

On March 31, 2016, we acquired an additional 4.87 per cent interest in Iroquois for an aggregate purchase price of

US$54 million. On May 1, 2016, we acquired an additional 0.65 per cent for an aggregate purchase price of

US$7 million. As a result of these acquisitions, our interest in Iroquois has increased to 50 per cent.

The increase in distributions received in excess of equity earnings is primarily due to distributions from Bruce Power. In second quarter 2016, Bruce Power issued bonds and borrowed under the bank credit facility as part of its financing program to fund its capital program and make distributions to the partners. Therefore, the distributions received from Bruce Power in second quarter 2016 were funded from both operating and financing activities and included

$725 million from Bruce Power financing program.

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SECOND QUARTER 2016

CASH PROVIDED BY FINANCING ACTIVITIES



	three months ended June 30				six months ended June 30
(unaudited - millions of $)	2016		2015		2016		2015

Notes payable issued/(repaid), net	(853	)	(749	)	323		(470	)
Long-term debt issued, net of issue costs	10,335		84		12,327		2,361
Long-term debt repaid	(933	)	(867	)	(2,290	)	(1,883	)
Junior subordinated notes issued, net of issue costs	—		917		—		917
Dividends and distributions paid	(482	)	(446	)	(932	)	(863	)
Common shares/subscription receipts issued, net of issue costs	4,371		1		4,374		11
Common shares repurchased	—		—		(14	)	—
Partnership units of subsidiary issued, net of issue costs	82		27		106		31
Preferred shares issued, net of issue costs	492		—		492		243
Net cash provided by/(used in) financing activities	13,012		(1,033	)	14,386		347

LONG-TERM DEBT ISSUED

(unaudited - millions of $)

Company

Issue date

Type

Maturity date

Amount

Interest rate

TRANSCANADA PIPELINES LIMITED

June 2016

Acquisition Bridge Facility¹

June 2018

US $5,213

Floating

June 2016

Medium Term Notes

July 2023

$300

3.690

June 2016

Medium Term Notes

June 2046

$700

4.350

January 2016

Senior Unsecured Notes

January 2019

US $400

3.125

January 2016

Senior Unsecured Notes

January 2026

US $850

4.875

ANR PIPELINE COMPANY

June 2016

Senior Unsecured Notes

June 2026

US $240

4.140

TRANSCANADA PIPELINE USA LTD.

June 2016

Acquisition Bridge Facility¹

June 2018

US $1,700

Floating

TUSCARORA GAS TRANSMISSION COMPANY

April 2016

Term Loan

April 2019

US $9.5

Floating


¹	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from specified asset monetizations must be used to repay these facilities. Proceeds from these facilities are held in Restricted cash. See Recent developments section for more information.


²	Reflects coupon rate. Re-issuance yield was 2.69 per cent.

LONG-TERM DEBT RETIRED



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

TRANSCANADA PIPELINES LIMITED
	June 2016	Senior Unsecured Notes	US $84		7.69	%
	June 2016	Senior Unsecured Notes	US $500		Floating
	January 2016	Senior Unsecured Notes	US $750		0.75	%
NOVA GAS TRANSMISSION LTD.
	February 2016	Debentures		$225	12.20	%

TRANSCANADA [38

SECOND QUARTER 2016

COMMON SHARES REPURCHASED

In November 2015, the TSX approved our normal course issuer bid (NCIB), which allows for the repurchase and cancellation of up to 21.3 million common shares, representing three per cent of our then issued and outstanding common shares, between November 23, 2015 and November 22, 2016 at prevailing market prices plus brokerage fees, or such other prices as may be permitted by the TSX. Since inception of the NCIB, 7.1 million shares were repurchased at an average price of $43.63. With the acquisition of Columbia, we do not anticipate further repurchases under this NCIB.

The following table summarizes shares repurchased in 2016 under the NCIB:



at June 30, 2016
(millions of $, except number of common shares and per share data)

Number of common shares repurchased¹	305,407
Weighted-average price per common share²		$44.90
Amount repurchased		$13.7


¹	Includes repurchases of common shares pursuant to private agreements with third-parties.


²	Includes brokerage fees.

