Exhibit

EX-13.1 2 trp-09302016xmda.htm MANAGEMENT'S DISCUSSION AND ANALYSIS Exhibit

EXHIBIT 13.1

Quarterly report to shareholders

Third quarter 2016

Financial highlights



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

Income
Revenues	3,632			2,944		8,886		8,449
Net (loss)/income attributable to common shares	(135		)	402		482		1,218
per common share - basic and diluted		($0.17	)		$0.57		$0.66		$1.72
Comparable EBITDA¹	1,886			1,483		4,757		4,381
Comparable earnings¹	622			440		1,482		1,302
per common share¹		$0.78			$0.62		$2.02		$1.84

Operating cash flow
Net cash provided by operations	1,183			1,247		3,277		2,976
Comparable funds generated from operations¹	1,411			1,148		3,529		3,374
Comparable distributable cash flow¹	1,025			953		2,701		2,774
per common share¹		$1.29			$1.34		$3.68		$3.91

Investing activities
Capital spending - capital expenditures	1,444			976		3,262		2,748
- projects in development	62			130		219		465
Contributions to equity investments	286			105		570		303
Acquisitions, net of cash acquired	12,609			—		13,608		—
Proceeds from sale of assets, net of transaction costs	—			—		6		—

Dividends declared
Per common share		$0.565			$0.52		$1.695		$1.56
Basic common shares outstanding (millions)
Average for the period	797			709		734		709
End of period	800			709		800		709


¹	Comparable EBITDA, comparable earnings, comparable earnings per common share, comparable 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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Management’s discussion and analysis

November 1, 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 nine months ended September 30, 2016, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2016 which have been prepared in accordance with U.S. GAAP. On July 1, 2016, we completed the acquisition of Columbia Pipeline Group, Inc. (Columbia). For further information on the acquisition refer to note 4 of the September 30, 2016 unaudited condensed consolidated financial statements. The three and nine months ended September 30, 2016 amounts reflect the results of Columbia post-acquisition from July 1, 2016. Comparative figures do not include Columbia.

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 November 1, 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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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 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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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


•	comparable funds generated from operations


•	comparable distributable cash flow


•	comparable distributable cash flow per common share


•	comparable earnings


•	comparable earnings per common share


•	comparable EBITDA


•	comparable EBIT


•	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.

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.

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Comparable measure	Original measure

comparable earnings	net income attributable to common shares
comparable earnings per common share	net income per common share
comparable EBITDA	segmented earnings
comparable EBIT	segmented earnings
comparable funds generated from operations	cash provided by operations
comparable distributable cash flow	cash provided by operations
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 goodwill, investments and other assets 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.

Comparable distributable cash flow

Comparable distributable cash flow is defined as comparable funds generated from operations plus distributions received from operating activities in excess of equity earnings from 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 comparable distributable cash flow 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.

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Consolidated results - third 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 September 30				nine months ended September 30
(unaudited - millions of $, except per share amounts)	2016		2015		2016		2015

Natural Gas Pipelines	753		522		1,952		1,627
Liquids Pipelines	187		284		609		773
Energy	(825	)	244		(569	)	715
Corporate	(37	)	(31	)	(155	)	(94		)
Total segmented earnings	78		1,019		1,837		3,021
Interest expense	(522	)	(341	)	(1,456	)	(990		)
Interest income and other	122		16		440		83
(Loss)/Income before income taxes	(322	)	694		821		2,114
Income tax recovery/(expense)	266		(223	)	(78	)	(680		)
Net (loss)/income	(56	)	471		743		1,434
Net income attributable to non-controlling interests	(52	)	(46	)	(184	)	(145		)
Net (loss)/income attributable to controlling interests	(108	)	425		559		1,289
Preferred share dividends	(27	)	(23	)	(77	)	(71		)
Net (loss)/income attributable to common shares	(135	)	402		482		1,218
Net (loss)/income per common share - basic and diluted	($0.17)		$0.57		$0.66			$1.72

Net income attributable to common shares decreased by $537 million to a net loss of $135 million for the three months ended September 30, 2016 and decreased $736 million for the nine months ended September 30, 2016 compared to the same periods in 2015. The 2016 results included:


•	a $656 million after-tax impairment on the Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeds its carrying value.


•	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

•

costs associated with the acquisition of Columbia including an after-tax charge of $67 million in third quarter, primarily relating to retention, severance and integration expenses, and $206 million year-to-date which included $109 million related to the dividend equivalent payments on the subscription receipts issued as part of the permanent financing of the transaction, $36 million related to acquisition costs and $6 million related to interest earned on the subscription receipt funds held in escrow


•	$28 million of income tax recoveries in third quarter related to the realized loss on a third party sale of Keystone XL project assets. A provision for the expected loss on these assets was included in our fourth quarter 2015 impairment charge, but the related income tax recoveries could not be recorded until realized


•	an after-tax charge of $9 million in third quarter and $24 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 year-to-date 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


•	$3 million of after-tax costs related to the monetization of our U.S. Northeast Power business

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

The 2015 results included:


•	an after-tax charge of $6 million in third quarter and $14 million year-to-date 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


•	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.

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 increased by $182 million and $180 million for the three and nine months ended September 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 September 30			nine months ended September 30
(unaudited - millions of $, except per share amounts)	2016		2015	2016		2015

Net (loss)/income attributable to common shares	(135	)	402	482		1,218
Specific items (net of tax):
Ravenswood goodwill impairment	656		—	656		—
Alberta PPA terminations	—		—	176		—
Acquisition related costs - Columbia	67		—	206		—
Keystone XL income tax recoveries	(28	)	—	(28	)	—
Keystone XL asset costs	9		—	24		—
Restructuring costs	—		6	10		14
TC Offshore loss on sale	—		—	3		—
U.S. Northeast Power business monetization	3		—	3		—
Alberta corporate income tax rate increase	—		—	—		34
Risk management activities¹	50		32	(50	)	36
Comparable earnings	622		440	1,482		1,302

Net (loss)/income per common share	($0.17)		$0.57	$0.66		$1.72
Specific items (net of tax):
Ravenswood goodwill impairment	0.82		—	0.89		—
Alberta PPA terminations	—		—	0.25		—
Acquisition related costs - Columbia	0.09		—	0.29		—
Keystone XL income tax recoveries	(0.03	)	—	(0.04	)	—
Keystone XL asset costs	0.01		—	0.03		—
Restructuring costs	—		0.01	0.01		0.02
U.S. Northeast Power business monetization	—		—	—		—
Alberta corporate income tax rate increase	—		—	—		0.05
Risk management activities	0.06		0.04	(0.07	)	0.05
Comparable earnings per share	$0.78		$0.62	$2.02		$1.84

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

	Canadian Power	(4	)	(14	)	3		(7	)
	U.S. Power	(73	)	(5	)	16		(22	)
	Liquids marketing	(8	)	—		(6	)	—
	Natural Gas Storage	4		2		9		2
	Foreign exchange	—		(26	)	49		(25	)
	Income tax attributable to risk management activities	31		11		(21	)	16
	Total unrealized (losses)/gains from risk management activities	(50	)	(32	)	50		(36	)

Comparable earnings increased by $182 million for the three months ended September 30, 2016 compared to the same period in 2015. This was primarily the net effect of:


•	higher earnings from U.S. Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation and storage revenue resulting from higher rates effective August 1, 2016


•	higher interest expense from debt issuances and lower capitalized interest


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


•	higher contribution from Mexican pipelines primarily due to earnings from Topolobampo beginning in July 2016


•	higher interest income and other due to 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 earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant acquired in February 2016 and higher sales to customers in the PJM market, offset by lower capacity revenues in New York


•	higher earnings from Bruce Power mainly due to lower depreciation and our increased ownership interest, partially offset by higher losses from contracting activities


•	higher earnings from Canadian Pipelines primarily due to a higher NGTL investment base and incentive earnings from Canadian Mainline and NGTL.

Comparable earnings increased by $180 million for the nine months ended September 30, 2016 compared to the same period in 2015. This was primarily the net effect of:


•	higher earnings from our U.S. Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition, higher ANR transportation and storage revenue resulting from higher rates effective August 1, 2016, higher ANR Southeast Mainline transportation revenues and lower OM&A expenses


•	higher interest expense from debt issuances and lower capitalized interest


•	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


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

The stronger U.S. dollar on a year-to-date basis compared to the same period in 2015 positively impacted the translated results of our U.S. and Mexican 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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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 September 30, 2016, consists of $25 billion of near-term projects and $48 billion of commercially secured medium- to longer-term projects. Amounts presented exclude maintenance capital expenditures, 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.

