TRP-03.31.2015-MD&A

EX-13.1 2 trp-03312015xmda.htm MANAGEMENT'S DISCUSSION AND ANALYSIS TRP-03.31.2015-MD&A

EXHIBIT 13.1

Quarterly report to shareholders

First quarter 2015

Financial highlights



	three months ended March 31
(unaudited - millions of $, except per share amounts)	2015			2014

Income
Revenue	2,874			2,884
Net income attributable to common shares	387			412
per common share - basic and diluted		$0.55			$0.58
Comparable EBITDA¹	1,531			1,396
Comparable earnings¹	465			422
per common share¹		$0.66			$0.60

Operating cash flow
Funds generated from operations¹	1,153			1,102
Increase in operating working capital	(393		)	(123		)
Net cash provided by operations	760			979
Investing activities
Capital expenditures	806			744
Capital projects under development	201			104
Equity investments	93			89
Dividends paid
Per common share		$0.52			$0.48
Basic common shares outstanding (millions)
Average for the period	709			708
End of period	709			708


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

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FIRST QUARTER 2015

Management’s discussion and analysis

April 30, 2015

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, 2015, and should be read with the accompanying unaudited condensed consolidated financial statements for the three months ended March 31, 2015 which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2014 audited consolidated financial statements and notes and the MD&A in our 2014 Annual Report, which have been prepared in accordance with U.S. GAAP.

About this document

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

Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2014 Annual Report.

All information is as of April 30, 2015 and all amounts are in Canadian dollars, unless noted otherwise.

FORWARD-LOOKING INFORMATION

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

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

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


•	anticipated business prospects


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


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


•	expected cash flows and future financing options available to us


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


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


•	expected regulatory processes and outcomes


•	expected impact of regulatory outcomes


•	expected outcomes with respect to legal proceedings, including arbitration 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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FIRST QUARTER 2015

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

Assumptions


•	inflation rates, commodity prices and capacity prices


•	timing of financings and hedging


•	regulatory decisions and outcomes


•	foreign exchange rates


•	interest rates


•	tax rates


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


•	integrity and reliability of our assets


•	access to capital markets


•	anticipated construction costs, schedules and completion dates


•	acquisitions and divestitures.

Risks and uncertainties


•	our ability to successfully implement our strategic initiatives


•	whether our strategic initiatives will yield the expected benefits


•	the operating performance of our pipeline and energy assets


•	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 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 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 2014 Annual Report.

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

FOR MORE INFORMATION

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

NON-GAAP MEASURES

We use the following non-GAAP measures:


•	EBITDA


•	EBIT


•	funds generated from operations


•	comparable earnings


•	comparable earnings per common share


•	comparable EBITDA

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FIRST QUARTER 2015


•	comparable EBIT


•	comparable depreciation and amortization


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

EBITDA and EBIT

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

Funds generated from operations

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

Comparable measures

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


•	gains or losses on sales of assets


•	legal, contractual and bankruptcy settlements


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


•	write-downs of assets and investments.

We calculate comparable earnings by excluding the unrealized gains and losses from changes in the fair value of 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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FIRST QUARTER 2015

Consolidated results - first quarter 2015



	three months ended March 31
(unaudited - millions of $, except per share amounts)	2015		2014

Natural Gas Pipelines	595		586
Liquids Pipelines	246		192
Energy	214		257
Corporate	(47	)	(43	)
Total segmented earnings	1,008		992
Interest expense	(318	)	(274	)
Interest income and other expense	(14	)	(8	)
Income before income taxes	676		710
Income tax expense	(207	)	(221	)
Net income	469		489
Net income attributable to non-controlling interests	(59	)	(54	)
Net income attributable to controlling interests	410		435
Preferred share dividends	(23	)	(23	)
Net income attributable to common shares	387		412