SUBSCRIPTION RECEIPTS

On April 1, 2016, we issued 96.6 million subscription receipts to partially fund the Columbia acquisition at a price of $45.75 each for total proceeds of $4.4 billion. Each subscription receipt entitled the holder to automatically receive one common share upon closing of the Columbia acquisition on July 1, 2016. Holders received dividend equivalent payments per subscription receipt equal to dividends declared on each common share, with the first payment on April 29, 2016 for holders of record at close of business on April 15, 2016. The second dividend equivalent payment will be made on July 29, 2016 to holders of record at the close of business on June 30, 2016. For the three and six months ended June 30, 2016, $109 million of dividend equivalent payments were recorded as interest expense and have been excluded from comparable earnings. See the Reconciliation of non-GAAP measures section.

The gross proceeds from the sale of the subscription receipts, less any amounts used for dividend equivalent payments, were held in escrow pending the acquisition close on July 1, 2016 and recorded as Restricted cash as at June 30, 2016. Interest income of $6 million relating to the proceeds has also been excluded from comparable earnings. See the Reconciliation of non-GAAP measures section.

On July 4, 2016, the subscription receipts were automatically exchanged for TransCanada common shares in accordance with the terms of the subscription receipt agreement and were delisted from the TSX.

DIVIDEND REINVESTMENT PLAN

Under our Dividend Reinvestment Plan, eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with the dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent in lieu of receiving cash dividends.

PREFERRED SHARE ISSUANCE AND CONVERSION

In February 2016, holders of 1.3 million Series 5 cumulative redeemable first preferred shares exercised their option to convert to Series 6 cumulative redeemable first preferred shares and receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 1.54 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 5 preferred shares was reset for five years at 2.263 per cent per annum. Such rate will reset every five years.

On April 20, 2016, we completed a public offering of 20 million Series 13 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $500 million. The Series 13 preferred shareholders will have the right to convert their Series 13 preferred shares into Series 14 cumulative redeemable first preferred shares on May 31, 2021

TRANSCANADA [39

SECOND QUARTER 2016

and on the last business day of May of every fifth year thereafter. The holders of Series 14 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the sum of the then applicable 90-day Government of Canada treasury bill rate plus 4.69 per cent. The fixed dividend rate on the Series 13 preferred shares was set for its initial period at 5.5 per cent per annum and will reset every five years to a rate equal to the sum of the then applicable five-year Government of Canada bond yield plus 4.69 per cent subject to a floor of not less than 5.5 per cent per annum.

The following table summarizes the impact of the 2016 conversion and issuance of preferred shares discussed above:

(unaudited)

Number of
shares
issued and
outstanding (thousands)

Current yield¹

Annual dividend per share¹

Redemption price per share²

Redemption and conversion option date^1,2

Right to convert into

Cumulative first preferred shares

Series 5

12,714

2.263

$0.56575

$25.00

January 30, 2021

Series 6

1,286

Floating³

Floating

$25.00

January 30, 2021

Series 5

Series 13

20,000

5.5

$1.375

$25.00

May 31, 2021

Series 14


¹	Holders of the cumulative redeemable first preferred shares set out in this table are entitled to receive a fixed cumulative quarterly preferred dividend, as and when declared by the Board, with the exception of Series 6 preferred shares. The holders of Series 6 preferred shares are entitled to receive a quarterly floating rate cumulative preferred dividend, as and when declared by the Board.

We may, at our option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends, on the redemption option date and on every fifth anniversary date thereafter. In addition, Series 6 preferred shares are redeemable by us at any time other than on a designated redemption option date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.


³	Commencing June 30, 2016, the floating quarterly dividend rate for the Series 6 preferred shares is 2.034 per cent and will reset every quarter going forward.

TC PIPELINES, LP AT-THE-MARKET (ATM) EQUITY ISSUANCE PROGRAM

Since January 1, 2016, 1.6 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$83 million. Our ownership interest in TC PipeLines, LP decreased to 27.4 per cent as a result of issuances under the ATM program and resulting dilution.

In connection with the late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon the filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the ATM program may have a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to TC PipeLines, LP. No unitholder has claimed or attempted to exercise any rescission rights to date and these rights expire one year from the date of purchase of the unit.

DIVIDENDS

On July 27, 2016, we declared quarterly dividends as follows:



Quarterly dividend on our common shares

$0.565 per share
Payable on October 31, 2016 to shareholders of record at the close of business on September 30, 2016



Quarterly dividend equivalent payment on our subscription receipts¹

$0.565 per subscription receipt
Payable on July 29, 2016 to holders of record at the close of business on June 30, 2016


¹	Dividend equivalent payments are a term of the subscription receipts and are not declared by the Board.