Near-term projects



at September 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

Topolobampo¹	Natural Gas Pipelines	2017	US 1.0	US 0.9
Mazatlán	Natural Gas Pipelines	2016	US 0.4	US 0.3
Canadian Mainline	Natural Gas Pipelines	2016-2017	0.7	0.4
NGTL - 2016/17 Facilities	Natural Gas Pipelines	2016-2020	2.7	0.8
- North Montney	Natural Gas Pipelines	2017+²	1.7	0.3
- 2018 Facilities	Natural Gas Pipelines	2018-2020	0.6	—
- Other	Natural Gas Pipelines	2016-2018	0.4	—
Grand Rapids³	Liquids Pipelines	2017	0.9	0.8
Northern Courier	Liquids Pipelines	2017	1.0	0.8
Tula	Natural Gas Pipelines	2017	US 0.5	US 0.2
Columbia - Leach XPress	Natural Gas Pipelines	2017	US 1.4	US 0.3
- Rayne XPress	Natural Gas Pipelines	2017	US 0.4	US 0.2
- Gibraltar	Natural Gas Pipelines	2017	US 0.3	US 0.2
- Modernization I	Natural Gas Pipelines	2016-2017	US 0.6	US 0.3
- Cameron Access	Natural Gas Pipelines	2018	US 0.3	US 0.1
- WB XPress	Natural Gas Pipelines	2018	US 0.9	US 0.2
- Mountaineer XPress	Natural Gas Pipelines	2018	US 2.0	US 0.1
- Gulf XPress	Natural Gas Pipelines	2018	US 0.7	—
- Modernization II	Natural Gas Pipelines	2018-2020	US 1.1	—
Napanee	Energy	2018	1.1	0.5
Villa de Reyes	Natural Gas Pipelines	2018	US 0.6	US 0.1
Sur de Texas³	Natural Gas Pipelines	2018	US 1.3	—
Bruce Power - life extension³	Energy	2016-2020	1.2	0.1
			21.8	6.6
Foreign exchange impact on near-term projects⁴			3.6	0.9
Total near-term projects CAD			25.4	7.5


¹	CFE has recognized that a force majeure has delayed construction and revenue has been recorded in third quarter 2016 as per terms of the Transportation Service Agreement (TSA). See the Recent developments section for more information.


²	In-service date is dependent on a positive final investment decision.


³	Our proportionate share.


⁴	Reflects U.S./Canada foreign exchange rate of $1.31 at September 30, 2016.

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Medium to longer-term projects



at September 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	—
		45.2	2.3
Foreign exchange impact on medium to longer-term projects⁴		2.7	0.1
Total medium to longer-term projects		47.9	2.4


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.


⁴	Reflects U.S./Canada foreign exchange rate of $1.31 at September 30, 2016.

Outlook

Our overall comparable earnings outlook for 2016 will be 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, increased earnings from the remainder of our Natural Gas Pipelines' assets, changes in our Canadian Power business and lower than expected Liquids and U.S. Power earnings, each of which are addressed within the relevant section of the MD&A.

Consolidated capital spending, equity investments and acquisition

Our expected total capital expenditures as outlined in the 2015 Annual Report remains unchanged.

On April 11, 2016, we announced that we were chosen to build, own and operate the 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 Sur de Texas natural gas pipeline in Mexico. On July 1, 2016, we acquired Columbia. Although we expect to defer capital expenditures on several of our other natural gas pipelines projects, we expect to spend an estimated additional $1 billion on Columbia capital projects in 2016, approximately $300 million on the Villa de Reyes pipeline project and $200 million on the Sur de Texas pipeline project.

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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. In addition, Columbia results are included in the Natural Gas Pipelines segment from its acquisition on July 1, 2016. Comparative periods do not include Columbia.



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable EBITDA	1,196		806		2,974		2,472
Depreciation and amortization	(361	)	(284	)	(936	)	(845	)
Comparable EBIT	835		522		2,038		1,627
Specific items:
Acquisition related costs - Columbia	(82	)	—		(82	)	—
TC Offshore loss on sale	—		—		(4	)	—
Segmented earnings	753		522		1,952		1,627

Natural Gas Pipelines segmented earnings increased by $231 million and $325 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015. Segmented earnings for the three and nine months ended September 30, 2016 included $82 million primarily related to retention and severance expenses incurred within the Natural Gas Pipelines segment resulting from the Columbia acquisition. Year-to-date 2016 segmented earnings also included an additional $4 million pre-tax loss on the sale of TC Offshore. These amounts have 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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	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Canadian Pipelines
Canadian Mainline	285		286		825		866
NGTL System	253		223		736		666
Foothills	24		26		76		79
Other Canadian pipelines¹	7		7		20		21
Canadian Pipelines - comparable EBITDA	569		542		1,657		1,632
Depreciation and amortization	(219	)	(212	)	(653	)	(632	)
Canadian Pipelines - comparable EBIT	350		330		1,004		1,000

U.S. and International Pipelines (US$)
Columbia²	174		—		174		—
ANR	76		52		235		171
TC PipeLines, LP^1,3	32		25		90		76
Great Lakes^3,4	11		8		47		35
Other U.S. pipelines (Iroquois¹,GTN^3,5, PNGTS^3,6)	10		13		33		65
Mexico	82		44		165		138
International and other^1,7	(6	)	(2	)	(2	)	2
Non-controlling interests⁸	94		68		264		208
U.S. and International Pipelines - comparable EBITDA	473		208		1,006		695
Depreciation and amortization	(107	)	(55	)	(214	)	(169	)
U.S. and International Pipelines - comparable EBIT	366		153		792		526
Foreign exchange impact	121		48		254		136
U.S. and International Pipelines - comparable EBIT(Cdn$)	487		201		1,046		662
Business Development comparable EBITDA and EBIT	(2	)	(9	)	(12	)	(35	)
Natural Gas Pipelines - comparable EBIT	835		522		2,038		1,627


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


²	We completed the acquisition of Columbia on July 1, 2016. Represents our effective ownership in these assets.

³TC PipeLines LP (TCLP) periodically conducts at-the-market equity issuances which decrease our ownership interest in TCLP. On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TCLP. On January 1, 2016, we sold a 49.9 per cent interest in PNGTS to TCLP. The following table shows our ownership interest in TCLP and our effective ownership interest of GTN, Great Lakes and PNGTS through our ownership interest in TCLP for the periods presented.



	ownership percentage as of
	September 30, 2016	June 30, 2016	March 31, 2016	January 1, 2016	April 1, 2015

TCLP	27.1	27.4	27.9	28.0	28.3
Effective ownership through TCLP:
GTN	27.1	27.4	27.9	28.0	28.3
Great Lakes	12.6	12.7	13.0	13.0	13.1
PNGTS	13.5	13.7	13.9	14.0	—


⁴	Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TCLP.


⁵	Represents our 30 per cent direct ownership interest until April 1, 2015 at which point the 30 per cent interest was sold to TCLP.


⁶	Represents our 61.7 per cent ownership interest in 2015 and 11.8 per cent effective January 1, 2016 as a result of the sale of 49.9 per cent interest to TCLP.

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THIRD QUARTER 2016


⁷	Includes our share of equity income from TransGas as well as general and administration costs relating to our U.S. and International Pipelines.


⁸	Comparable EBITDA for the portions of TCLP, PNGTS and Columbia Pipeline Partners LP that we do not own.

CANADIAN PIPELINES

Net income and comparable EBITDA for our rate-regulated Canadian pipelines are generally affected by our approved ROE, our investment base, our 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 September 30		nine months ended September 30
(unaudited - millions of $)	2016	2015	2016	2015

Canadian Mainline	52	47	154	161
NGTL System	81	70	233	200
Foothills	4	3	11	11

Net income for the Canadian Mainline increased by $5 million for the three months ended September 30, 2016 compared to the same period in 2015 primarily due to higher incentive earnings, partially offset by a lower average investment base and higher carrying charges. Net Income for the Canadian Mainline decreased by $7 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to a lower average investment base and higher carrying charges, partially offset by higher incentive earnings in 2016.

Net income for the NGTL System increased by $11 million and $33 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to a higher average investment base and OM&A incentive earnings recorded in 2016.

U.S. AND INTERNATIONAL PIPELINES

Earnings for our U.S. natural gas pipelines operations, which include Columbia effective July 1, 2016, are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services. Columbia and ANR results are also affected by the contracting and pricing of its storage capacity and incidental commodity sales.

The results for Columbia include our 91.6 per cent effective ownership of Columbia Gas Transmission, Columbia Gulf Transmission, Columbia Midstream and Columbia Energy Ventures through a 84.3 per cent direct ownership and our 46.5 per cent ownership in Columbia Pipeline Partners LP which owns the remaining 15.7 per cent ownership interest in these assets.

Comparable EBITDA for U.S. and International Pipelines increased by US$265 million and US$311 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015. This was the net effect of:


•	US$174 million of contributions from Columbia as a result of the acquisition on July 1, 2016


•	higher contribution from Mexican pipelines primarily due to incremental earnings from Topolobampo. The Topolobampo project has experienced a delay in construction, which, under the terms of the TSA, constitutes a force majeure and, as a result, we began realizing revenue in July 2016.


•	higher ANR transportation and storage revenue resulting from higher rates as part of our rates settlement effective August 1, 2016, higher ANR Southeast Mainline transportation revenues and lower OM&A expenses, offset by a first quarter 2015 non-recurring settlement with a producer


•	higher transportation revenues from Great Lakes


•	higher contribution from TC PipeLines, LP.

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THIRD QUARTER 2016

As well, a stronger U.S. dollar on a year-to-date basis in 2016 compared to 2015 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 $77 million and $91 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to the Columbia acquisition on July 1, 2016, a higher investment base on the NGTL System, increased depreciation rates on ANR following the rate settlement, and the effect of a stronger U.S. dollar.

BUSINESS DEVELOPMENT

Business development expenses were lower by $7 million and $23 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to the capitalization of business development activities in 2016 related to the successful Mexico projects, a focus on the Columbia acquisition and decreased business development activity in other areas in 2016.

OUTLOOK

The 2016 earnings outlook for the Canadian regulated and Mexican pipelines remains consistent with what we disclosed in the 2015 Annual Report. We are expecting an increase in 2016 earnings from U.S. Pipelines 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. Earnings for the other U.S. Pipelines are expected to be slightly higher this year as a result of higher revenues and lower costs.

OPERATING STATISTICS - WHOLLY OWNED PIPELINES



nine months ended September 30	Canadian Mainline¹		NGTL System²		ANR³
(unaudited)	2016	2015	2016	2015	2016	2015

Average investment base (millions of $)	4,423	4,840	7,401	6,599	n/a	n/a
Delivery volumes (Bcf):
Total	1,217	1,204	2,978	2,871	1,190	1,212
Average per day	4.4	4.4	10.9	10.5	4.3	4.4


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 nine months ended September 30, 2016 were 802 Bcf (2015 – 833 Bcf). Average per day was 2.9 Bcf (2015 – 3.1 Bcf).


