Exhibit

three months ended March 31

(unaudited - millions of $)

Net income attributable to non-controlling interests

EX-13.1 2 trp-03312016xmda.htm MANAGEMENT'S DISCUSSION AND ANALYSIS Exhibit

EXHIBIT 13.1

Quarterly report to shareholders

First quarter 2016

Financial highlights



	three months ended March 31
(unaudited - millions of $, except per share amounts)	2016			2015

Income
Revenues	2,547			2,874
Net income attributable to common shares	252			387
per common share - basic and diluted		$0.36			$0.55
Comparable EBITDA¹	1,502			1,531
Comparable earnings¹	494			465
per common share¹		$0.70			$0.66

Operating cash flow
Funds generated from operations¹	1,125			1,153
Increase in operating working capital	(80		)	(393		)
Net cash provided by operations	1,045			760

Comparable distributable cash flow¹	970			956
per common share¹		$1.38			$1.35

Investing activities
Capital spending - capital expenditures	836			806
Capital spending - projects in development	67			163
Contributions to equity investments	170			93
Acquisitions, net of cash acquired	995			—
Proceeds from sale of assets, net of transaction costs	6			—

Dividends declared
Per common share		$0.565			$0.52
Basic common shares outstanding (millions)
Average for the period	702			709
End of period	702			709


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

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Management’s discussion and analysis

April 28, 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 months ended March 31, 2016, and should be read with the accompanying unaudited condensed consolidated financial statements for the three months ended March 31, 2016 which have been prepared in accordance with U.S. GAAP.

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 April 28, 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:


•	anticipated business prospects, including the expected closing and financing of the Columbia Pipeline Group, Inc. (Columbia) acquisition


•	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


•	timing and completion of the Columbia acquisition including receipt of regulatory and Columbia stockholder approval


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


•	inflation rates, commodity prices and capacity prices


•	timing of financings and hedging


•	regulatory decisions and outcomes


•	termination of the Alberta PPAs


•	foreign exchange rates


•	interest rates


•	tax rates


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


•	integrity and reliability of our assets


•	access to capital markets


•	anticipated construction costs, schedules and completion dates


•	acquisitions and divestitures.

Risks and uncertainties


•	length of time to complete the acquisition of Columbia


•	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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FIRST QUARTER 2016

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

FOR MORE INFORMATION

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

NON-GAAP MEASURES

We use the following non-GAAP measures:


•	EBITDA


•	EBIT


•	funds generated from operations


•	distributable cash flow


•	distributable cash flow per common share


•	comparable earnings


•	comparable earnings per common share


•	comparable EBITDA


•	comparable EBIT


•	comparable distributable cash flow


•	comparable distributable cash flow per common share


•	comparable income from equity investments


•	comparable interest expense


•	comparable interest income and other expense


•	comparable income tax expense.

These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar measures presented by other entities. Please see the Reconciliation of non-GAAP measures section in this MD&A for a reconciliation of the GAAP measures to the non-GAAP measures.

EBITDA and EBIT

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

Funds generated from operations

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

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Distributable cash flow

Distributable cash flow is defined as funds generated from operations plus distributions received in excess of equity earnings 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 includes amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. We believe it is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. See the Financial condition section for a reconciliation to net cash provided by operations.

Comparable measures

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



Comparable measure	Original measure

comparable earnings	net income attributable to common shares
comparable earnings per common share	net income per common share
comparable EBITDA	EBITDA
comparable EBIT	segmented earnings
comparable distributable cash flow	distributable cash flow
comparable distributable cash flow per common share	distributable cash flow per common share
comparable income from equity investments	income from equity investments
comparable interest expense	interest expense
comparable interest income and other expense	interest income and other expense
comparable income tax expense	income tax expense

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


•	certain fair value adjustments relating to risk management activities


•	income tax refunds and adjustments and changes to enacted rates


•	gains or losses on sales of assets


•	legal, contractual and bankruptcy settlements


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


•	restructuring costs


•	impairment of assets and investments


•	acquisition costs.

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

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Consolidated results - first 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 March 31
(unaudited - millions of $, except per share amounts)	2016		2015

Natural Gas Pipelines	607		585
Liquids Pipelines	218		242
Energy	(122	)	212
Corporate	(60	)	(31		)
Total segmented earnings	643		1,008
Interest expense	(420	)	(318		)
Interest income and other	201		(14		)
Income before income taxes	424		676
Income tax expense	(70	)	(207		)
Net income	354		469
Net income attributable to non-controlling interests	(80	)	(59		)
Net income attributable to controlling interests	274		410
Preferred share dividends	(22	)	(23		)
Net income attributable to common shares	252		387
Net income per common share - basic and diluted	$0.36			$0.55

Net income attributable to common shares decreased by $135 million for the three months ended March 31, 2016 compared to the same period in 2015. The 2016 results included:


•	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 relating 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.

Net income in both 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 $29 million for the three months ended March 31, 2016 compared to the same period in 2015 as discussed below in the reconciliation of net income to comparable earnings.

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FIRST QUARTER 2016

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS



	three months ended March 31
(unaudited - millions of $, except per share amounts)	2016	2015

Net income attributable to common shares	252	387
Specific items (net of tax):
Alberta PPA terminations	176	—
Acquisition costs - Columbia Pipeline Group	26	—
Keystone XL asset costs	6	—
TC Offshore loss on sale	3	—
Risk management activities¹	31	78
Comparable earnings	494	465

Net income per common share	$0.36	$0.55
Specific items (net of tax):
Alberta PPA terminations	0.25	—
Acquisition costs - Columbia Pipeline Group	0.04	—
Keystone XL asset costs	0.01	—
TC Offshore loss on sale	—	—
Risk management activities	0.04	0.11
Comparable earnings per share	$0.70	$0.66



¹	Risk management activities	three months ended March 31
	(unaudited - millions of $)	2016		2015

	Canadian Power	(13	)	(22	)
	U.S. Power	(115	)	(68	)
	Liquids	(2	)	—
	Natural Gas Storage	5		1
	Foreign exchange	53		(29	)
	Income tax attributable to risk management activities	41		40
	Total losses from risk management activities	(31	)	(78	)

Comparable earnings increased by $29 million for the three months ended March 31, 2016 compared to the same period in 2015. This was primarily the net effect of:


•	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 and increased AFUDC related to our rate-regulated projects


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


•	higher interest expense from debt issuances and lower capitalized interest from Keystone XL


•	lower earnings from U.S. Power mainly due to decreased margins on sales to wholesale, commercial and industrial customers, the impact of lower realized prices in both New England and New York and lower capacity prices in New York, partially offset by incremental earnings from the Ironwood power plant in Lebanon, Pennsylvania acquired February 1, 2016


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


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


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

TRANSCANADA [8

FIRST QUARTER 2016

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

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 consists of $13 billion of near-term projects and $45 billion of commercially secured medium and longer-term projects. Amounts presented exclude the impact of foreign exchange, capitalized interest and AFUDC.