TRANSCANADA [40

SECOND QUARTER 2016



Quarterly dividends on our preferred shares

Series 1	$0.204125
Series 2	$0.15528142
Series 3	$0.1345
Series 4	$0.11506284
Payable on September 30, 2016 to shareholders of record at the close of business on August 31, 2016
Series 5	$0.14143750
Series 6	$0.12781967
Series 7	$0.25
Series 9	$0.265625
Payable on October 31, 2016 to shareholders of record at the close of business on September 30, 2016
Series 11	$0.2375
Series 13	$0.34375
Payable on August 31, 2016 to shareholders of record at the close of business on August 12, 2016

SHARE INFORMATION



as at July 22, 2016

Common shares	Issued and outstanding
	800 million
Preferred shares	Issued and outstanding	Convertible to
Series 1	9.5 million	Series 2 preferred shares
Series 2	12.5 million	Series 1 preferred shares
Series 3	8.5 million	Series 4 preferred shares
Series 4	5.5 million	Series 3 preferred shares
Series 5	12.7 million	Series 6 preferred shares
Series 6	1.3 million	Series 5 preferred shares
Series 7	24 million	Series 8 preferred shares
Series 9	18 million	Series 10 preferred shares
Series 11	10 million	Series 12 preferred shares
Series 13	20 million	Series 14 preferred shares

Options to buy common shares	Outstanding	Exercisable
	11 million	7 million

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SECOND QUARTER 2016

CREDIT FACILITIES

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

At July 27, 2016, we had approximately $19.1 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 TCPL credit facility that supports TCPL's Canadian commercial paper program	December 2020
US$5.2 billion	—	TCPL	Committed, syndicated, senior asset sale bridge term loan commitment that supports the acquisition of Columbia¹	June 2018
US$1.0 billion	US$1.0 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility that supports TCPL's U.S. commercial paper program	December 2016
US$1.7 billion	—	TCPL USA	Committed, syndicated, senior asset sale bridge term loan commitment that supports the acquisition of Columbia¹	June 2018
US$1.5 billion	US$1.5 billion	TCPL USA	Committed, syndicated, revolving, extendible TCPL USA credit facility that is used for TCPL USA general corporate purposes	December 2016
US$1.5 billion	US$1.5 billion	TAIL/TCPM	Committed, syndicated, revolving, extendible credit facility that supports the joint TAIL/TCPM commercial paper program in the U.S.	December 2016
$1.9 billion	$0.5 billion	TCPL/TCPL USA	Supports the issuance of letters of credit and provides additional liquidity	Demand


¹	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at Libor plus an applicable margin. Proceeds from specified asset monetizations must be used to repay these facilities. See Recent developments section for more information.

At July 27, 2016, our operated affiliates had an additional $0.5 billion of undrawn capacity on committed credit facilities.

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

CONTRACTUAL OBLIGATIONS

Our capital commitments have increased by approximately $0.2 billion since December 31, 2015 as a result of the new commitments for the Tuxpan-Tula, Tula-Villa de Reyes and Sur de Texas-Tuxpan natural gas pipelines partially offset by decreased commitments on Grand Rapids and Napanee. Our other purchase obligations are consistent with the amounts reported at December 31, 2015.

Our commitments at December 31, 2015 included fixed payments net of sublease receipts for Alberta PPAs. With the March 7, 2016 notice to terminate our Sheerness, Sundance A and Sundance B PPAs, our future obligations from December 31, 2015 have decreased as follows: 2016 - $195 million, 2017 - $200 million, 2018 - $141 million, 2019 - $138 million and 2020 - $115 million. Our commitments for 2021 and beyond increased by approximately $0.3 billion as a result of the extension of premises leases in second quarter 2016. There were no other material changes to our contractual obligations in second quarter 2016 or to payments due in the next five years or after. See the MD&A in our 2015 Annual Report for more information about our contractual obligations.

TRANSCANADA [42

SECOND QUARTER 2016

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.