Net income per common share - basic and diluted	$0.55		$0.58

Net income attributable to common shares decreased by $25 million for the three months ended March 31, 2015 compared to the same period in 2014. Net income in both periods included unrealized gains and losses from changes in risk management activities and we exclude these unrealized gains and losses to arrive at comparable earnings. For the three months ended March 31, 2015, comparable earnings increased by $43 million compared to the same period in 2014, as discussed below in the reconciliation of net income to comparable earnings.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS



	three months ended March 31
(unaudited - millions of $, except per share amounts)	2015	2014

Net income attributable to common shares	387	412
Specific items (net of tax):
Risk management activities¹	78	10
Comparable earnings	465	422

Net income per common share	$0.55	$0.58
Specific items (net of tax):
Risk management activities¹	0.11	0.02
Comparable earnings per share	$0.66	$0.60



1	Risk management activities	three months ended March 31
	(unaudited - millions of $)	2015		2014

	Canadian Power	(22	)	—
	U.S. Power	(68	)	(2	)
	Natural Gas Storage	1		(9	)
	Foreign exchange	(29	)	(2	)
	Income tax attributable to risk management activities	40		3
	Total losses from risk management activities	(78	)	(10	)

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FIRST QUARTER 2015

Comparable earnings increased by $43 million for the three months ended March 31, 2015 compared to the same period in 2014. This was primarily the net effect of:


•	incremental earnings from the Gulf Coast extension which was placed in service in January 2014 and higher volumes on the Keystone Pipeline System


•	higher earnings from U.S. Power mainly due to timing of earnings recognized on certain contracts in our power marketing business


•	higher earnings from the Tamazunchale Extension which was placed in service in 2014


•	higher earnings from Eastern Power due to the sale of unused natural gas transportation, higher contractual earnings at Bécancour and incremental earnings from Ontario solar facilities acquired in 2014


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


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


•	higher interest expense from debt issuances, higher foreign exchange on interest related to U.S. dollar-denominated debt and lower capitalized interest on projects placed in service.

The stronger U.S. dollar this quarter compared to the same period in 2014 positively impacted the translated results in our U.S. businesses, however, this impact was mostly offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our net exposure through our hedging program.

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FIRST QUARTER 2015

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 is comprised of $12 billion of small to medium-sized, shorter-term projects and $34 billion of commercially secured large-scale, medium and longer-term projects. Amounts presented exclude the impact of foreign exchange and capitalized interest.

Estimated project costs are based on the last announced project estimates and are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.



at March 31, 2015	Segment	Expected in-service date	Estimated project cost	Amount spent
(unaudited - billions of $)	Segment	Expected in-service date	Estimated project cost	Amount spent

Small to medium sized, shorter-term
Houston Lateral and Terminal	Liquids Pipelines	2015	US 0.6	US 0.4
Topolobampo	Natural Gas Pipelines	2016	US 1.0	US 0.7
Mazatlan	Natural Gas Pipelines	2016	US 0.4	US 0.2
Grand Rapids¹	Liquids Pipelines	2016-2017	1.5	0.3
Heartland and TC Terminals	Liquids Pipelines	2017	0.9	0.1
Northern Courier	Liquids Pipelines	2017	1.0	0.3
Canadian Mainline - Other	Natural Gas Pipelines	2015-2016	0.4	—
NGTL System - North Montney	Natural Gas Pipelines	2016-2017	1.7	0.1
- 2016/17 Facilities	Natural Gas Pipelines	2016-2018	2.7	0.1
- Other	Natural Gas Pipelines	2015-2016	0.4	—
Napanee	Energy	2017 or 2018	1.0	0.1
			11.6	2.3
Large-scale, medium and longer-term
Upland	Liquids Pipelines	2020	US 0.6	—
Keystone projects
Keystone XL²	Liquids Pipelines	³	US 8.0	US 2.4
Keystone Hardisty Terminal	Liquids Pipelines	³	0.3	0.2
Energy East projects
Energy East⁴	Liquids Pipelines	2020	12.0	0.6
Eastern Mainline	Natural Gas Pipelines	2017	1.5	—
BC west coast LNG-related projects
Coastal GasLink	Natural Gas Pipelines	2019+	4.8	0.3
Prince Rupert Gas Transmission	Natural Gas Pipelines	2019+	5.0	0.3
NGTL System - Merrick	Natural Gas Pipelines	2020	1.9	—
			34.1	3.8
			45.7	6.1


1	Represents our 50 per cent share.


2	Estimated project cost dependent on the timing of the Presidential permit.


3	Approximately two years from the date the Keystone XL permit is received.


4	Excludes transfer of Canadian Mainline natural gas assets.

Outlook

The earnings outlook for 2015 is expected to be consistent with what was previously included in the 2014 Annual Report. See the MD&A in our 2014 Annual Report for further information about our outlook.