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



at March 31, 2016	Estimated project cost	Carrying value
(unaudited - billions of $)	Estimated project cost	Carrying value
Summary
Near-term	13.3	4.3
Medium to longer-term	45.2	2.2
Total capital program	58.5	6.5

Foreign exchange impact on Capital Program¹	3.5	0.7


¹	Reflects U.S. foreign exchange rate of $1.30 at March 31, 2016.



at March 31, 2016	Segment	Expected in-service date	Estimated project cost	Carrying value
(unaudited - billions of $)	Segment	Expected in-service date	Estimated project cost	Carrying value

Houston Lateral and Terminal	Liquids Pipelines	2016	US 0.6	US 0.5
Topolobampo	Natural Gas Pipelines	2016	US 1.0	US 0.9
Mazatlan	Natural Gas Pipelines	2016	US 0.4	US 0.3
Canadian Mainline	Natural Gas Pipelines	2016-2017	0.7	0.1
NGTL - 2016/17 Facilities	Natural Gas Pipelines	2016-2018	2.7	0.5
- North Montney	Natural Gas Pipelines	2017	1.7	0.3
- 2018 Facilities	Natural Gas Pipelines	2018	0.6	—
- Other	Natural Gas Pipelines	2016-2017	0.4	—
Grand Rapids¹	Liquids Pipelines	2017	0.9	0.6
Northern Courier	Liquids Pipelines	2017	1.0	0.6
Tuxpan-Tula	Natural Gas Pipelines	2017	US 0.5	US 0.1
Napanee	Energy	2017 or 2018	1.0	0.4
Tula-Villa de Reyes	Natural Gas Pipelines	2018	US 0.6	—
Bruce Power - life extension¹	Energy	2016-2020	1.2	—
Total near-term projects			13.3	4.3


¹	Our proportionate share.

TRANSCANADA [9

FIRST QUARTER 2016



at March 31, 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 0.4
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	0.3
Prince Rupert Gas Transmission	Natural Gas Pipelines	5.0	0.4
NGTL System - Merrick	Natural Gas Pipelines	1.9	—
Total medium to longer-term projects		45.2	2.2


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.

Outlook

Our overall earnings outlook for 2016 remains consistent with what was previously included in the 2015 Annual Report. Any changes in outlook with respect to specific lines of business are addressed within each business section of the MD&A. This outlook excludes the Columbia acquisition and related financing and asset sales. See Recent developments section for more information.

TRANSCANADA [10

FIRST QUARTER 2016

Natural Gas Pipelines

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



	three months ended March 31
(unaudited - millions of $)	2016		2015

Comparable EBITDA	898		864
Depreciation and amortization	(287	)	(279	)
Comparable EBIT	611		585
Specific item:
TC Offshore loss on sale	(4	)	—
Segmented earnings	607		585

Natural Gas Pipelines segmented earnings increased by $22 million for the three months ended March 31, 2016 compared to the same period in 2015 and included an additional $4 million pre-tax loss on the sale of TC Offshore. This amount has been excluded from our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below.



	three months ended March 31
(unaudited - millions of $)	2016		2015

Canadian Pipelines
Canadian Mainline	240		263
NGTL System	234		219
Foothills	26		26
Other Canadian pipelines¹	7		6
Canadian Pipelines - comparable EBITDA	507		514
Depreciation and amortization	(216	)	(209	)
Canadian Pipelines - comparable EBIT	291		305

U.S. and International Pipelines (US$)
ANR	88		86
TC PipeLines, LP^1,2	31		26
Great Lakes³	25		20
Other U.S. pipelines (Iroquois¹,GTN^2,4, PNGTS^2,5)	14		41
Mexico (Guadalajara, Tamazunchale)	41		47
International and other^1,6	2		2
Non-controlling interests⁷	95		74
U.S. and International Pipelines - comparable EBITDA	296		296
Depreciation and amortization	(53	)	(57	)
U.S. and International Pipelines - comparable EBIT	243		239
Foreign exchange impact	84		59
U.S. and International Pipelines - comparable EBIT(Cdn$)	327		298
Business Development comparable EBITDA and EBIT	(7	)	(18	)
Natural Gas Pipelines - comparable EBIT	611		585

TRANSCANADA [11

FIRST QUARTER 2016


¹	Results from TQM, Northern Border, Iroquois and TransGas reflect our share of equity income from these investments. On March 31, 2016, we purchased an additional 4.87 per cent interest in Iroquois.

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



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

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


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


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


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


⁶	Includes our share of the equity income from TransGas as well as general and administration costs relating to our U.S. and International Pipelines.


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

CANADIAN PIPELINES

Net income and comparable EBITDA for our rate-regulated Canadian pipelines are generally affected by our approved ROE, our investment base, the level of deemed common equity and incentive earnings or losses. Changes in depreciation, financial charges and taxes also impact comparable EBITDA but do not have 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 March 31
(unaudited - millions of $)	2016	2015

Canadian Mainline	50	47
NGTL System	73	64
Foothills	4	4

Net income for the Canadian Mainline increased by $3 million for the three months ended March 31, 2016 compared to the same period in 2015 primarily due to higher incentive earnings partially offset by a lower average investment base in 2016. No incentive earnings were recorded in the first quarter of 2015 because NEB approval of 2015 - 2020 compliance tolls for the NEB 2014 Decision was not received until June 2015. The NEB 2014 Decision included an approved ROE of 10.1 per cent with a possible range of achieved ROE outcomes between 8.7 per cent to 11.5 per cent.

Net income for the NGTL System increased by $9 million for the three months ended March 31, 2016 compared to the same period in 2015 mainly due to a higher average investment base.

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FIRST QUARTER 2016

U.S. AND INTERNATIONAL PIPELINES

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

Comparable EBITDA for U.S. and International Pipelines was consistent for the three months ended March 31, 2016 compared to the same period in 2015. This was the net effect of:


•	higher ANR Southeast mainline transportation revenues offset by a first quarter 2015 non-recurring settlement


•	lower contributions from Mexico Pipelines


•	higher transportation revenues from Great Lakes.

As well, a stronger U.S. dollar in first quarter 2016 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 $8 million for three months ended March 31, 2016 compared to the same period in 2015 mainly because of a higher investment base on the NGTL System and the effect of a stronger U.S. dollar.

BUSINESS DEVELOPMENT

Business development expenses were lower by $11 million for the three months ended March 31, 2016 compared to the same period in 2015 mainly due to decreased business development activity.

OPERATING STATISTICS - WHOLLY OWNED PIPELINES



three months ended March 31	Canadian Mainline¹		NGTL System²		ANR³
(unaudited)	2016	2015	2016	2015	2016	2015

Average investment base (millions of $)	4,384	5,018	7,257	6,419	n/a	n/a
Delivery volumes (Bcf):
Total	481	529	1,063	1,058	449	509
Average per day	5.3	5.9	11.7	11.8	4.9	5.7


¹	Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2016 were 274 Bcf (2015 – 302 Bcf). Average per day was 3.0 Bcf (2015 – 3.4 Bcf).


²	Field receipt volumes for the NGTL System for the three months ended March 31, 2016 were 1,074 Bcf (2015 – 1,009 Bcf). Average per day was 11.8 Bcf (2015 – 11.2 Bcf).