²	Field receipt volumes for the NGTL System for the nine months ended September 30, 2016 were 3,080 Bcf (2015 – 2,994 Bcf). Average per day was 11.2 Bcf (2015 – 11.0 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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THIRD QUARTER 2016

Liquids Pipelines



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable EBITDA	281		352		861		970
Depreciation and amortization	(72	)	(68	)	(209	)	(197	)
Comparable EBIT	209		284		652		773
Specific items:
Keystone XL asset costs	(14	)	—		(37	)	—
Risk management activities	(8	)	—		(6	)	—
Segmented earnings	187		284		609		773

Liquids Pipelines segmented earnings decreased by $97 million and $164 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included pre-tax charges related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project as well as unrealized losses 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 September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Keystone Pipeline System	284		360		870		988
Liquids Pipelines Business Development and Other	(3	)	(8	)	(9	)	(18	)
Liquids Pipelines - comparable EBITDA	281		352		861		970
Depreciation and amortization	(72	)	(68	)	(209	)	(197	)
Liquids Pipelines - comparable EBIT	209		284		652		773

Comparable EBIT denominated as follows:
Canadian dollars	52		57		164		172
U.S. dollars	119		171		369		474
Foreign exchange impact	38		56		119		127
	209		284		652		773

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.

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THIRD QUARTER 2016

Comparable EBITDA for the Keystone Pipeline System decreased by $76 million and $118 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was due to the net effect of lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink, partially offset by higher contracted volumes on Keystone Pipeline.

BUSINESS DEVELOPMENT AND OTHER

Business development and other, which primarily includes business development activity and our marketing business, decreased by $5 million and $9 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was the effect of lower business development spending and a growing contribution from the marketing business.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $4 million and $12 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar.

OUTLOOK

Excluding specified items, our 2016 earnings are expected to be lower than our 2015 earnings due to lower uncontracted volumes and market conditions related to the lower crude oil price environment.

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

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THIRD QUARTER 2016

Energy



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable EBITDA	419		340		984		990
Depreciation and amortization	(81	)	(79	)	(251	)	(248	)
Comparable EBIT	338		261		733		742
Specific items:
Ravenswood goodwill impairment	(1,085	)	—		(1,085	)	—
Alberta PPA terminations	—		—		(240	)	—
U.S. Northeast Power business monetization	(5	)	—		(5	)	—
Risk management activities	(73	)	(17	)	28		(27	)
Segmented (losses)/earnings	(825	)	244		(569	)	715

Energy segmented earnings decreased by $1,069 million and $1,284 million to segmented losses of $825 million and $569 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT:


•	a $1,085 million pre-tax impairment charge on the Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeds its carrying value.


•	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


•	$5 million of pre-tax costs related to the process of monetizing our U.S. Northeast Power business


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



Risk management activities	three months ended September 30				nine months ended September 30
(unaudited - millions of $, pre-tax)	2016		2015		2016	2015

Canadian Power	(4	)	(14	)	3	(7	)
U.S. Power	(73	)	(5	)	16	(22	)
Natural Gas Storage	4		2		9	2
Total unrealized (losses)/gains from risk management activities	(73	)	(17	)	28	(27	)

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 impacts 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.

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THIRD QUARTER 2016

Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast Power business, 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, has contributed to higher volatility in U.S. Power risk management activities.

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



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Canadian Power
Western Power¹	26		24		49		73
Eastern Power	82		86		270		306
Bruce Power	76		57		210		202
Canadian Power - comparable EBITDA^1,2	184		167		529		581
Depreciation and amortization	(35	)	(47	)	(117	)	(141	)
Canadian Power - comparable EBIT^1,2	149		120		412		440
U.S. Power (US$)
U.S. Power - comparable EBITDA	164		140		323		335
Depreciation and amortization	(33	)	(23	)	(95	)	(78	)
U.S. Power - comparable EBIT	131		117		228		257
Foreign exchange impact	44		36		74		68
U.S. Power - comparable EBIT (Cdn$)	175		153		302		325

Natural Gas Storage and other - comparable EBITDA	20		(1	)	39		8
Depreciation and amortization	(3	)	(3	)	(9	)	(9	)
Natural Gas Storage and other - comparable EBIT	17		(4	)	30		(1	)

Business Development comparable EBITDA and EBIT	(3	)	(8	)	(11	)	(22	)
Energy - comparable EBIT^1,2	338		261		733		742


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

Comparable EBITDA for Energy increased by $79 million for the three months ended September 30, 2016 compared to the same period in 2015 due to the net effect of:


•	higher earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant acquired in February 2016 and higher contributions from sales to customers in the PJM market, offset by lower capacity revenues in New York


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


•	higher earnings from Bruce Power mainly due to lower depreciation and our increased ownership interest, partially offset by higher losses from contracting activities.

Comparable EBITDA for Energy decreased by $6 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to the net effect of:


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


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

TRANSCANADA [19

THIRD QUARTER 2016


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


•	higher earnings from Bruce Power mainly due to lower depreciation and our increased ownership interest, partially offset by lower volumes and higher operating costs from higher planned outage days.

CANADIAN POWER

Western and Eastern Power



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Revenue¹
Western Power	39		126		170		412
Eastern Power	112		119		315		358
Other²	2		1		31		49
	153		246		516		819
Comparable income from equity investments³	9		(2	)	16		13
Commodity purchases resold	(1	)	(83	)	(60	)	(266	)
Plant operating costs and other	(57	)	(65	)	(150	)	(194	)
Exclude risk management activities¹	4		14		(3	)	7
Comparable EBITDA⁴	108		110		319		379
Depreciation and amortization	(35	)	(47	)	(117	)	(141	)
Comparable EBIT⁴	73		63		202		238

Breakdown of comparable EBITDA
Western Power⁴	26		24		49		73
Eastern Power	82		86		270		306
Comparable EBITDA⁴	108		110		319		379


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.

Includes our share of comparable equity income from our investments in ASTC Power Partnership, which held the Sundance B PPA, and Portlands Energy. Comparable equity income does not include any gains or losses related to our risk management activities and, for the nine months ended September 30, 2016 excludes a $29 million charge related to the Sundance B PPA termination which was held in ASTC Power Partnership.


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

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THIRD QUARTER 2016

Sales volumes and plant availability

Includes our share of volumes from our equity investments.



	three months ended September 30				nine months ended September 30
(unaudited)	2016		2015		2016		2015

Sales volumes (GWh)
Supply
Generation
Western Power	606		589		1,824		1,876
Eastern Power	1,152		1,083		2,767		3,145
Purchased
Sundance A & B and Sheerness PPAs¹	—		2,734		1,620		7,226
Other purchases	21		281		409		677
	1,779		4,687		6,620		12,924
Sales
Contracted
Western Power	627		2,188		2,752		5,627
Eastern Power	1,152		1,083		2,767		3,145
Spot
Western Power	—		1,416		1,101		4,152
	1,779		4,687		6,620		12,924
Plant availability²
Western Power³	94	%	96	%	92	%	97	%
Eastern Power⁴	96	%	96	%	93	%	97	%


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	Does not include Bécancour because power generation remains suspended.

Western Power

Comparable EBITDA for Western Power increased by $2 million for the three months ended September 30, 2016 compared to the same period in 2015 mainly due to higher realized prices on generated volumes offset by lower earnings following the termination of the PPAs.

Comparable EBITDA for Western Power decreased by $24 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to lower realized power prices and 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 31 per cent from $26/MWh to $18/MWh for the three months ended September 30, 2016 and decreased 54 per cent from $37/MWh to $17/MWh for the nine months ended September 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. 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.

TRANSCANADA [21

THIRD QUARTER 2016

One hundred per cent of Western Power sales volumes were sold under contract in third quarter 2016 compared to 61 per cent in third quarter 2015.

Depreciation and amortization decreased by $12 million and $24 million for the three and nine months ended September 30, 2016 compared to the same periods in 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 the remaining months of 2016, the natural gas-fired cogeneration assets are expected to perform well in the lower natural 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 $4 million and $36 million for the three and nine months ended September 30, 2016 compared to the same period in 2015 mainly due to lower contractual earnings at Bécancour, and lower earnings on the sale of unused natural gas transportation for the nine months ended September 30, 2016 compared to the same period in 2015.

Our 2016 earnings outlook provided in the 2015 Annual Report will be modestly lower 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 this 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 September 30						nine months ended September 30
(unaudited - millions of $, unless noted otherwise)	2016			2015			2016			2015

Income from equity investments¹	76			57			210			202
Comprised of:
Revenues	365			298			1,094			945
Operating expenses	(204		)	(159		)	(643		)	(498		)
Depreciation and other	(85		)	(82		)	(241		)	(245		)
	76			57			210			202
Bruce Power - Other information
Plant availability²	88		%	86		%	82		%	85		%
Planned outage days	50			88			335			287
Unplanned outage days	37			8			49			30
Sales volumes (GWh)¹	5,886			4,621			16,420			13,970
Realized sales price per MWh^3,4		$66			$64			$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 realized gains and losses from contracting activities and cost flow-through items.


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

Equity income from Bruce Power increased by $19 million and $8 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to lower depreciation as a result of the Bruce Power facility's operating life extension and our increased ownership interest. These increases were partially offset by

TRANSCANADA [22

THIRD QUARTER 2016

higher losses from contracting activities in the three months ended September 30, 2016 and lower volumes and higher operating costs from higher planned outage days for the nine months ended September 30, 2016 compared to the same periods 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 a 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. Additional planned maintenance was completed on unit 3 in third quarter 2016. Planned maintenance on unit 7 began in third quarter 2016 and is scheduled to be completed 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 primarily due to strong results year-to-date.