Our liquids marketing business began operations in the first quarter of 2016. It enters into short-term or long-term pipeline and storage terminal capacity contracts, primarily on the Company’s assets, increasing the utilization of those assets and earning the market value of the capacity. Derivative instruments are used to fix a portion of the variable price exposures that arise from physical liquids transactions.

See our 2015 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2015.

LIQUIDITY RISK

We manage our liquidity risk by continuously forecasting our cash flow for a 12 month period to ensure 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


•	restricted investments


•	the fair value of derivative assets


•	cash and cash equivalents


•	notes receivable.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At June 30, 2016, we had no significant credit losses and no significant amounts past due or impaired. We had a credit risk concentration of $187 million (US$144 million) at June 30, 2016 with one counterparty (December 31, 2015 - $248 million (US$179 million)). This amount is secured by a guarantee from the counterparty's parent company and is expected to be fully collectible.

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, this exposure increases. The majority 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, a portion of which we manage using a combination of interest rate swaps and options.

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SECOND QUARTER 2016

Average exchange rate - U.S. to Canadian dollars



three months ended June 30, 2016	1.29
three months ended June 30, 2015	1.23

six months ended June 30, 2016	1.32
six months ended June 30, 2015	1.24

The impact of changes in the value of the U.S. dollar on our U.S. and international operations is significantly offset by interest on U.S. dollar-denominated long-term debt, as set out in the table below. Comparable EBIT is a non-GAAP measure. See our Reconciliation of non-GAAP measures section for more information.

Significant U.S. dollar-denominated amounts



	three months ended June 30				six months ended June 30
(unaudited - millions of US$)	2016		2015		2016		2015

U.S. and International Natural Gas Pipelines comparable EBIT	183		134		426		373
U.S. Liquids Pipelines comparable EBIT	120		156		250		303
U.S. Power comparable EBIT	51		35		97		140
Interest on U.S. dollar-denominated long-term debt	(250	)	(228	)	(496	)	(446	)
Capitalized interest on U.S. dollar-denominated capital expenditures	9		29		16		60
U.S. non-controlling interests	(40	)	(32	)	(100	)	(80	)
	73		94		193		350

Derivatives designated as a net investment hedge

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 or principal amounts for the derivatives designated as a net investment hedge were as follows:



	June 30, 2016			December 31, 2015
(unaudited - millions of Canadian $, unless noted otherwise)	Fair value¹		Notional or principal amount	Fair value¹		Notional or principal amount

Asset/(liability)
U.S. dollar cross-currency interest rate swaps (maturing 2016 to 2019)²	(499	)	US 2,650	(730	)	US 3,150
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	(37	)	US 450	50		US 1,800
	(536	)	US 3,100	(680	)	US 4,950


¹	Fair values equal carrying values.


²	In the three and six months ended June 30, 2016, net realized gains of $2 million and $4 million, respectively, (2015 - gains of $2 million and $5 million, respectively) related to the interest component of cross-currency swaps settlements are included in interest expense.

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



(unaudited - millions of Canadian $, unless noted otherwise)	June 30, 2016	December 31, 2015

Notional amount	28,400 (US 21,800)	23,100 (US 16,700)
Fair value	31,200 (US 24,000)	23,800 (US 17,200)

TRANSCANADA [44

SECOND QUARTER 2016

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.

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 and are designated for hedge accounting treatment.

The majority of 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.

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, 2016		December 31, 2015

Other current assets	445		442
Intangible and other assets	195		168
Accounts payable and other	(734	)	(926	)
Other long-term liabilities	(432	)	(625	)
	(526	)	(941	)

Unrealized and realized gains/(losses) of derivative instruments

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)	2016		2015		2016		2015

Derivative instruments held for trading¹
Amount of unrealized gains/(losses) in the period
Commodities²	187		23		120		(3	)
Foreign exchange	20		30		47		1
Amount of realized (losses)/gains in the period
Commodities	(47	)	(33	)	(142	)	(32	)
Foreign exchange	13		(10	)	57		(53	)
Derivative instruments in hedging relationships
Amount of realized (losses)/gains in the period
Commodities	(67	)	(113	)	(140	)	(97	)
Foreign exchange	(43	)	—		(106	)	—
Interest rate	1		2		3		4


¹	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in 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.

TRANSCANADA [45

SECOND QUARTER 2016


²	Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast power assets, a loss of $49 million and a gain of $7 million (2015 - nil) were recorded in net income in the three months ended March 31, 2016 relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale.