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

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FIRST QUARTER 2016

Liquids Pipelines



	three months ended March 31
(unaudited - millions of $)	2016		2015

Comparable EBITDA	300		305
Depreciation and amortization	(70	)	(63	)
Comparable EBIT	230		242
Specific items:
Keystone XL asset costs	(10	)	—
Risk management activities	(2	)	—
Segmented earnings	218		242

Liquids Pipelines segmented earnings decreased by $24 million for the three months ended March 31, 2016 compared to the same period in 2015 and included a $10 million pre-tax charge related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project, and unrealized 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 March 31
(unaudited - millions of $)	2016		2015

Keystone Pipeline System	307		311
Liquids Pipelines Business Development and Other	(7	)	(6	)
Liquids Pipelines - comparable EBITDA	300		305
Depreciation and amortization	(70	)	(63	)
Liquids Pipelines - comparable EBIT	230		242

Comparable EBIT denominated as follows:
Canadian dollars	55		60
U.S. dollars	130		147
Foreign exchange impact	45		35
	230		242

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

Comparable EBITDA for the Keystone Pipeline System decreased by $4 million for the three months ended March 31, 2016 compared to the same period in 2015. The decrease was the net effect of:


•	lower uncontracted volumes on Keystone Pipeline System


•	lower volumes on Marketlink


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

TRANSCANADA [14

FIRST QUARTER 2016

BUSINESS DEVELOPMENT AND OTHER

Business development and other expenses increased by $1 million for the three months ended March 31, 2016 compared to the same period in 2015.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $7 million for the three months ended March 31, 2016 compared to the same period in 2015 due to the effect of a stronger U.S. dollar.

OUTLOOK

Following our Keystone XL impairment charge in 2015, future expenditures on the project for the maintenance and liquidation of project assets, expected to be approximately $65 million before tax ($42 million after tax) in 2016, are being expensed pending further advancement of this project. These costs will be excluded from comparable earnings.

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FIRST QUARTER 2016

Energy



	three months ended March 31
(unaudited - millions of $)	2016		2015

Comparable EBITDA	329		386
Depreciation and amortization	(88	)	(85	)
Comparable EBIT	241		301
Specific items:
Alberta PPA terminations	(240	)	—
Risk management activities	(123	)	(89	)
Segmented (loss)/earnings	(122	)	212

Energy segmented earnings decreased by $334 million for the three months ended March 31, 2016 compared to the same period in 2015 and included the following specific items that have been excluded from comparable EBIT:


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


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



Risk management activities	three months ended March 31
(unaudited - millions of $, pre-tax)	2016		2015

Canadian Power	(13	)	(22	)
U.S. Power	(115	)	(68	)
Natural Gas Storage	5		1
Total losses from risk management activities	(123	)	(89	)

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

Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast power assets, we were required to discontinue hedge accounting for certain cash flow hedges which resulted in a pre-tax net loss of $42 million for the three months ended March 31, 2016. This contributed to higher unrealized losses for U.S. Power risk management activities.

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



	three months ended March 31
(unaudited - millions of $)	2016		2015

Canadian Power
Western Power¹	4		15
Eastern Power	103		130
Bruce Power	114		79
Canadian Power - comparable EBITDA^1,2	221		224
Depreciation and amortization	(46	)	(48	)
Canadian Power - comparable EBIT^1,2	175		176

U.S. Power (US$)
U.S. Power - comparable EBITDA	76		132
Depreciation and amortization	(30	)	(27	)
U.S. Power - comparable EBIT	46		105
Foreign exchange impact	17		24
U.S. Power - comparable EBIT (Cdn$)	63		129

Natural Gas Storage and other - comparable EBITDA	9		3
Depreciation and amortization	(3	)	(3	)
Natural Gas Storage and other - comparable EBIT	6		—

Business Development comparable EBITDA and EBIT	(3	)	(4	)
Energy - comparable EBIT^1,2	241		301


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


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

Comparable EBITDA for Energy decreased by $57 million for the three months ended March 31, 2016 compared to the same period in 2015 due to the net effect of:


•	lower earnings from U.S. Power mainly due to decreased margins on sales to wholesale, commercial and industrial customers, the impact of lower realized prices in both New England and New York and lower capacity prices in New York, partially offset by incremental earnings from the Ironwood power plant in Lebanon, Pennsylvania acquired February 1, 2016


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


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


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


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

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CANADIAN POWER

Western and Eastern Power



	three months ended March 31
(unaudited - millions of $)	2016		2015

Revenue¹
Western Power	75		108
Eastern Power	95		125
Other²	29		45
	199		278
Comparable income from equity investments³	—		5
Commodity purchases resold	(59	)	(90	)
Plant operating costs and other	(46	)	(70	)
Exclude risk management activities¹	13		22
Comparable EBITDA⁴	107		145
Depreciation and amortization	(46	)	(48	)
Comparable EBIT⁴	61		97

Breakdown of comparable EBITDA
Western Power⁴	4		15
Eastern Power	103		130
Comparable EBITDA⁴	107		145


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


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


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


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

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Sales volumes and plant availability

Includes our share of volumes from our equity investments.



	three months ended March 31
(unaudited)	2016		2015

Sales volumes (GWh)
Supply
Generation
Western Power	690		637
Eastern Power	757		1,323
Purchased
Sundance A & B and Sheerness PPAs¹	1,823		2,388
Other purchases	8		8
	3,278		4,356
Sales
Contracted
Western Power	1,420		1,645
Eastern Power	757		1,323
Spot
Western Power	1,101		1,388
	3,278		4,356
Plant availability²
Western Power³	99	%	97	%
Eastern Power^4,5	86	%	98	%


¹	Includes volumes from Sundance A and Sheerness PPAs and our 50 per cent ownership interest of Sundance B PPA 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 has been suspended since 2008.


⁵	Plant availability was lower in the three months ended March 31, 2016 than the same period in 2015 due to an unplanned outage at the Halton Hills facility.

Western Power

Comparable EBITDA for Western Power decreased by $11 million for the three months ended March 31, 2016 compared to the same period in 2015 due to lower realized power prices and PPA volumes following the termination of the PPAs.

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

The decrease in comparable equity earnings for the three months ended March 31, 2016 of $5 million compared to the same period in 2015 is primarily due to the impact of lower Alberta spot market prices on earnings from the ASTC Power Partnership. Comparable equity earnings do not include the impact of related contracting activities.

Average spot market power prices in Alberta decreased 38 per cent from $29/MWh to $18/MWh for the three months ended March 31, 2016 compared to the same period in 2015. The Alberta power market remained well supplied and few higher priced hours were observed in first quarter 2016. Warmer than normal temperatures prevailed leading to

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FIRST QUARTER 2016

low power and natural gas prices. 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.

Fifty-six per cent of Western Power sales volumes were sold under contract in first quarter 2016 compared to 54 per cent in first quarter 2015.

Depreciation and amortization decreased by $2 million following the termination of the PPAs.

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

Eastern Power

Comparable EBITDA for Eastern Power decreased by $27 million for the three months ended March 31, 2016 compared to the same period in 2015 mainly due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour.