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THIRD QUARTER 2016

U.S. POWER



	three months ended September 30				nine months ended September 30
(unaudited - millions of US$)	2016		2015		2016		2015

Revenue¹
Power²	764		568		1,666		1,552
Capacity	84		99		223		254
	848		667		1,889		1,806
Commodity purchases resold	(594	)	(412	)	(1,188	)	(1,159	)
Plant operating costs and other³	(147	)	(119	)	(362	)	(329	)
Exclude risk management activities²	57		4		(16	)	17
Comparable EBITDA¹	164		140		323		335
Depreciation and amortization	(33	)	(23	)	(95	)	(78	)
Comparable EBIT¹	131		117		228		257


¹	Includes Ironwood acquisition commencing February 1, 2016.


²	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.


³	Includes the cost of fuel consumed in generation.

Sales volumes and plant availability



	three months ended September 30				nine months ended September 30
(unaudited)	2016		2015		2016		2015

Physical sales volumes (GWh)
Supply
Generation¹	4,387		2,707		10,043		5,756
Purchased	9,924		6,919		19,734		15,800
	14,311		9,626		29,777		21,556

Plant availability^2,3	97	%	93	%	85	%	77	%


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 nine months ended September 30, 2015 compared to the same period 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 September 30		nine months ended September 30
(unaudited)	2016	2015	2016	2015

Average Spot Power Prices (US$ per MWh)
New England¹	32	29	29	47
New York²	33	31	29	44
PJM³	28	n/a	25	n/a
Average New York² Spot Capacity Prices (US$ per KW-M)	12.19	15.27	9.39	12.18


¹	New England ISO all hours Mass Hub price.


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

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THIRD QUARTER 2016


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

Comparable EBITDA for U.S. Power increased US$24 million for the three months ended September 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 sales to wholesale utility 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.

Comparable EBITDA for U.S. Power decreased US$12 million for the nine months ended September 30, 2016 compared to the same period in 2015 primarily due to the net effect of:


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


•	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.

Higher sales to wholesale utility customers in the PJM market resulted in higher earnings for the three months ended September 30, 2016 compared to the same period in 2015 as we continue to expand our customer base in the PJM market. However, significantly lower realized power prices and mild winter weather have resulted in lower margins in our wholesale business in both the PJM and New England markets for the nine months ended September 30, 2016 compared to the same period in 2015, the impact of which was primarily seen in the first quarter results.

Wholesale electricity prices in New York and New England were slightly higher for the three months ended September 30, 2016 and significantly lower for the nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to unseasonably warm weather in first quarter 2016. In New England, spot power prices for the three and nine months ended September 30, 2016 were 10 per cent higher and 38 per cent lower compared to the same periods in 2015. In New York City, spot power prices for the three and nine months ended September 30, 2016 were six per cent higher and 34 per cent lower compared to the same periods in 2015.

Average New York Zone J spot capacity prices were approximately 20 per cent and 23 per cent lower for the three and nine months ended September 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 in New York was partially offset by capacity revenues earned by our Ironwood power plant acquired in February 2016.

Capacity revenues were also negatively impacted by an outage at Unit 30 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 nine months ended September 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. Insurance recoveries, net of deductibles, 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

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impact on our earnings although the recording of earnings has not coincided exactly 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.

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 nine month months ended September 30, 2016 than the same periods in 2015 as we have expanded our customer base in the PJM and New England markets.

As at September 30, 2016, approximately 1,500 GWh, or 43 per cent, of U.S. Power’s planned generation was contracted for the remainder of 2016 and 3,900 GWh, or 30 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 and plant availability.

U.S. Power results for 2016 are not expected to be significantly impacted by the announced monetization of the U.S. Northeast Power business as these transactions are not expected to close until the first half of 2017. See the Recent developments section for more information. Nevertheless, operating results for the full year in 2016 are expected to be lower than the Outlook in our 2015 Annual Report due to lower commodity prices experienced in the first half of 2016.

NATURAL GAS STORAGE AND OTHER

Comparable EBITDA increased by $21 million and $31 million for the three and nine months ended September 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 the 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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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 September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable EBITDA	(10	)	(15	)	(62	)	(51	)
Depreciation and amortization	(13	)	(8	)	(29	)	(23	)
Comparable EBIT	(23	)	(23	)	(91	)	(74	)
Specific items:
Acquisition related costs - Columbia	(14	)	—		(50	)	—
Restructuring costs	—		(8	)	(14	)	(20	)
Segmented losses	(37	)	(31	)	(155	)	(94	)

Corporate segmented losses in 2016 increased by $6 million and $61 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT:


•	acquisition and integration costs associated with the acquisition of Columbia


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

Interest expense



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable interest on long-term debt (including interest on junior subordinated notes)
Canadian-dollar denominated	(122	)	(109	)	(343	)	(324	)
U.S. dollar-denominated (US$)	(315	)	(231	)	(811	)	(677	)
Foreign exchange impact	(102	)	(72	)	(260	)	(177	)
	(539	)	(412	)	(1,414	)	(1,178	)
Other interest and amortization expense	(23	)	(11	)	(60	)	(35	)
Capitalized interest	46		82		133		223
Comparable interest expense	(516	)	(341	)	(1,341	)	(990	)
Specific item:
Acquisition related costs - Columbia¹	(6	)	—		(115	)	—
Interest expense	(522	)	(341	)	(1,456	)	(990	)


¹	This amount represents the dividend equivalent payments of $109 million on the subscription receipts issued to partially fund the Columbia acquisition and $6 million of other acquisitions related costs. See the Financial condition section for more information.

Comparable interest expense increased by $175 million and $351 million for the three and nine months ended September 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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•	higher interest expense on debt acquired in the acquisition of Columbia on July 1, 2016


•	higher foreign exchange on interest on 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 September 30			nine months ended September 30
(unaudited - millions of $)	2016	2015		2016	2015

AFUDC
Canadian-dollar denominated	44	30		133	81
U.S. dollar-denominated (US$)	55	37		149	98
Foreign exchange impact	11	11		40	25
Total AFUDC	110	78		322	204
Other	12	(36	)	63	(96	)
Comparable interest income and other	122	42		385	108
Specific items:
Acquisition related costs - Columbia¹	—	—		6	—
Risk management activities	—	(26	)	49	(25	)
Interest income and other	122	16		440	83


¹	This amount represents interest income on the gross proceeds of the subscriptions receipts issued to partially fund the Columbia acquisition. See the Financial condition section for more information.

Comparable interest income and other increased by $80 million and $277 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 due to the net effect of:


•	higher AFUDC related to our rate-regulated projects, primarily Mexico Pipelines, Energy East Pipeline, NGTL expansion and Columbia projects


•	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.

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Income tax expense



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable income tax expense	(261	)	(236	)	(630	)	(668	)
Specific items:
Ravenswood goodwill impairment	429		—		429		—
Alberta PPA terminations	—		—		64		—
Acquisition related costs - Columbia	32		—		32		—
Keystone XL income tax recoveries	28		—		28		—
Keystone XL asset costs	5		—		13		—
Restructuring costs	—		2		4		6
TC Offshore loss on sale	—		—		1		—
U.S. Northeast Power business monetization	2		—		2		—
Alberta corporate income tax rate increase	—		—		—		(34	)
Risk management activities	31		11		(21	)	16
Income tax recovery/(expense)	266		(223	)	(78	)	(680	)

Comparable income tax expense increased by $25 million and decreased by $38 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was mainly the result of changes in the proportion of income earned between Canadian and foreign jurisdictions and lower flow-through taxes in 2016 on Canadian regulated pipelines.

Net income attributable to non-controlling interests



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Comparable net income attributable to non-controlling interests	(55	)	(46	)	(187	)	(145	)
Specific item:
Acquisition related costs - Columbia	3		—		3		—
Net income attributable to non-controlling interests	(52	)	(46	)	(184	)	(145	)

Net income attributable to non-controlling interests increased by $6 million and $39 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included a $3 million charge related to the non-controlling interest portion of retention and severance expenses resulting from the Columbia acquisition.

Comparable net income attributable to non-controlling interests increased by $9 million and $42 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to the acquisition of Columbia which included a non-controlling interest in Columbia Pipeline Partners LP. In addition, 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 along with the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP increased net income attributable to non-controlling interests year-over-year.

Preferred share dividends



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Preferred share dividends	(27	)	(23	)	(77	)	(71	)

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Preferred share dividends increased by $4 million and $6 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to preferred shares issuances in 2016 and 2015 offset by lower dividend rates on certain series.

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, draws on 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. See Financial condition section for additional information on the bridge term loan credit facilities and the subscription receipts.

Columbia operates a portfolio of approximately 24,000 km (15,000 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 additional long-term growth opportunities. The acquisition also includes a large portfolio of new capital growth projects which includes seven 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 2020 to ensure the continuation of a safe, reliable and efficient system. We are currently executing plans to ensure an effective integration of Columbia into the TransCanada organization. We remain on track to realizing our $250 million of annual cost, revenue and financing benefits.