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)	2016		2015		2016		2015

Change in fair value of derivative instruments recognized in OCI (effective portion)¹
Commodities	42		(50	)	26		(29	)
Foreign exchange	40		—		5		—
Interest rate	—		—		(1	)	—
	82		(50	)	30		(29	)
Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)¹
Commodities²	(21	)	(21	)	61		48
Foreign exchange³	(39	)	—		(5	)	—
Interest rate⁴	4		4		8		8
	(56	)	(17	)	64		56
Gains/(losses) on derivative instruments recognized in net income (ineffective portion)
Commodities²	43		56		(15	)	(7	)
	43		56		(15	)	(7	)


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


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


³	Reported within interest income and other on the condensed consolidated statement of income.


⁴	Reported within interest expense on the condensed consolidated statement of income.

Credit risk related contingent features of derivative instruments

Derivatives 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). We may also need to provide collateral if the fair value of our derivative financial instruments exceeds pre-defined exposure limits.

Based on contracts in place and market prices at June 30, 2016, 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, 2015 – $32 million), with collateral provided in the normal course of business of nil (December 31, 2015 – nil). If the credit-risk-related contingent features in these agreements were triggered on June 30, 2016, we would have been required to provide additional collateral of $17 million (December 31, 2015 – $32 million) to our counterparties. We have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

TRANSCANADA [46

SECOND QUARTER 2016

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, 2016, 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 2016 that had or are likely to have a material impact on our internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES

When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. You can find a summary of our critical accounting estimates in our 2015 Annual Report.

Our significant accounting policies have remained unchanged since December 31, 2015 other than described below. You can find a summary of our significant accounting policies in our 2015 Annual Report.

Changes in accounting policies for 2016

Extraordinary and unusual income statement items

In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from U.S. GAAP the concept of extraordinary items. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on our consolidated financial statements.

Consolidation

In February 2015, the FASB issued new guidance on consolidation. This update requires that entities re-evaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance was effective January 1, 2016, was applied retrospectively and did not result in any change to our consolidation conclusions. Disclosure requirements outlined in the new guidance are included in Note 14, Variable interest entities.

Imputation of interest

In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance was effective January 1, 2016, was applied retrospectively and resulted in a reclassification of debt issuance costs previously recorded in Intangible and other assets to an offset of their respective debt liabilities on our consolidated balance sheet.

Business Combinations

In September 2015, the FASB issued guidance which intends to simplify the accounting measurement period adjustments in business combinations. The amended guidance requires an acquirer to recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In the period the adjustment was determined, the guidance also requires the acquirer to record the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on our consolidated financial statements.

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SECOND QUARTER 2016

Future accounting changes

Revenue from contracts with customers

In 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. In July 2015, the FASB deferred the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are 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. We are currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and have begun an assessment in order to determine any impact on our consolidated financial statements.

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance is effective January 1, 2017 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.

Financial Instruments

In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in fair value of financial liabilities when the fair value option is elected. The new guidance also requires us to assess valuation allowances for deferred tax assets related to available-for-sale debt securities in combination with our other deferred tax assets. This new guidance is effective January 1, 2018. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

Leases

In February 2016, the FASB issued new guidance on leases. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees may be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. We are currently identifying existing lease agreements that are within the scope of the new guidance that may have an impact on our consolidated financial statements as a result of adopting this new standard.

Derivatives and Hedging

In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks. This new guidance is effective January 1, 2017 and we are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

Equity Method Investments

In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance is effective January 1,

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2017 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.

Employee share-based payments

In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. This new guidance is effective January 1, 2017 and we do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.

Measurement of credit losses on financial instruments

In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write-down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance 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)	2016		2015		2016		2015