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 March 31
(unaudited - millions of $, unless noted otherwise)	2016			2015

Income from equity investments¹	114			79

Comprised of:
Revenues	411			331
Operating expenses	(221		)	(172		)
Depreciation and other	(76		)	(80		)
	114			79
Bruce Power - Other information
Plant availability²	88		%	93		%
Planned outage days	76			39
Unplanned outage days	8			9
Sales volumes (GWh)¹	5,834			4,984
Realized sales price per MWh^3,4		$65			$64


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


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


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


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

Equity income from Bruce Power increased by $35 million for the three months ended March 31, 2016 compared to the same period in 2015. The increase was mainly due to higher gains from contracting activities, lower depreciation as a result of Bruce Power facility's operating life extension and our increased ownership interest, partially offset by higher planned outage days.

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FIRST QUARTER 2016

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, which includes certain flow-through items such as fuel and lease expenses recovery, for all units in January 2016. 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 $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, 2015 - December 31, 2015	$78.42
April 1, 2014 - March 31, 2015	$76.70


¹	Includes fuel expense recovery on flow-through basis estimated at $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, 2015 - December 31, 2015	$54.13
April 1, 2014 - March 31, 2015	$52.86

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.

In January 2016, planned outage work commenced on Unit 8 and was completed on April 25, 2016. In April 2016, a planned outage on Unit 2 commenced which will continue concurrently with the station containment outage that is expected to occur later in second quarter 2016. The station containment outage inspects and maintains key safety systems including containment structures and is required to be completed approximately once every decade. As part of this work program, Bruce Units 1 to 4 are expected to be removed from service for approximately one month. Additional planned maintenance is scheduled for fourth quarter 2016. The overall average plant availability percentage in 2016 is expected to be in the low 80s.

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FIRST QUARTER 2016

U.S. POWER



	three months ended March 31
(unaudited - millions of US$)	2016		2015

Revenue
Power¹	331		605
Capacity	62		67
	393		672
Commodity purchases resold	(305	)	(476	)
Plant operating costs and other²	(99	)	(118	)
Exclude risk management activities¹	87		54
Comparable EBITDA	76		132
Depreciation and amortization	(30	)	(27	)
Comparable EBIT	46		105


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


²	Includes the cost of fuel consumed in generation.

Sales volumes and plant availability



	three months ended March 31
(unaudited)	2016		2015

Physical sales volumes (GWh)
Supply
Generation¹	2,280		914
Purchased	4,748		4,425
	7,028		5,339

Plant availability^2,3	71	%	61	%


¹	Increase primarily due to Ironwood acquisition.


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


³	Plant availability was lower in the three months ended March 31, 2015 than 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 March 31
(unaudited)	2016	2015

Average Spot Power Prices (US$ per MWh)
New England¹	30	85
New York²	28	72
PJM³	21	n/a
Average New York² Spot Capacity Prices (US$ per KW-M)	5.83	8.34


¹	New England ISO all hours Mass Hub price.


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


³	The METED Zone price in Pennsylvania where the Ironwood plant operates. Average price for 2016 is from February 1 to March 31, 2016.

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FIRST QUARTER 2016

Comparable EBITDA for U.S. Power decreased US$56 million for the three months ended March 31, 2016 compared to the same period in 2015 primarily due to the net effect of:


•	lower margins on sales to wholesale, commercial and industrial customers in both the New England and PJM markets


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


•	lower capacity revenues at Ravenswood due to lower realized capacity prices in New York and the impact of lower availability at the facility, partially offset by insurance recoveries, net of deductibles


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

Wholesale electricity prices in New York and New England were significantly lower for the three months ended March 31, 2016 compared to the same period in 2015 primarily due to unseasonably warm weather in 2016. In New England and New York City, spot power prices for the three months ended March 31, 2016 were 65 and 61 per cent lower, respectively, compared to the same period in 2015. Both markets have also experienced lower natural gas commodity prices throughout 2016 compared to 2015.

Lower margins on sales to wholesale, commercial and industrial customers in both the PJM and New England markets resulted in significantly lower earnings for the three months ended March 31, 2016 compared to the same period in 2015. Although we have expanded our customer base in the PJM market, significantly lower realized power prices and mild weather have resulted in lower margins in our wholesale business.

Average New York Zone J spot capacity prices were approximately 30 per cent lower for the three months ended March 31, 2016 compared to the same period 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 increased available operational supply in New York City's Zone J market. The impact of lower capacity prices was partially offset by capacity revenues earned by our Ironwood power plant acquired in February 2016.

Capacity revenues were also negatively impacted by a unit outage from September 2014 to May 2015 at Ravenswood. The calculation used by the NYISO to determine the capacity volume for which a generator is compensated utilizes a rolling average forced outage rate. As a result of this methodology, outages impact capacity volumes and associated revenues on a lagged basis. Accordingly, capacity revenues for the three months ended March 31, 2016 were negatively impacted compared to the same period in 2015. The outage continues to be included in the rolling average forced outage rate. Insurance recoveries for this event were received and have been recognized in capacity revenues to offset amounts lost during the three months ended March 31, 2016. As a result of these insurance recoveries, the Unit 30 unplanned outage is not expected to have a significant impact on our earnings although the recording of earnings has not coincided with lost revenues due to timing of the insurance proceeds.

Physical generation volumes were higher for the three months ended March 31, 2016 compared to the same period in 2015 due to our acquisition of the Ironwood power plant and higher generation at our Ravenswood and Hydro facilities. Physical purchased volumes sold to wholesale, commercial and industrial customers were higher for the three months ended March 31, 2016 compared to the same period in 2015 as we have expanded our customer base in the PJM market.

As at March 31, 2016, approximately 6,100 GWh or 70 per cent of U.S. Power’s planned generation was contracted for the remainder of 2016 and 3,900 GWh or 39 per cent for 2017. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.

U.S. Power results for 2016 will be dependent on the timing of the previously announced monetization of the U.S. Northeast power assets. Nevertheless, operating results for the full year in 2016 are expected to be lower than our

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FIRST QUARTER 2016

Outlook in our 2015 Annual Report due to lower commodity prices experienced in the first quarter of 2016 and forecast for the remainder of the year.

NATURAL GAS STORAGE AND OTHER

Comparable EBITDA increased by $6 million for three months ended March 31, 2016 compared to the same period in 2015 mainly due to increased storage revenues as a result of higher realized natural gas storage price spreads.

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

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FIRST QUARTER 2016

Corporate

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



	three months ended March 31
(unaudited - millions of $)	2016		2015

Comparable EBITDA	(25	)	(24	)
Depreciation and amortization	(9	)	(7	)
Comparable EBIT	(34	)	(31	)
Specific item:
Acquisition costs - Columbia Pipeline Group	(26	)	—
Segmented losses	(60	)	(31	)

Corporate segmented losses in 2016 increased by $29 million compared to 2015 due to a charge of $26 million relating to costs associated with the acquisition of Columbia. This amount has been excluded from our calculation of comparable EBIT.

Interest Expense



	three months ended March 31
(unaudited - millions of $)	2016		2015

Comparable interest on long-term debt (including interest on junior subordinated notes)
Canadian-dollar denominated	(111	)	(109	)
U.S. dollar-denominated (US$)	(246	)	(218	)
Foreign exchange impact	(85	)	(48	)
	(442	)	(375	)
Other interest and amortization expense	(19	)	(13	)
Capitalized interest	41		70
Comparable interest expense	(420	)	(318	)
Specific items¹	—		—
Interest expense	(420	)	(318	)


¹	There were no specific items in the periods.