The following table summarizes the acquisition related costs for Columbia that have been excluded from comparable earnings for the three and nine months ended September 30, 2016.



	three months ended September 30		nine months ended September 30
(unaudited - millions of $)	2016		2016

Natural Gas Pipelines	82		82
Corporate	14		50
Interest expense	6		115
Interest income and other	—		(6	)
Income tax expense	(32	)	(32	)
Non-controlling interests	(3	)	(3	)
Total excluded from comparable earnings	67		206

Monetization of U.S. Northeast Power business

We currently expect to realize approximately US$3.7 billion from the monetization of our U.S. Northeast Power business. This includes the November 1, 2016 announced sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors for US$2.2 billion and TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC for US$1.065 billion, with the remainder attributed to the marketing business which is expected to be realized going forward. These two sale transactions are expected to close in the first half of 2017 subject to certain regulatory and other approvals and will include closing adjustments. These sales are expected to result in an approximate $1.1 billion after-tax net loss which is comprised of a $656 million after-tax goodwill impairment charge recorded at September 30, 2016, an approximate $863 million after-tax net loss on the

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sale of the thermal and wind package to be recorded in fourth quarter 2016 and an approximate $443 million after-tax gain on the sale of the hydro assets to be recorded upon close of that transaction. Proceeds from these sales and future realization of value of the marketing business will be used to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities which were used to partially finance the Columbia acquisition earlier this year.

Minority interest in Mexican pipelines

As part of the Columbia acquisition financing plan, we previously disclosed our intention to monetize a minority interest in our Mexico natural gas pipeline business. On November 1, 2016, we announced a decision to maintain our full ownership interest in a growing portfolio of natural gas pipeline assets in Mexico rather than sell a minority interest in six of these pipelines, which is consistent with maintaining a simple corporate structure. We currently own and operate the Tamazunchale and Guadalajara pipelines and are investing US$3.8 billion to develop and complete construction of four additional pipelines plus fund our interest in the Sur de Texas project, all of which will serve growing natural gas demand in Mexico. All projects are expected to be in-service by the end of 2018 and are underpinned by 25-year take-or-pay contracts with the CFE. Once completed, we expect our Mexican natural gas pipeline assets to be accretive to earnings per share and generate approximately US$575 million of annual EBITDA, up from US$181 million in 2015.

In connection with this decision, we also entered into an agreement with a group of underwriters to proceed with a common equity offering concurrent with the release of these financial results. See Corporate recent developments for more information.

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NATURAL GAS PIPELINES

Canadian Regulated Pipelines

NGTL System

On October 31, 2016, the Government of Canada approved our $1.3 billion NGTL 2017 Facilities Application. In addition, on October 6, 2016, the NEB recommended to the government approval of the $0.4 billion Towerbirch Project. This project consists of a 55 km (34 miles) pipeline loop and a 32 km (20 miles) pipeline extension of the NGTL System in northwest Alberta and northeast B.C. The NEB approved NGTL’s continued use of its existing rolled-in toll methodology for this project. Of NGTL's $5.4 billion near-term capital program we have received approvals for $4.0 billion, while $0.5 billion has been filed and is awaiting approval. Approximately $0.9 billion is expected to be filed with regulators in the future.

We continue to work closely with our shippers to ensure that new proposed facilities meet our shippers and market demands. In second quarter 2016, we added new long term delivery contracts on the NGTL System to meet demand in the Pacific Northwest and California which will require the construction of $135 million of new facilities (the Sundre Crossover Project) that were not previously included in our 2018 Facilities program. The open season process supporting the development of these new contracts identified further demand for service to this market that we are currently assessing.

In second quarter 2016, in response to cancellations or deferrals of our certain customer projects, contract non-renewals, and contract transfers, we re-evaluated planned facility requirements to meet future aggregate system service requirements and made changes in the spending profile of our programs to match revised in-service dates. The projected expansion capital spend 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 have deferred approximately $225 million of spending for facilities in the 2016/17 Facilities program with revised service dates of 2018 through 2020 as well as $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). On September 15, 2016, the NEB approved the sunset clause extension to June 10, 2017. The extension continues to be subject to the condition that construction shall not begin until a positive Final Investment Decision (FID) has been made on the Pacific Northwest LNG (PNW LNG) Project. NGTL continues to work with our customers and stakeholders to be ready to initiate construction of the NMML facilities, however, the in-service date will be finalized once a FID has been made.

2016-2017 NGTL Revenue Requirement Settlement

In April 2016, the NEB approved the NGTL revenue requirement settlement application that was filed in December 2015, subject to certain reporting requirements that were subsequently met and approved by the NEB. 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.

Canadian Mainline Tolling Option Open Season

On October 13, 2016, we launched an open season for the Canadian Mainline, seeking binding commitments on our new long-term, fixed-price proposal to transport WCSB supply from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The contract term for this service is ten years with tolls ranging from $0.75/GJ to $0.82/GJ depending on the shippers’ contract volume commitments. Early termination rights are provided and can be exercised following the initial five years of service upon payment of a premium fee. Subject to a successful open season that closes November 10, 2016, and to NEB regulatory approval, the new service is targeted to begin November 1, 2017.

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U.S. Pipelines

Columbia Capital Projects

The July 1, 2016 acquisition of Columbia included a capital expansion program that was underway for new facilities planned to be in service in 2017 and 2018 as well as modernization programs for existing assets to be completed through 2020. The large capital expansion program consists of US$7.4 billion related to our regulated pipeline business and US$0.3 billion related to our midstream business. The following summarizes the key capital projects for this new set of assets that are now part of the our overall Natural Gas Pipelines footprint in North America.

Leach XPress

This Columbia Gas Transmission (TCO) project is designed to transport up to 1.5 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with the Columbia Gulf System (CGT). The project consists of 219 km (136 miles) of 36-inch greenfield pipe, 39 km (24 miles) of 36-inch loop, three km (two miles) of 30-inch greenfield pipe, 82.8 MW (111,000 hp) of greenfield compression and 24.6 MW (33,000 hp) of brownfield compression. We expect the project, with an estimated capital investment of US$1.4 billion, to be in service in fourth quarter 2017. The FERC 7(C) application was filed in June 2015 and the Final Environmental Impact Statement (FEIS) was received September 1, 2016.

Rayne XPress

This CGT project is designed to transport up to 1.1 Bcf/d of southwest Marcellus and Utica production associated with the Leach XPress expansion and an interconnect with the Texas Eastern System (TETCO) to various delivery points on the CGT system and Gulf Coast. The project consists of bi-directional compressor station modifications along the CGT system, 38.8 MW (52,000 hp) of greenfield compression, 20.1 MW (27,000 hp) of replacement compression and six km (four miles) of 30-inch pipe replacement. We expect the project, with an estimated capital investment of

US$420 million, to be in service in fourth quarter 2017. The FERC 7(C) application was filed in July 2015 and the FEIS was received September 1, 2016.

Mountaineer XPress

This TCO project is designed to transport up to 2.7 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with the CGT system. The project consists of 264 km (164 miles) of 36-inch greenfield pipeline, ten km (six miles) of 24-inch lateral pipeline, 0.6 km (0.4 miles) of 30-inch replacement pipeline, 114.1 MW (153,000 hp) of greenfield compression and 55.9 MW (75,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$2 billion, to be in service in fourth quarter 2018. The FERC 7(C) application was filed in April 2016.

Gulf XPress

This CGT project is designed to transport up to 0.9 Bcf/d associated with the Mountaineer XPress expansion to various delivery points on the CGT system and Gulf Coast. The project consists of adding seven greenfield midpoint compressor stations along the CGT System route totaling 182.7 MW (254,000 hp). We expect this project, with an estimated capital investment of US$0.7 billion, to be placed in service in fourth quarter 2018. The FERC 7(C) application was filed in April 2016.

Cameron Access Project

This CGT project is designed to transport up to 0.8 Bcf/d of gas supply to the Cameron LNG export terminal in Louisiana. The project consists of 44 km (27 miles) of 36-inch greenfield pipeline, 11 km (seven miles) of 30-inch looping and 9.7 MW (13,000 hp) of greenfield compression. We expect this project, with an estimated capital investment of US$300 million, to be in service in first quarter 2018. The FERC certificate was received in September 2015.

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WB XPress

This TCO project is designed to transport up to 1.3 Bcf/d of Marcellus gas supply westbound (0.8 Bcf/d) to the Gulf Coast via an interconnect with the Tennessee Gas Pipeline, and eastbound (0.5 Bcf/d) to Mid-Atlantic markets, WGL Midstream and Transco interconnects. The project consists of 47 km (29 miles) of various diameter pipeline, 338 km (210 miles) of restoring and uprating maximum operating pressure of existing pipeline, 29.8 MW (40,000 hp) of greenfield compression and 99.9 MW (134,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$0.9 billion, to have a Western build in service in the beginning of second quarter 2018 and an Eastern build in service in fourth quarter 2018. The FERC 7(C) application for both segments was filed in December 2015.

Modernization I & II

TCO and its customers have entered into a settlement arrangement, approved by FERC, which provides recovery and return on investment to modernize its system, improve system integrity and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. Modernization I has been approved for up to US$0.6 billion of work yet to be completed in 2016 through 2017. Modernization II has been approved for up to US$1.1 billion of work to be completed in 2018 through 2020. As per terms of the arrangements, facilities in service by October 31 collect revenues effective February 1 of the following year.

Columbia Midstream - Gibraltar Pipeline Project

We expect to invest US$260 million to construct an approximate 1 MMDth/d dry gas header pipeline in southwest Pennsylvania to be completed in multiple phases with an initial in-service date in fourth quarter 2016 and a final in-service date in fourth quarter 2017.

ANR Section 4 Rate Case Settlement

ANR reached a settlement with its shippers effective August 1, 2016 and filed the final, unopposed settlement agreement with the FERC for approval on September 16, 2016. Transmission reservation rates will increase by 34.8 per cent and storage rates will remain the same for contracts one to three years in length, while increasing slightly for contracts of less than one year and decreasing slightly for contracts more than three years in duration. There is a moratorium on any further rate changes until August 1, 2019. ANR may file for new rates after that date if it has spent more than US$0.8 billion in capital additions, but must file for new rates no later than an effective date of August 1, 2022.