EBITDA	1,560		1,434		2,657		2,876
Alberta PPA terminations	—		—		240		—
Acquisition costs - Columbia Pipeline Group	10		—		36		—
Keystone XL asset costs	13		—		23		—
Restructuring costs	14		12		14		12
TC Offshore loss on sale	—		—		4		—
Risk management activities¹	(228	)	(79	)	(103	)	10
Comparable EBITDA	1,369		1,367		2,871		2,898
Depreciation and amortization	(444	)	(440	)	(898	)	(874	)
Comparable EBIT	925		927		1,973		2,024
Other income statement items
Comparable interest expense	(405	)	(331	)	(825	)	(649	)
Comparable interest income and other	115		51		263		66
Comparable income tax expense	(189	)	(185	)	(369	)	(432	)
Net income attributable to non-controlling interests	(52	)	(40	)	(132	)	(99	)
Preferred share dividends	(28	)	(25	)	(50	)	(48	)
Comparable earnings	366		397		860		862
Specific items (net of tax):
Alberta PPA terminations	—		—		(176	)	—
Acquisition costs - Columbia Pipeline Group	(113	)	—		(139	)	—
Keystone XL asset costs	(9	)	—		(15	)	—
Restructuring costs	(10	)	(8	)	(10	)	(8	)
TC Offshore loss on sale	—		—		(3	)	—
Alberta corporate income tax rate increase	—		(34	)	—		(34	)
Risk management activities¹	131		74		100		(4	)
Net income attributable to common shares	365		429		617		816

Comparable interest expense	(405	)	(331	)	(825	)	(649	)
Specific item:
Acquisition costs - Columbia Pipeline Group	(109	)	—		(109	)	—
Interest expense	(514	)	(331	)	(934	)	(649	)

Comparable interest income and other	115		51		263		66
Specific items:
Acquisition costs - Columbia Pipeline Group	6		—		6		—
Risk management activities¹	(4	)	30		49		1
Interest income and other	117		81		318		67

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	three months ended June 30						six months ended June 30
(unaudited - millions of $, except per share amounts)	2016			2015			2016			2015

Comparable income tax expense	(189		)	(185		)	(369		)	(432		)
Specific items:
Alberta PPA terminations	—			—			64			—
Acquisition costs - Columbia Pipeline Group	—			—			—			—
Keystone XL asset costs	4			—			8			—
Restructuring costs	4			4			4			4
TC Offshore loss on sale	—			—			1			—
Alberta corporate income tax rate increase	—			(34		)	—			(34		)
Risk management activities¹	(93		)	(35		)	(52		)	5
Income tax expense	(274		)	(250		)	(344		)	(457		)

Comparable earnings per common share	$0.52			$0.56				$1.22			$1.22
Specific items (net of tax):
Alberta PPA terminations	—			—			(0.25		)	—
Acquisition costs - Columbia Pipeline Group	(0.16		)	—			(0.20		)	—
Keystone XL asset costs	(0.01		)	—			(0.02		)	—
Restructuring costs	(0.01		)	(0.01		)	(0.01		)	(0.01		)
TC Offshore loss on sale	—			—			—			—
Alberta corporate income tax rate increase	—			(0.05		)	—			(0.05		)
Risk management activities	0.18			0.10			0.14			(0.01		)
Net income per common share		$0.52			$0.60			$0.88			$1.15



¹	Risk management activities	three months ended June 30				six months ended June 30
	(unaudited - millions of $)	2016		2015		2016		2015

	Canadian Power	20		29		7		7
	U.S. Power	204		51		89		(17	)
	Liquids	4		—		2		—
	Natural Gas Storage	—		(1	)	5		—
	Foreign exchange	(4	)	30		49		1
	Income tax attributable to risk management activities	(93	)	(35	)	(52	)	5
	Total gains/(losses) from risk management activities	131		74		100		(4	)

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Comparable EBITDA and EBIT by business segment



three months ended June 30, 2016	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total

EBITDA	880		271		460		(51	)	1,560
Alberta PPA terminations	—		—		—		—		—
Acquisition costs - Columbia Pipeline Group	—		—		—		10		10
Keystone XL asset costs	—		13		—		—		13
Restructuring costs	—		—		—		14		14
Risk management activities	—		(4	)	(224	)	—		(228	)
Comparable EBITDA	880		280		236		(27	)	1,369
Comparable depreciation and amortization	(288	)	(67	)	(82	)	(7	)	(444	)
Comparable EBIT	592		213		154		(34	)	925



three months ended June 30, 2015	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total

EBITDA	799		313		346		(24	)	1,434
Restructuring costs	—		—		—		12		12
Risk management activities	—		—		(79	)	—		(79	)
Comparable EBITDA	799		313		267		(12	)	1,367
Comparable depreciation and amortization	(282	)	(66	)	(84	)	(8	)	(440	)
Comparable EBIT	517		247		183		(20	)	927



six months ended June 30, 2016	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total