Comparable interest expense increased by $102 million for the three months ended March 31, 2016 compared to the same period in 2015 due to the net effect of:


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


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


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

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FIRST QUARTER 2016

Interest income and other



	three months ended March 31
(unaudited - millions of $)	2016	2015

Comparable interest income and other
AFUDC	101	58
Other	47	(43	)
	148	15
Specific item (pre-tax):
Risk management activities	53	(29	)
Interest income and other	201	(14	)

Comparable interest income and other increased by $133 million for the three months ended March 31, 2016 compared to the same period in 2015 as a net result of:


•	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


•	increased AFUDC related to our rate-regulated projects including Mexico pipelines, NGTL's expansion and Energy East.

Income tax expense



	three months ended March 31
(unaudited - millions of $)	2016		2015

Comparable income tax expense	(180	)	(247	)
Specific items:
Alberta PPA terminations	64		—
Keystone XL asset costs	4		—
TC Offshore loss on sale	1		—
Risk management activities	41		40
Income tax expense	(70	)	(207	)

Comparable income tax expense decreased by $67 million for the three months ended March 31, 2016 compared to the same period in 2015. The decrease was mainly the result of lower pre-tax earnings in 2016 compared to 2015, changes in the proportion of income earned between Canadian and foreign jurisdictions and by lower flow-through taxes in 2016 on Canadian regulated pipelines.

Net income attributable to non-controlling interests

Net income attributable to non-controlling interests increased by $21 million for the three months ended March 31, 2016 compared to the same period in 2015 primarily due to the sale of our 30 per cent direct interest in GTN in April 2015 and 49.9 per cent direct interest in PNGTS in January 2016 to TC PipeLines, LP and the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP.

Preferred share dividends

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FIRST QUARTER 2016

Recent developments

ACQUISITION OF COLUMBIA PIPELINE GROUP, INC.

Acquisition

On March 17, 2016, we entered into an agreement and plan of merger to acquire Columbia. Columbia owns one of the largest interstate natural gas pipeline systems in the U.S., providing transportation, storage and related services to a variety of customers in the northeast, mid-west, mid-Atlantic and Gulf Coast regions. Its assets include Columbia Gas Transmission, which operates approximately 18,000 km (11,300 miles) of pipelines and 620 Bcf in total operational capacity, with approximately 286 Bcf of working gas capacity in the Marcellus and Utica shale production areas, and Columbia Gulf Transmission, an approximate 5,400-km (3,300-mile) pipeline system that extends from Appalachia to the Gulf Coast.

Columbia stockholders will receive US$25.50 per share which represents an aggregate transaction value of approximately US$13 billion including the assumption of approximately US$2.8 billion of debt. We expect to finance the US$10.2 billion cash component of the acquisition through an offering of subscription receipts, which closed on April 1, 2016 for gross proceeds of approximately $4.4 billion, the planned monetization of our U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline business, and existing cash on hand. A syndicate of lenders have committed to provide debt bridge facilities in the amount of US$6.9 billion which will be utilized pending the realization of proceeds from the planned monetization of assets outlined above. We expect the acquisition, net of financing and the planned asset monetization, to be accretive to earnings per share in the first full year of ownership. We are targeting US$250 million of annual cost, revenue and financing benefits. See the Financial condition section for more information about the subscription receipts which will be automatically exchanged into common shares upon the closing of the acquisition.

We and Columbia each filed a Hart-Scott-Rodino Notification with the U.S. Federal Trade Commission on April 4, 2016. We also both submitted a filing with the Committee on Foreign Investment in the United States which was accepted on April 13, 2016. The special meeting for Columbia stockholders to approve the transaction is scheduled for June 22, 2016.

Two class action lawsuits seeking to enjoin the Columbia acquisition have been filed in the Delaware Court of Chancery by purported stockholders of Columbia on their own behalf and on behalf of all other stockholders of Columbia. The first, filed on March 30, 2016, names Columbia, the TransCanada entities that are parties to the merger agreement with Columbia, and each member of Columbia's Board of Directors. The second action was filed on April 7, 2016 against each member of Columbia's Board of Directors. We are not named as a defendant. Our view is that there is no merit to the allegations in these actions.

We expect the acquisition to close in second half 2016 subject to the shareholder and regulatory approvals outlined above.

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

We expect to partially finance the acquisition of Columbia through the monetization of our U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline business.

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FIRST QUARTER 2016

NATURAL GAS PIPELINES

Canadian Regulated Pipelines

NGTL System

In first quarter 2016, we placed approximately $100 million of facilities in service with another $600 million currently under construction. The NGTL System continues to develop approximately $7.3 billion of new supply and demand facilities. We have approximately $2.5 billion of facilities that have received regulatory approval and a further approximately $1.9 billion of facilities which are currently under regulatory review. Applications for approval to construct and operate an additional $2.9 billion of facilities have yet to be filed.

Included in our capital program described above is the recently announced 2018 expansion of a further $600 million of facilities required on the NGTL System. The 2018 expansion includes multiple projects totaling approximately 88 km (55 miles) of 20- to 48-inch diameter pipeline, one new compressor, approximately 35 new and expanded meter stations and other associated facilities. Applications to construct and operate the various components of the 2018 expansion program will be filed with the NEB in late 2016 and early 2017. Subject to regulatory approvals, construction is expected to start in 2017, with all facilities expected to be in service in 2018.

North Montney Mainline

On March 28, 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). A pre-construction CPCN condition requires that Petronas make a positive FID on the proposed Pacific Northwest LNG Project. Petronas is waiting on completion of the federal environmental assessment process for the LNG Project before it makes an FID. On March 18, 2016, the federal government extended the legislated time-line for that process by three months and is seeking additional information on the project. The requested extension of the NMML CPCN sunset clause ensures our regulatory approvals remain valid and do not expire pending an FID.

2016-2017 NGTL Revenue Requirement Settlement

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

U.S. Pipelines

Iroquois Gas Transmission System

On March 31, 2016, we closed the acquisition of an additional 4.87 per cent interest in Iroquois Gas Transmission System, L.P. (Iroquois) from one of our partners for US$54 million. Following this acquisition, our ownership interest in Iroquois increased to 49.35 per cent. We are also expecting to close an additional 0.65 per cent interest from another partner in second quarter 2016 that will increase our overall ownership interest to 50 per cent.

ANR Section 4 Rate Case

On January 29, 2016, ANR filed a Section 4 Rate Case with the FERC that requests an increase to ANR's maximum transportation rates. On February 29, 2016, the FERC issued an order that accepted and suspended ANR’s rate and tariff changes to become effective August 1, 2016, subject to refund and the outcome of a hearing. In addition, on March 23, 2016, the FERC established a procedural schedule for the hearing and appointed a settlement judge to assist the parties in their settlement negotiations. The hearing is currently scheduled for early February 2017 and settlement conferences will be held throughout the process.

TC Offshore

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

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FIRST QUARTER 2016

Mexico

Tula-Villa de Reyes Pipeline

On April 11, 2016, we announced we were awarded the contract to build, own and operate the Tula-Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 million cubic feet per day with the CFE. We expect to invest approximately US$550 million on 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.