Columbia Pipeline Partners LP

On November 1, 2016, we announced that we have entered into an agreement and plan of merger through which our wholly-owned subsidiary, Columbia Pipeline Group, Inc, has agreed to acquire, for cash, all of the outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL) at a price of US$17.00 per common unit for an aggregate transaction value of approximately US$915 million. Common unitholders will also continue to receive regular quarterly distributions of US$0.1975 per common unit including a pro-rated distribution for any partial period to the closing date. The transaction is expected to close in first quarter 2017 subject to receipt of CPPL unitholder approval and customary closing conditions, and is expected to be accretive to earnings per share and simplify our corporate structure. There will be no gain or loss recorded on closing this transaction as CPPL is a consolidated subsidiary.

Mexico

Topolobampo Pipeline

The Topolobampo project is a 530 km (329 miles), 30-inch pipeline with a capacity of 670 MMcf/d and a cost of US$1 billion that will deliver natural gas from interconnections with third party pipelines to Topolobampo, Sinaloa and into the Mazatlán pipeline. Construction of the pipeline is supported by a 25-year natural gas Transportation Service Agreement (TSA) for 670 MMcf/d with the CFE. The physical in-service date is expected to be delayed into 2017 due to

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right-of-way acquisition delays. Under the terms of the TSA, this delay is recognized as a force majeure event with provisions allowing for the collection of revenue as per the original TSA service commencement date of July 2016.

Mazatlán Pipeline

The Mazatlán project is a 413 km (257 miles), 24-inch diameter pipeline running from El Oro to Mazatlán within the state of Sinaloa with an estimated cost of US$0.4 billion and is supported by 25-year contract with the CFE. Construction of the pipeline is supported by a 25-year natural gas TSA for 200 MMcf/d with the CFE. Physical construction is complete and is awaiting natural gas to commence in-service under the contract.

Tula Pipeline

The Tula project is a US$500 million, 36 inch, 250 km (155 mile) pipeline with a contracted capacity of 886 MMcf/d for 25 years with the CFE. The pipeline begins at Tuxpan, Veracruz extending through the states of Puebla and Hidalgo, supplying natural gas to markets near Tula, Querétaro. Construction has commenced with one pipeline spread and at the compressor stations.

Villa de Reyes Pipeline

On April 11, 2016, we announced that we were awarded the contract to build, own and operate the Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 MMcf/d with the CFE. We expect to invest approximately US$0.5 billion 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 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 pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 2.6 bcf/d 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. The project will deliver natural gas to our Tamazunchale and Tuxpan-Tula pipelines and to other transporters in the region.

LNG Pipeline Projects

Prince Rupert Gas Transmission

On September 27, 2016, Pacific NorthWest LNG (PNW LNG) received an environmental certificate from the Government of Canada for a proposed LNG plant at Prince Rupert, B.C. PNW LNG has indicated they will conduct a total project review over the coming months prior to announcing next steps for the project.

PRGT continues engagement with Aboriginal groups and other stakeholders along the route in preparation for a FID by PNW LNG. To date, PRGT has executed long-term project agreements with twelve First Nation groups along the pipeline route.

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, B.C. 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.

TRANSCANADA [35

THIRD 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. Corrective measures required by PHMSA were completed in September 2016. This shutdown did not significantly impact our 2016 earnings.

Houston Lateral and Terminal

In August 2016, the Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline System to Houston, Texas, went into service. 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. These suspensions are in effect until early November 2016, but may have to be extended given the delay in the NEB process noted below.

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 marked 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. On July 20, 2016, the NEB issued the hearing order which provides further detail on the regulatory process.

On August 8, 2016, the NEB commenced the first of a series of community panel sessions held along the pipeline route in New Brunswick. Panel sessions scheduled for the week of August 29, 2016 in Montréal, Québec were subsequently cancelled as three NEB panelists announced their decision to recuse themselves from continuing to sit on the panel to review the project due to allegations of reasonable apprehension of bias. The Chair of the NEB and the Vice Chair, who is also a panel member, have recused themselves of any further duties related to the project. As a result, all hearings for the project were adjourned until further notice as we wait on the federal government to appoint new NEB members and then for the NEB to establish a new panel to hear our applications. The new panel members will then determine how the review process is to be re-initiated. As a result of these actions, we expect a delay in the NEB review process.

TRANSCANADA [36

THIRD QUARTER 2016

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 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. The Balancing Pool has refused to proceed with the arbitrations pending resolution of the court application. On October 20, 2016, we made an application to the Court of Queen’s Bench requesting that the court order the Balancing Pool to proceed. 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 Cap and Trade

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 sets a limit on annual province-wide greenhouse gas emissions beginning in January 2017 and introduces 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 distributors 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. We do not expect a significant overall impact as a result of this new regulation.

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 continues to advocate for the contract on its economic merit as part of their strategy to meet the winter peak capacity needs of the province and is pursuing regulatory options for our agreement to be reinstated. We expect the project need and potential timing will be reassessed in the recently released review of HQ's ten year supply plan.

TRANSCANADA [37

THIRD QUARTER 2016

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.

CORPORATE

Common equity offering

On November 1, 2016, in conjunction with our decision to maintain our current ownership interest in a growing Mexican natural gas pipelines business, and concurrent with the release of these financial results, we also entered into an agreement with a group of underwriters to proceed with an offering of common shares. The common shares will be offered to the public in Canada and the United States through the underwriters or their representatives. The offering is subject to the receipt of all necessary regulatory and stock exchange approvals.

Proceeds from the offering will be used to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities which were used to finance a portion of the purchase price of Columbia. The closing for the offering is expected to be on November 16, 2016.

Dividend Reinvestment Plan

Under our Dividend Reinvestment Plan (DRP), 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 dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent.

TRANSCANADA [38

THIRD 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 (including through the establishment of an at-the-market equity issuance program, if applicable), monetization of assets, cash on hand and substantial committed credit facilities.

At September 30, 2016, our current assets were $5.4 billion and current liabilities were $6.1 billion, leaving us with a working capital deficit of $0.7 billion compared to a deficit of $3.4 billion at December 31, 2015. 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 $8.6 billion of unutilized, unsecured committed credit facilities.

CASH PROVIDED BY OPERATING ACTIVITIES



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016			2015

Net cash provided by operations	1,183		1,247		3,277			2,976
Increase/(decrease) in operating working capital	110		(107	)	(28		)	378
Funds generated from operations¹	1,293		1,140		3,249			3,354
Specific items:
Acquisition related costs - Columbia	99		—		238			—
Keystone XL asset costs	14		—		37			—
Restructuring costs	—		8		—			20
U.S. Northeast Power business monetization	5		—		5			—
Current income taxes	—		—		—			—
Comparable funds generated from operations	1,411		1,148		3,529			3,374
Dividends on preferred shares	(28	)	(23	)	(74		)	(69		)
Distributions paid to non-controlling interests	(77	)	(60	)	(201		)	(168		)
Distributions received in excess of equity earnings²	30		111		217			221
Maintenance capital expenditures including equity investments	(311	)	(223	)	(770		)	(584		)
Comparable distributable cash flow	1,025		953		2,701			2,774
Comparable distributable cash flow per common share	$1.29		$1.34			$3.68			$3.91


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


²	Reflects distributions received from equity investee operating activities and excludes additional distributions of $725 million resulting from Bruce Power's financing program.

COMPARABLE FUNDS GENERATED FROM OPERATIONS

Comparable funds generated from operations is a non-GAAP measure. 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. We calculate this comparable measure by adjusting funds generated from operations for specific items we believe are significant but not reflective of our underlying operations. See the non-GAAP measures section of this MD&A for further discussion on specific items.

Comparable funds generated from operations increased $263 million and $155 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to the increase in net income due to the Columbia acquisition on July 1, 2016.

TRANSCANADA [39

THIRD QUARTER 2016

COMPARABLE DISTRIBUTABLE CASH FLOW

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 for the three and nine months ended September 30, 2016 on our Canadian regulated natural gas pipelines were $105 million and $202 million, respectively (2015 - $87 million and $201 million, respectively) which contributed to their respective rate bases and net income.

CASH USED IN INVESTING ACTIVITIES



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Capital spending
Capital expenditures	(1,444	)	(976	)	(3,262	)	(2,748	)
Capital projects in development	(62	)	(130	)	(219	)	(465	)
	(1,506	)	(1,106	)	(3,481	)	(3,213	)
Contributions to equity investments	(286	)	(105	)	(570	)	(303	)
Restricted cash	13,113		—		—		—
Acquisitions, net of cash acquired	(12,609	)	—		(13,608	)	—
Proceeds from sale of assets, net of transaction costs	—		—		6		—
Distributions received in excess of equity earnings	30		111		942		221
Deferred amounts and other	38		36		18		240
Net cash used in investing activities	(1,220	)	(1,064	)	(16,693	)	(3,055	)

Capital expenditures in 2016 were primarily related to:


•	expansion of the NGTL System


•	construction of Mexico pipelines


•	expansion of the ANR pipeline


•	expansion of Columbia pipelines


•	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, Bruce Power and Sur de Texas.

Restricted cash held in escrow at June 30, 2016 was used for the purchase of Columbia on July 1, 2016.

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

778 MW, for US$653 million in cash after 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 its bank credit facility as part of its financing program to fund its capital program and make distributions to its partners which resulted in $725 million being received by us.