EBITDA	1,774		559		426		(102	)	2,657
Alberta PPA terminations	—		—		240		—		240
Acquisition costs - Columbia Pipeline Group	—		—		—		36		36
Keystone XL asset costs	—		23		—		—		23
Restructuring costs	—		—		—		14		14
TC Offshore loss on sale	4		—		—		—		4
Risk management activities	—		(2	)	(101	)	—		(103	)
Comparable EBITDA	1,778		580		565		(52	)	2,871
Depreciation and amortization	(575	)	(137	)	(170	)	(16	)	(898	)
Comparable EBIT	1,203		443		395		(68	)	1,973



six months ended June 30, 2015	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total

EBITDA	1,666		618		640		(48	)	2,876
Restructuring costs	—		—		—		12		12
Risk management activities	—		—		10		—		10
Comparable EBITDA	1,666		618		650		(36	)	2,898
Depreciation and amortization	(561	)	(129	)	(169	)	(15	)	(874	)
Comparable EBIT	1,105		489		481		(51	)	2,024

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Quarterly results

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA



	2016				2015									2014
(unaudited - millions of $, except per share amounts)	Second		First		Fourth			Third		Second		First		Fourth		Third

Revenues	2,751		2,503		2,851			2,944		2,631		2,874		2,616		2,451
Net income attributable to common shares	365		252		(2,458		)	402		429		387		458		457
Comparable earnings	366		494		453			440		397		465		511		450
Share statistics
Net income per common share - basic and diluted		$0.52		$0.36		($3.47	)		$0.57		$0.60		$0.55		$0.65		$0.64
Comparable earnings per share		$0.52		$0.70		$0.64			$0.62		$0.56		$0.66		$0.72		$0.63
Dividends declared per common share		$0.565		$0.565		$0.52			$0.57		$0.52		$0.52		$0.48		$0.48

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT

Quarter-over-quarter revenues and net income sometimes fluctuate, the causes of which 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, revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income are also affected by:


•	developments outside of the normal course of operations


•	newly constructed assets being placed in service


•	regulatory decisions.

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


•	weather


•	customer demand


•	market prices for natural gas and power


•	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.

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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 generally 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 2016, comparable earnings excluded:


•	a charge of $113 million related to costs associated with the acquisition of Columbia


•	a charge of $9 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project


•	a charge of $10 million after tax for restructuring charges mainly related to expected future losses under lease commitments.

In first quarter 2016, comparable earnings excluded:


•	a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs


•	a charge of $26 million related to costs associated with the acquisition of Columbia


•	a charge of $6 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project


•	an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016.

In fourth quarter 2015, comparable earnings excluded:


•	a $2,891 million after-tax impairment charge on the carrying value of our investment in Keystone XL and related projects


•	an $86 million after-tax loss provision related to the sale of TC Offshore expected to close in early 2016

•

a net charge of $60 million after tax for our business restructuring and transformation initiative comprised of $28 million mainly related to 2015 severance costs and a provision of $32 million for 2016 planned severance costs and expected future losses under lease commitments. These charges form part of a restructuring initiative which commenced in 2015 to maximize the effectiveness and efficiency of our existing operations and reduce overall costs


•	a $43 million after-tax charge related to an impairment in value of turbine equipment held for future use in our Energy business


•	a charge of $27 million after tax related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships


•	a $199 million positive income adjustment related to the impact on our net income from non-controlling interests of TC PipeLines, LP's impairment of their equity investment in Great Lakes.

In third quarter 2015, comparable earnings excluded a charge of $6 million after-tax for severance costs as part of a restructuring initiative to maximize the effectiveness and efficiency of our existing operations.

In second quarter 2015, comparable earnings excluded a $34 million adjustment to income tax expense due to the enactment of an increase in the Alberta corporate income tax rate in June 2015 and a charge of $8 million after-tax for severance costs primarily as a result of the restructuring of our major projects group in response to delayed timelines on certain of our major projects along with a continued focus on enhancing the efficiency and effectiveness of our operations.

In fourth quarter 2014, comparable earnings excluded an $8 million after-tax gain on the sale of our interest in Gas Pacifico/INNERGY.

TC Energy (TRP) 6-KTransCanada Reports Solid Second Quarter 2016 Financial Results