LNG Pipeline Projects

Prince Rupert Gas Transmission

We are continuing engagement with Aboriginal groups and have now announced project agreements with eleven First Nation groups along the pipeline route which outline financial and other benefits and commitments that will be provided to each First Nation group for as long as the project is in service.

Coastal GasLink

The LNG Canada joint venture participants anticipate reaching a final investment decision on their Kitimat-based LNG project in late 2016. Based on the current schedule, preliminary construction work could begin in January 2017.

We continue to engage with all First Nations and stakeholders along the pipeline route. At the end of 2015, we had reached long-term project agreements with eleven of the twenty First Nations with claims to traditional and treaty territory traversed by the project. We continue to negotiate with the remaining First Nations and expect to execute additional project agreements in 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. Permanent repairs and remaining restoration work at site is planned for May 2016 with further investigative activities and corrective measures required by PHMSA planned in 2016.

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

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 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 National Energy Board 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. Whether the CQDE, as the other applicant to the litigation, will similarly seek

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to suspend the action is not known at this time. We do not anticipate this will result in a delay with regard to the NEB's review process.

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

On March 21, 2016, the NEB approved the Table of Contents for the consolidated application. Filing of the consolidated application is targeted for mid-May.

Liquids Marketing Business

The liquids marketing business began operations in 2016 to generate incremental revenues through the purchase and concurrent sale of crude oil. Derivative instruments are used to fix a portion of the variable price exposures that arise from physical liquids transactions. To settle purchase and sale activities, we will enter into contracts for pipeline and terminal capacity, including space on our assets.

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. 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 have 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 of ASTC Power Partnership which holds the Sundance B PPA.

Carbon tax

In February 2016, the Government of Ontario released enabling legislation and draft regulations for its proposed cap and trade program which would set an annual province-wide cap on greenhouse gas emissions beginning in 2017 and introduce a market to administer the purchase and trading of emissions allowances. The program would cover most emission sources in the province, including emissions from the electricity generation sector.

In parallel with this, the IESO has launched their own consultation process to determine what contractual amendments will be proposed to address the change in deemed operating costs for emitting generators and the resulting deemed energy margin derived from the market. We anticipate that the associated costs with the purchase of greenhouse gas emission allowances will be recovered from the IESO market and that our contracts with the IESO will be amended to preserve the economic value.

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Financial condition

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

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

CASH PROVIDED BY OPERATING ACTIVITIES



	three months ended March 31
(unaudited - millions of $)	2016		2015

Funds generated from operations¹	1,125		1,153
Increase in operating working capital	(80	)	(393	)
Net cash provided by operations	1,045		760


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

At March 31, 2016, our current assets were $4.1 billion and current liabilities were $7.1 billion, leaving us with a working capital deficit of $3.0 billion compared to $3.4 billion at December 31, 2015. This working capital deficiency is considered to be in the normal course of business and is managed through:


•	our ability to generate cash flow from operations


•	our access to capital markets


•	approximately $6.9 billion of unutilized, unsecured committed credit facilities.

COMPARABLE DISTRIBUTABLE CASH FLOW



	three months ended March 31
(unaudited - millions of $)	2016			2015

Net cash provided by operations	1,045			760
Increase in operating working capital	80			393
Funds generated from operations	1,125			1,153
Dividends on preferred shares	(23		)	(22		)
Distributions paid to non-controlling interests	(62		)	(54		)
Distributions received in excess of equity earnings	88			46
Maintenance capital expenditures including equity investments	(190		)	(167		)
Distributable cash flow	938			956
Specific items (net of tax):
Acquisition costs - Columbia Pipeline Group	26			—
Keystone XL asset costs	6			—
Comparable distributable cash flow	970			956
Comparable distributable cash flow per common share		$1.38			$1.35

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

Maintenance capital expenditures on our Canadian regulated natural gas pipelines were $55 million and $52 million in first quarter 2016 and 2015, respectively, which contributed to their respective rate bases and net income.

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CASH USED IN INVESTING ACTIVITIES



	three months ended March 31
(unaudited - millions of $)	2016		2015

Capital spending
Capital expenditures	(836	)	(806	)
Capital projects in development	(67	)	(163	)
	(903	)	(969	)
Contributions to equity investments	(170	)	(93	)
Acquisitions, net of cash acquired	(995	)	—
Proceeds from sale of assets, net of transaction costs	6		—
Distributions received in excess of equity earnings	88		46
Deferred amounts and other	—		179
Net cash used in investing activities	(1,974	)	(837	)

Capital expenditures in 2016 were primarily related to:


•	expansion of the NGTL System


•	construction of Mexico pipelines


•	expansion of the ANR pipeline


•	construction of the Northern Courier pipeline


•	expansion of the Canadian Mainline


•	construction of the Napanee power generating facility.

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

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

On February 1, 2016, we acquired the Ironwood natural gas fired, combined cycle power plant in Lebanon, Pennsylvania, with a capacity of 778 MW, for US$657 million in cash before post-acquisition adjustments.

On March 31, 2016, we acquired an additional 4.87 per cent interest in Iroquois Gas Transmission System LP (Iroquois) for an aggregate purchase price of US$54 million. As a result of this acquisition, our interest in Iroquois has increased to 49.35 per cent.

The increase in distributions received in excess of equity earnings is primarily due to distributions from Bruce Power.

CASH PROVIDED BY FINANCING ACTIVITIES



	three months ended March 31
(unaudited - millions of $)	2016		2015

Notes payable issued, net	1,176		279
Long-term debt issued, net of issue costs	1,992		2,277
Long-term debt repaid	(1,357	)	(1,016	)
Dividends and distributions paid	(450	)	(417	)
Common shares issued, net of issue costs	3		10
Common shares repurchased	(14	)	—
Preferred shares issued, net of issue costs	—		243
Partnership units of subsidiary issued, net of issue costs	24		4
Net cash provided by financing activities	1,374		1,380

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LONG-TERM DEBT ISSUED

(unaudited - millions of $)

Company

Issue date

Type

Maturity date

Amount

Interest rate

TRANSCANADA PIPELINES LIMITED

January 2016

Senior Unsecured Notes

January 2019

US $400

3.125

January 2016

Senior Unsecured Notes

January 2026

US $850

4.875

LONG-TERM DEBT RETIRED



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

TRANSCANADA PIPELINES LIMITED
	January 2016	Senior Unsecured Notes	US $750		0.75	%
NOVA GAS TRANSMISSION LTD.
	February 2016	Debentures		$225	12.2	%

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 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.

The following table provides the information related to shares repurchased in 2016 under the NCIB:



at April 28, 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 of repurchase		$13.7


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


²	Includes brokerage fees.