TRANSCANADA [40

THIRD QUARTER 2016

CASH PROVIDED BY FINANCING ACTIVITIES



	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2016		2015		2016		2015

Notes payable repaid, net	(423	)	(358	)	(100	)	(828	)
Long-term debt issued, net of issue costs	6		962		12,333		3,323
Long-term debt repaid	(53	)	(183	)	(2,343	)	(2,066	)
Junior subordinated notes issued, net of issue costs	1,551		—		1,551		917
Dividends and distributions paid	(502	)	(452	)	(1,434	)	(1,315	)
Common shares/subscription receipts issued, net of issue costs	(37	)	1		4,337		12
Common shares repurchased	—		—		(14	)	—
Partnership units of subsidiary issued, net of issue costs	45		—		151		31
Preferred shares issued, net of issue costs	—		—		492		243
Net cash provided by/(used in) financing activities	587		(30	)	14,973		317

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 the U.S. Northeast Power business monetizations and the November 2016 common equity offering will be used to partially repay these facilities.


²	Reflects coupon rate on re-opening of existing medium term notes (MTN) issue. New MTNs were issued at a premium resulting in a re-issuance yield of 2.69 per cent.

JUNIOR SUBORDINATED DEBT ISSUED

(unaudited - millions of $)
Company

Issue date

Type

Maturity date

Amount

Interest rate

TRANSCANADA PIPELINES LIMITED

August 2016

Junior Subordinated Unsecured Notes¹

August 2076

US $1,200

6.125


¹	The Junior subordinated unsecured notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL and are callable at TCPL's option at any time on or after August 15, 2026 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

TRANSCANADA [41

THIRD QUARTER 2016


²	The Junior subordinated unsecured notes were issued to TransCanada Trust. The interest rate is fixed at 6.125 per cent per annum and will reset starting August 2026 until August 2046 to the three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the three month LIBOR plus 5.64 per cent per annum.

On August 15, 2016, TransCanada Trust (the Trust), a wholly owned trust subsidiary of TCPL, issued US$1.2 billion of Trust Notes to third party investors with a fixed interest rate of 5.875 per cent for the first ten years converting to a floating rate thereafter. The proceeds of the Trust Notes were loaned to TCPL through the subscription for US$1.2 billion of junior subordinated notes of TCPL at a rate of 6.125 per cent which includes a 0.25 per cent administration charge. While the obligations of the Trust are fully guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL.

Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with other outstanding first preferred shares of TCPL.

LONG-TERM DEBT RETIRED



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

TRANSCANADA PIPELINES LIMITED
	October 2016	Medium Term Notes		$400	4.65	%
	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	%

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 September 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.

TRANSCANADA [42

THIRD QUARTER 2016

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 holder received one common share upon closing of the Columbia acquisition. 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 was made on July 29, 2016 to holders of record at the close of business on June 30, 2016. For the nine months ended September 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.

Interest income of $6 million relating to the proceeds while held in escrow 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

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.

In April 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 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 yield

Annual dividend per share¹

Redemption price per share²

Redemption and conversion option date^2,3

Right to convert into³

Cumulative first preferred shares

Series 5

12,714

2.263

$0.56575

$25.00

January 30, 2021

Series 6

1,286

Floating⁴

Floating

$25.00

January 30, 2021

Series 5

Series 13

20,000

5.5

$1.375

$25.00

May 31, 2021

Series 14

TRANSCANADA [43

THIRD QUARTER 2016


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	The holder will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter.


⁴	Commencing September 30, 2016, the floating quarterly dividend rate for the Series 6 preferred shares is 2.073 per cent and will reset every quarter going forward.

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

Since January 1, 2016, 2.7 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$143 million. Our ownership interest in TC PipeLines, LP was 27 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 November 1, 2016, we declared quarterly dividends as follows:



Quarterly dividend on our common shares

$0.565 per share
Payable on January 30, 2017 to shareholders of record at the close of business on January 3, 2017



Quarterly dividends on our preferred shares

Series 1	$0.204125
Series 2	$0.15283060
Series 3	$0.1345
Series 4	$0.11212020
Payable on December 30, 2016 to shareholders of record at the close of business on November 30, 2016
Series 5	$0.14143750
Series 6	$0.13038299
Series 7	$0.25
Series 9	$0.265625
Payable on January 30, 2017 to shareholders of record at the close of business on January 3, 2017
Series 11	$0.2375
Series 13	$0.34375
Payable on November 30, 2016 to shareholders of record at the close of business on November 14, 2016

TRANSCANADA [44

THIRD QUARTER 2016

SHARE INFORMATION



as at October 28, 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	6 million

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 November 1, 2016, we had approximately $19.2 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$1.3 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	$0.6 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 the LIBOR plus an applicable margin. Proceeds from the U.S. Northeast Power business monetizations and the November 2016 common equity offering will be used to partially repay these facilities.

At November 1, 2016, our operated affiliates had an additional $0.4 billion of undrawn capacity on committed credit facilities.

TRANSCANADA [45

THIRD QUARTER 2016

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

CONTRACTUAL OBLIGATIONS

Our capital commitments have increased by approximately $1.5 billion since December 31, 2015 as a result of the new commitments for the Tula, Villa de Reyes and Sur de Texas 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 $0.5 billion as a result of the extension of premises leases in second quarter 2016. The acquisition of Columbia on July 1, 2016 resulted in a total increase to our contractual obligations of $349 million for transportation contracts and premises leases. There were no other material changes to our contractual obligations in third 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.

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


•	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 September 30, 2016, we had no significant credit losses and no significant amounts past due or impaired. We had a credit risk concentration of $191 million (US$146 million) at September 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.

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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 further managed 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.

Average exchange rate - U.S. to Canadian dollars



three months ended September 30, 2016	1.31
three months ended September 30, 2015	1.31

nine months ended September 30, 2016	1.32
nine months ended September 30, 2015	1.26

The impact of changes in the value of the U.S. dollar on our U.S. and international operations, on a pre-tax basis, 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 September 30				nine months ended September 30
(unaudited - millions of US$)	2016		2015		2016		2015

U.S. and International Natural Gas Pipelines comparable EBIT	366		153		792		526
U.S. Liquids Pipelines comparable EBIT	119		171		369		474
U.S. Power comparable EBIT	131		117		228		257
AFUDC on U.S. dollar-denominated projects	55		37		149		98
Interest on U.S. dollar-denominated long-term debt	(315	)	(231	)	(811	)	(677	)
Capitalized interest on U.S. dollar-denominated capital expenditures	6		42		22		102
U.S. non-controlling interests	(38	)	(35	)	(138	)	(115	)
	324		254		611		665

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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:



	September 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	(433	)	US 2,400	(730	)	US 3,150
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	(16	)	US 200	50		US 1,800
	(449	)	US 2,600	(680	)	US 4,950


¹	Fair values equal carrying values.


²	In the three and nine months ended September 30, 2016, net realized gains of $1 million and $5 million, respectively, (2015 - gains of $2 million and $7 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)	September 30, 2016	December 31, 2015

Notional amount	30,200 (US 23,000)	23,100 (US 16,700)
Fair value	33,700 (US 25,700)	23,800 (US 17,200)

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.

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Balance sheet presentation of derivative instruments

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



(unaudited - millions of $)	September 30, 2016		December 31, 2015

Other current assets	332		442
Intangible and other assets	181		168
Accounts payable and other	(616	)	(926	)
Other long-term liabilities	(428	)	(625	)
	(531	)	(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 September 30				nine months ended September 30
(unaudited - millions of $, pre-tax)	2016		2015		2016		2015

Derivative instruments held for trading¹
Amount of unrealized (losses)/gains in the period
Commodities²	(97	)	(27	)	23		(30	)
Foreign exchange	—		(26	)	47		(25	)
Amount of realized (losses)/gains in the period
Commodities	(23	)	(52	)	(165	)	(84	)
Foreign exchange	(5	)	(34	)	52		(87	)
Derivative instruments in hedging relationships
Amount of realized (losses)/gains in the period
Commodities	(15	)	(35	)	(155	)	(132	)
Foreign exchange	5		—		(101	)	—
Interest rate	1		2		4		6


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.


²	Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast Power business, 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.

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Derivatives in cash flow hedging relationships

The components of the condensed consolidated statement of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests is as follows:



	three months ended September 30				nine months ended September 30
(unaudited - millions of $, pre-tax)	2016		2015		2016		2015

Change in fair value of derivative instruments recognized in OCI (effective portion)¹
Commodities	7		(48	)	33		(77	)
Foreign exchange	(5	)	—		—		—
Interest rate	4		(1	)	—		(1	)
	6		(49	)	33		(78	)
Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)¹
Commodities²	(7	)	76		54		124
Foreign exchange³	5		—		—		—
Interest rate⁴	3		4		11		12
	1		80		65		136
Gains/(losses) on derivative instruments recognized in net income (ineffective portion)
Commodities²	14		10		(1	)	3
	14		10		(1	)	3


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 September 30, 2016, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $24 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 September 30, 2016, we would have been required to provide additional collateral of $24 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.

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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 September 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.

We acquired Columbia on July 1, 2016. Assets attributable to Columbia as of July 1, 2016 represented approximately 25 per cent of our total assets as of July 1, 2016, and revenues attributable to Columbia for the period July 1, 2016 to September 30, 2016 represented approximately 12 per cent of our total revenues for third quarter 2016. Management is currently in the process of evaluating and integrating Columbia’s controls over financial reporting with ours. We expect to complete this integration in 2017.

Other than as described above, there were no changes in third 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. The fair value of assets and liabilities acquired in a business combination accounted for under the acquisition method are also subject to estimates and judgement. 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.