SUBSCRIPTION RECEIPTS

On April 1, 2016, we issued 96.6 million subscription receipts to partially fund the Columbia Pipeline Group acquisition at a price of $45.75 each for total proceeds of approximately $4.4 billion. Each subscription receipt entitles the holder to automatically receive one common share upon closing of the Columbia acquisition. While the subscription receipts remain outstanding, holders will be entitled to receive cash payments per subscription receipt that are equal to dividends declared on each common share, with the first payment on April 29, 2016 for holders of record at close of business on April 15, 2016. The second dividend equivalent payment will be made to holders of record at the close of business on June 30, 2016, provided that the acquisition has not closed or the Merger Agreement with Columbia has not been terminated. If the Merger Agreement is terminated after the common share dividend declaration date of April 29, 2016 but before the common share dividend record date of June 30, 2016, subscription receipt holders of record on the termination date shall receive a pro-rata payment of the dividend as the dividend equivalent payment. If the Merger Agreement has not closed by March 17, 2017, we will be required to make a termination payment equal to the aggregate issue price plus any unpaid dividend equivalent payments owing to the holders.

The gross proceeds from the sale of the subscription receipts, less any amounts used for dividend equivalent payments, will be held in escrow until the acquisition close date and will be recorded as restricted cash.

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PREFERRED SHARE ISSUANCE AND CONVERSION

On February 1, 2016, holders of 1.3 million Series 5 cumulative redeemable first preferred shares exercised their option to convert to Series 6 cumulative redeemable first preferred shares and receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 1.54 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 5 preferred shares was reset for five years at 2.263 per cent per annum. Such rate will reset every five years.

On April 20, 2016, we completed a public offering of 20 million Series 13 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $500 million. The Series 13 preferred shareholders will have the right to convert their Series 13 preferred shares into Series 14 cumulative redeemable first preferred shares on May 31, 2021 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 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 five years at 5.5 per cent per annum. The dividend rate will reset every five years at a rate equal to the sum of the applicable five-year Government of Canada bond yield plus 4.69 per cent but not less than 5.5 per cent per annum.

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

(unaudited)

Number of
shares
issued and
outstanding (thousands)

Current yield¹

Annual dividend per share¹

Redemption price per share²

Redemption and conversion option date^1,2

Right to convert into

Cumulative first preferred shares

Series 5

12,714

2.263

$0.56575

$25.00

January 30, 2021

Series 6

1,286

Floating³

Floating

$25.00

January 30, 2021

Series 5

Series 13

20,000

5.5

$1.375

$25.00

May 31, 2021

Series 14


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

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


³	Commencing March 31, 2016, the floating quarterly dividend rate for the Series 6 preferred shares is 2.002 per cent and will reset every quarter going forward.

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

Since January 1, 2016, 0.8 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$39 million. Our ownership interest in TC PipeLines, LP decreased as a result of issuances under the ATM program.

DIVIDENDS

On April 28, 2016, we declared quarterly dividends as follows:



Quarterly dividend on our common shares

$0.565 per share
Payable on July 29, 2016 to shareholders of record at the close of business on June 30, 2016

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Quarterly dividend equivalent payment on our subscription receipts¹

$0.565 per subscription receipt
Payable on April 29, 2016 to holders of record at the close of business on April 15, 2016
Payable on July 29, 2016 to holders of record at the close of business on June 30, 2016²


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


²	If the Merger Agreement with Columbia is terminated after the common share dividend declaration date of April 29, 2016 but before the common share dividend record date of June 30, 2016, subscription receipt holders of record on the termination date shall receive a pro-rata payment of the dividend as the dividend equivalent payment.



Quarterly dividends on our preferred shares

Series 1	$0.204125
Series 2	$0.14806148
Series 3	$0.1345
Series 4	$0.10828005
Payable on June 30, 2016 to shareholders of record at the close of business on May 31, 2016
Series 5	$0.14143750
Series 6	$0.12444126
Series 7	$0.25
Series 9	$0.265625
Payable on August 2, 2016 to shareholders of record at the close of business on June 30, 2016
Series 11	$0.2375
Series 13	$0.154
Payable on May 31, 2016 to shareholders of record at the close of business on May 12, 2016

SHARE INFORMATION



as at April 25, 2016

Common shares	Issued and outstanding
	702 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
	12 million	7 million

Subscription receipts	Outstanding	Convertible to
	96.6 million	96.6 million common shares

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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 as well as providing additional liquidity including the acquisition of Columbia Pipelines.

At April 28, 2016, we had approximately $17.6 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	US$5.2 billion	TCPL	Committed, syndicated, senior unsecured asset sale bridge term loan commitment that supports the acquisition of Columbia¹	24 months from acquisition closing date
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	US$1.7 billion	TCPL USA	Committed, syndicated, senior unsecured asset sale bridge term loan commitment that supports the acquisition of Columbia¹	24 months from acquisition closing date
US$0.5 billion	US$0.5 billion	TCPL USA	Committed, syndicated, revolving, extendible TCPL USA credit facility that is used for TCPL USA general corporate purposes	December 2016
US$1.5 billion	US$1.5 billion	TAIL/TCPM	Committed, syndicated, revolving, extendible credit facility that supports the joint TAIL/TCPM commercial paper program in the U.S.	December 2016
$1.7 billion	$0.6 billion	TCPL/TCPL USA	Supports the issuance of letters of credit and provides additional liquidity	Demand


¹	Proceeds from asset sales must be used to repay these facilities. See Recent developments section for more information.

At April 28, 2016, our operated affiliates had an additional $0.7 billion of undrawn capacity on committed credit facilities.

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

CONTRACTUAL OBLIGATIONS

In addition to our commitment to acquire Columbia, our capital commitments increased by approximately $0.2 billion since December 31, 2015 as a result of the new commitments for the Tuxpan-Tula natural gas pipeline 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. There were no other material changes to our contractual obligations in first 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.

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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 its 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 and making sure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.

COUNTERPARTY CREDIT RISK

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


•	accounts receivable


•	portfolio investments


•	the fair value of derivative assets


•	cash and notes receivable.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At March 31, 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$147 million) at March 31, 2016 with one counterparty (December 31, 2015 - $248 million (US$179 million)). This amount is secured by a guarantee from the counterparty's parent company and is expected to be fully collectible.

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

FOREIGN EXCHANGE AND INTEREST RATE RISK

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

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

Average exchange rate - U.S. to Canadian dollars



three months ended March 31, 2016	1.35
three months ended March 31, 2015	1.24

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

Significant U.S. dollar-denominated amounts



	three months ended March 31
(unaudited - millions of US$)	2016		2015

U.S. and International Natural Gas Pipelines comparable EBIT	243		239
U.S. Liquids Pipelines comparable EBIT	130		147
U.S. Power comparable EBIT	46		105
Interest on U.S. dollar-denominated long-term debt	(246	)	(218	)
Capitalized interest on U.S. dollar-denominated capital expenditures	7		31
U.S. non-controlling interests	(60	)	(48	)
	120		256

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:



	March 31, 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	(573	)	US 2,900	(730	)	US 3,150
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	(58	)	US 700	50		US 1,800
	(631	)	US 3,600	(680	)	US 4,950


¹	Fair values equal carrying values.


²	In the three months ended March 31, 2016, net realized gains of $2 million (2015 - gains of $3 million) 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)	March 31, 2016	December 31, 2015

Notional amount	19,100 (US 14,700)	23,100 (US 16,700)
Fair value	20,100 (US 15,500)	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

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accounting treatment. The effective portion of the change in the fair value of hedging derivatives for cash flow hedges and hedges of our net investment in foreign operations are recorded in OCI in the period of change. Any ineffective portion is recognized in net income in the same financial category as the underlying transaction. The change in the fair value of derivative instruments that have been designated as fair value hedges are recorded in net income in interest income and other and interest expense.