Impairment of long-lived assets and goodwill

We test goodwill for impairment on an annual basis or more frequently if events or changes in circumstances indicate that it might be impaired. As a result of information received during the process to monetize our U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood did not exceed its carrying value, including goodwill, at September 30, 2016. The fair value of Ravenswood was determined using a combination of methods including a discounted cash flow approach and a range of expected consideration from a potential sale. Plant, property and equipment was also tested for impairment. As a result, at September 30, 2016, we recorded a goodwill impairment charge on the full goodwill amount of $1,085 million ($656 million after tax) related to the Ravenswood facility within the Energy segment and also determined there was no impairment on the plant, property and equipment.

At September 30, 2016, our goodwill included $1.9 billion related to the ANR natural gas transportation business. As a result of our ANR Section 4 rate case settlement filed on September 16, 2016, we tested this reporting unit for impairment. The fair value of this reporting unit was measured by using a discounted cash flow analysis incorporating the key terms of the settlement. While no impairment of goodwill was necessary, the estimated fair value of ANR exceeds its carrying value, including goodwill, by less than 10 per cent. Under the settlement, there is a moratorium on any further rate changes until August 1, 2019. Adverse conditions impacting rates and volumes on ANR beyond the moratorium period could result in a reduction for our estimated future cash flows, which could result in future impairment of a portion of the goodwill balance related to ANR.

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.

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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 16, 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.

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

TRANSCANADA [52

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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 do not expect the adoption of this guidance to have a material impact 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, 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.

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We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

Classification of certain cash receipts and cash payments

In August 2016, the FASB issued new guidance to clarify how entities should classify certain cash receipts and cash payments. These include debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance and distributions received from equity method investees. The new guidance is effective January 1, 2018 and will be applied using a retrospective approach. The new guidance also specifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the impact on our consolidated financial statements.

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Reconciliation of non-GAAP measures



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

EBITDA	605		1,458		3,262		4,334
Ravenswood goodwill impairment	1,085		—		1,085		—
Alberta PPA terminations	—		—		240		—
Acquisition related costs - Columbia	96		—		132		—
Keystone XL asset costs	14		—		37		—
Restructuring costs	—		8		14		20
TC Offshore loss on sale	—		—		4		—
U.S. Northeast Power business monetization	5		—		5		—
Risk management activities¹	81		17		(22	)	27
Comparable EBITDA	1,886		1,483		4,757		4,381
Depreciation and amortization	(527	)	(439	)	(1,425	)	(1,313	)
Comparable EBIT	1,359		1,044		3,332		3,068
Other income statement items
Comparable interest expense	(516	)	(341	)	(1,341	)	(990	)
Comparable interest income and other	122		42		385		108
Comparable income tax expense	(261	)	(236	)	(630	)	(668	)
Comparable net income attributable to non-controlling interests	(55	)	(46	)	(187	)	(145	)
Preferred share dividends	(27	)	(23	)	(77	)	(71	)
Comparable earnings	622		440		1,482		1,302
Specific items (net of tax):
Ravenswood goodwill impairment	(656	)	—		(656	)	—
Alberta PPA terminations	—		—		(176	)	—
Acquisition related costs - Columbia	(67	)	—		(206	)	—
Keystone XL income tax recoveries	28		—		28		—
Keystone XL asset costs	(9	)	—		(24	)	—
Restructuring costs	—		(6	)	(10	)	(14	)
TC Offshore loss on sale	—		—		(3	)	—
U.S. Northeast Power business monetization	(3	)	—		(3	)	—
Alberta corporate income tax rate increase	—		—		—		(34	)
Risk management activities¹	(50	)	(32	)	50		(36	)
Net (loss)/income attributable to common shares	(135	)	402		482		1,218

Comparable interest expense	(516	)	(341	)	(1,341	)	(990	)
Specific item:
Acquisition related costs - Columbia	(6	)	—		(115	)	—
Interest expense	(522	)	(341	)	(1,456	)	(990	)

Comparable interest income and other	122		42		385		108
Specific items:
Acquisition related costs - Columbia	—		—		6		—
Risk management activities¹	—		(26	)	49		(25	)
Interest income and other	122		16		440		83

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

Comparable income tax expense	(261		)	(236		)	(630		)	(668		)
Specific items:
Ravenswood goodwill impairment	429			—			429			—
Alberta PPA terminations	—			—			64			—
Acquisition related costs - Columbia	32			—			32			—
Keystone XL income tax recoveries	28			—			28			—
Keystone XL asset costs	5			—			13			—
Restructuring costs	—			2			4			6
TC Offshore loss on sale	—			—			1			—
U.S. Northeast Power business monetization	2			—			2			—
Alberta corporate income tax rate increase	—			—			—			(34		)
Risk management activities¹	31			11			(21		)	16
Income tax recovery/(expense)	266			(223		)	(78		)	(680		)

Comparable net income attributable to non-controlling interests	(55		)	(46		)	(187		)	(145		)
Specific item:
Acquisition related costs - Columbia	3			—			3			—
Net income attributable to non-controlling interests	(52		)	(46		)	(184		)	(145		)

Comparable earnings per common share	$0.78			$0.62				$2.02			$1.84
Specific items (net of tax):
Ravenswood goodwill impairment	(0.82		)	—			(0.89		)	—
Alberta PPA terminations	—			—			(0.25		)	—
Acquisition related costs - Columbia	(0.09		)	—			(0.29		)	—
Keystone XL income tax recoveries	0.03			—			0.04			—
Keystone XL asset costs	(0.01		)	—			(0.03		)	—
Restructuring costs	—			(0.01		)	(0.01		)	(0.02		)
U.S. Northeast Power business monetization	—			—			—			—
Alberta corporate income tax rate increase	—			—			—			(0.05		)
Risk management activities	(0.06		)	(0.04		)	0.07			(0.05		)
Net (loss)/income per common share		($0.17	)		$0.57			$0.66			$1.72



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

	Canadian Power	(4	)	(14	)	3		(7	)
	U.S. Power	(73	)	(5	)	16		(22	)
	Liquids	(8	)	—		(6	)	—
	Natural Gas Storage	4		2		9		2
	Foreign exchange	—		(26	)	49		(25	)
	Income tax attributable to risk management activities	31		11		(21	)	16
	Total unrealized (losses)/gains from risk management activities	(50	)	(32	)	50		(36	)

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Comparable EBITDA and EBIT by business segment



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

EBITDA	1,114		259		(744	)	(24	)	605
Ravenswood goodwill impairment	—		—		1,085		—		1,085
Alberta PPA terminations	—		—		—		—		—
Acquisition related costs - Columbia	82		—		—		14		96
Keystone XL asset costs	—		14		—		—		14
Restructuring costs	—		—		—		—		—
U.S. Northeast Power business monetization	—		—		5		—		5
Risk management activities	—		8		73		—		81
Comparable EBITDA	1,196		281		419		(10	)	1,886
Comparable depreciation and amortization	(361	)	(72	)	(81	)	(13	)	(527	)
Comparable EBIT	835		209		338		(23	)	1,359



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

EBITDA	806		352		323		(23	)	1,458
Restructuring costs	—		—		—		8		8
Risk management activities	—		—		17		—		17
Comparable EBITDA	806		352		340		(15	)	1,483
Comparable depreciation and amortization	(284	)	(68	)	(79	)	(8	)	(439	)
Comparable EBIT	522		284		261		(23	)	1,044



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

EBITDA	2,888		818		(318	)	(126	)	3,262
Ravenswood goodwill impairment	—		—		1,085		—		1,085
Alberta PPA terminations	—		—		240		—		240
Acquisition related costs - Columbia	82		—		—		50		132
Keystone XL asset costs	—		37		—		—		37
Restructuring costs	—		—		—		14		14
TC Offshore loss on sale	4		—		—		—		4
U.S. Northeast Power business monetization	—		—		5		—		5
Risk management activities	—		6		(28	)	—		(22	)
Comparable EBITDA	2,974		861		984		(62	)	4,757
Depreciation and amortization	(936	)	(209	)	(251	)	(29	)	(1,425	)
Comparable EBIT	2,038		652		733		(91	)	3,332

TRANSCANADA [57

THIRD QUARTER 2016



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

EBITDA	2,472		970		963		(71	)	4,334
Restructuring costs	—		—		—		20		20
Risk management activities	—		—		27		—		27
Comparable EBITDA	2,472		970		990		(51	)	4,381
Depreciation and amortization	(845	)	(197	)	(248	)	(23	)	(1,313	)
Comparable EBIT	1,627		773		742		(74	)	3,068

TRANSCANADA [58

THIRD QUARTER 2016

Quarterly results

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA



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

Revenues	3,632			2,751		2,503		2,851			2,944		2,631		2,874		2,616
Net (loss)/income attributable to common shares	(135		)	365		252		(2,458		)	402		429		387		458
Comparable earnings	622			366		494		453			440		397		465		511
Share statistics
Net (loss)/income per common share - basic and diluted		($0.17	)		$0.52		$0.36		($3.47	)		$0.57		$0.60		$0.55		$0.65
Comparable earnings per share		$0.78			$0.52		$0.70		$0.64			$0.62		$0.56		$0.66		$0.72
Dividends declared per common share		$0.565			$0.565		$0.565		$0.52			$0.52		$0.52		$0.52		$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


•	impairment of goodwill and other assets.

TRANSCANADA [59

THIRD QUARTER 2016

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 third quarter 2016, comparable earnings excluded:


•	a $656 million after-tax impairment on the Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeds its carrying value


•	costs associated with the acquisition of Columbia including a charge of $67 million after tax primarily relating to retention, severance and integration expenses


•	$28 million of income tax recoveries related to the realized loss on a third party sale of Keystone XL plant and equipment. A provision for the expected loss on these assets was was included in our fourth quarter 2015 impairment charge but the related tax recoveries could not be recorded until realized


•	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 $3 million after-tax charge related to the monetization of our U.S. Northeast Power business.

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

TRANSCANADA [60

THIRD QUARTER 2016


•	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.