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

Balance sheet presentation of derivative instruments

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



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

Other current assets	556		442
Intangible and other assets	216		168
Accounts payable and other	(1,081	)	(926	)
Other long-term liabilities	(625	)	(625	)
	(934	)	(941	)

Unrealized and realized (losses)/gains of derivative instruments

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



	three months ended March 31
(unaudited - millions of $, pre-tax)	2016		2015

Derivative instruments held for trading^1,2
Amount of unrealized (losses)/gains in the period
Commodities	(67	)	(26	)
Foreign exchange	27		(29	)
Amount of realized (losses)/gains in the period
Commodities	(95	)	1
Foreign exchange	44		(43	)
Derivative instruments in hedging relationships
Amount of realized (losses)/gains in the period
Commodities	(73	)	16
Foreign exchange	(63	)	—
Interest rate	2		2


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 assets, a loss of $49 million and a gain of $7 million (2015 - nil) were recorded in net income 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 is as follows:



	three months ended March 31
(unaudited - millions of $, pre-tax)	2016		2015

Change in fair value of derivative instruments recognized in OCI (effective portion)¹
Commodities	(16	)	21
Foreign exchange	(35	)	—
Interest rate	(1	)	—
	(52	)	21
Reclassification of gains on derivative instruments from AOCI to net income (effective portion)¹
Commodities²	82		69
Foreign exchange³	34		—
Interest rate⁴	4		4
	120		73
Losses on derivative instruments recognized in net income (ineffective portion)
Commodities²	(58	)	(63	)
	(58	)	(63	)


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 March 31, 2016, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $42 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 March 31, 2016, we would have been required to provide additional collateral of $42 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 March 31, 2016, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

There were no changes in first quarter 2016 that had or are likely to have a material impact on our internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES

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

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

Changes in accounting policies for 2016

Extraordinary and unusual income statement items

In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from 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 13, Variable interest entities.

Imputation of interest

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

Business Combinations

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

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

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance is effective January 1, 2017 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.

Financial Instruments

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

Leases

In February 2016, the FASB issued new guidance on leases. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees will 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 evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

Derivatives and Hedging

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

Equity Method Investments

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

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Reconciliation of non-GAAP measures



	three months ended March 31
(unaudited - millions of $, except per share amounts)	2016		2015

EBITDA	1,097		1,442
Alberta PPA terminations	240		—
Acquisition costs - Columbia Pipeline Group	26		—
Keystone XL asset costs	10		—
TC Offshore loss on sale	4		—
Risk management activities¹	125		89
Comparable EBITDA	1,502		1,531
Depreciation and amortization	(454	)	(434	)
Comparable EBIT	1,048		1,097
Other income statement items
Comparable interest expense	(420	)	(318	)
Comparable interest income and other	148		15
Comparable income tax expense	(180	)	(247	)
Net income attributable to non-controlling interests	(80	)	(59	)
Preferred share dividends	(22	)	(23	)
Comparable earnings	494		465
Specific items (net of tax):
Alberta PPA terminations	(176	)	—
Acquisition costs - Columbia Pipeline Group	(26	)	—
Keystone XL asset costs	(6	)	—
TC Offshore loss on sale	(3	)	—
Risk management activities¹	(31	)	(78	)
Net income attributable to common shares	252		387

Comparable interest income and other	148		15
Specific items:
Risk management activities¹	53		(29	)
Interest income and other expense	201		(14	)

Comparable income tax expense	(180	)	(247	)
Specific items:
Alberta PPA terminations	64		—
Keystone XL asset costs	4		—
TC Offshore loss on sale	1		—
Risk management activities¹	41		40
Income tax expense	(70	)	(207	)

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	three months ended March 31
(unaudited - millions of $, except per share amounts)	2016			2015

Comparable earnings per common share		$0.70			$0.66
Specific items (net of tax):
Alberta PPA terminations	(0.25		)	—
Acquisition costs - Columbia Pipeline Group	(0.04		)	—
Keystone XL asset costs	(0.01		)	—
TC Offshore loss on sale	—			—
Risk management activities	(0.04		)	(0.11		)
Net income per common share		$0.36			$0.55



¹	Risk management activities	three months ended March 31
	(unaudited - millions of $)	2016		2015

	Canadian Power	(13	)	(22	)
	U.S. Power	(115	)	(68	)
	Liquids	(2	)	—
	Natural Gas Storage	5		1
	Foreign exchange	53		(29	)
	Income tax attributable to risk management activities	41		40
	Total losses from risk management activities	(31	)	(78	)

Comparable EBITDA and EBIT by business segment



three months ended March 31, 2016	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total

EBITDA	894		288		(34	)	(51	)	1,097
Alberta PPA terminations	—		—		240		—		240
Acquisition costs - Columbia Pipeline Group	—		—		—		26		26
Keystone XL asset costs	—		10		—		—		10
TC Offshore loss on sale	4		—		—		—		4
Risk management activities	—		2		123		—		125
Comparable EBITDA	898		300		329		(25	)	1,502
Depreciation and amortization	(287	)	(70	)	(88	)	(9	)	(454	)
Comparable EBIT	611		230		241		(34	)	1,048



three months ended March 31, 2015	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total

EBITDA	864		305		297		(24	)	1,442
Risk management activities	—		—		89		—		89
Comparable EBITDA	864		305		386		(24	)	1,531
Depreciation and amortization	(279	)	(63	)	(85	)	(7	)	(434	)
Comparable EBIT	585		242		301		(31	)	1,097

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Quarterly results

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA



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

Revenues	2,547		2,851			2,944		2,631		2,874		2,616		2,451		2,234
Net income attributable to common shares	252		(2,458		)	402		429		387		458		457		416
Comparable earnings	494		453			440		397		465		511		450		332
Share statistics
Net income per common share - basic and diluted		$0.36		($3.47	)		$0.57		$0.60		$0.55		$0.65		$0.64		$0.59
Comparable earnings per share		$0.70		$0.64			$0.62		$0.56		$0.66		$0.72		$0.63		$0.47
Dividends declared per common share		$0.565		$0.52			$0.52		$0.52		$0.52		$0.48		$0.48		$0.48

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT

Quarter-over-quarter revenues and net income sometimes fluctuate, the causes of which vary across our business segments.

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


•	regulatory decisions


•	negotiated settlements with shippers


•	acquisitions and divestitures


•	developments outside of the normal course of operations


•	newly constructed assets being placed in service.

In Liquids Pipelines, revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income are also affected by:


•	developments outside of the normal course of operations


•	newly constructed assets being placed in service


•	regulatory decisions.

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


•	weather


•	customer demand


•	market prices for natural gas and power


•	capacity prices and payments


•	planned and unplanned plant outages


•	acquisitions and divestitures


•	certain fair value adjustments


•	developments outside of the normal course of operations


•	newly constructed assets being placed in service.

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FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER

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

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

In 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 relating 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 relating to an impairment in value of turbine equipment held for future use in our Energy business


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


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

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

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

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

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