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FIRST QUARTER 2015

Natural Gas Pipelines

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



	three months ended March 31
(unaudited - millions of $)	2015		2014

Comparable EBITDA	874		848
Comparable depreciation and amortization¹	(279	)	(262	)
Comparable EBIT	595		586
Specific items²	—		—
Segmented earnings	595		586


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


2	There were no specific items in either of these periods.

Natural Gas Pipelines segmented earnings increased by $9 million for the three months ended March 31, 2015 compared to the same period in 2014 and are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.



	three months ended March 31
(unaudited - millions of $)	2015		2014

Canadian Pipelines
Canadian Mainline	266		315
NGTL System	222		219
Foothills	27		27
Other Canadian pipelines¹	7		5
Canadian Pipelines - comparable EBITDA	522		566
Comparable depreciation and amortization	(209	)	(203	)
Canadian Pipelines - comparable EBIT	313		363

U.S. and International Pipelines (US$)
ANR	88		78
TC PipeLines, LP^1,2	26		26
Great Lakes³	20		19
Other U.S. pipelines (Bison⁴, Iroquois¹,GTN⁵, Portland⁶)	41		45
Mexico (Guadalajara, Tamazunchale)	47		25
International and other^1,7	2		(1	)
Non-controlling interests⁸	74		73
U.S. and International Pipelines - comparable EBITDA	298		265
Comparable depreciation and amortization	(57	)	(54	)
U.S. and International Pipelines - comparable EBIT	241		211
Foreign exchange impact	59		21
U.S. and International Pipelines - comparable EBIT(Cdn$)	300		232
Business Development comparable EBITDA and EBIT	(18	)	(9	)
Natural Gas Pipelines - comparable EBIT	595		586


1	Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments. In November 2014, we sold our interest in Gas Pacifico/INNERGY.

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FIRST QUARTER 2015

Beginning in August 2014, TC PipeLines, LP began its at-the-market equity issuance program which, when utilized, will decrease our ownership interest in TC PipeLines, LP going forward. On October 1, 2014, we sold our remaining 30 per cent interest in Bison to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of GTN, Bison and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented. On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TC PipeLines, LP.



	Ownership percentage as of
	October 1, 2014	January 1, 2014

TC PipeLines, LP	28.3	28.9
Effective ownership through TC PipeLines, LP:
Bison	28.3	20.2
GTN	19.8	20.2
Great Lakes	13.1	13.4


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


4	Effective October 1, 2014, we have no direct ownership in Bison. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.


5	Effective July 1, 2013, represents our 30 per cent direct ownership interest in GTN. On April 1, 2015, we sold our remaining direct interest in GTN to TC PipeLines, LP.


6	Represents our 61.7 per cent ownership interest.


7	Includes our share of the equity income from Gas Pacifico/INNERGY and TransGas as well as general and administration costs relating to our U.S. and International Pipelines. In November 2014, we sold our interest in Gas Pacifico/INNERGY.


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

CANADIAN PIPELINES

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

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES



	three months ended March 31
(unaudited - millions of $)	2015	2014

Canadian Mainline	47	66
NGTL System	64	63
Foothills	4	4

Net income for the Canadian Mainline decreased by $19 million for the three months ended March 31, 2015 compared to the same period in 2014. In 2015, the Canadian Mainline began operating under the 2015 - 2030 Tolls and Tariff Application approved by the NEB in November 2014. The decrease in net income was due to a lower ROE of 10.10 per cent in 2015 compared to 11.50 per cent in 2014 on deemed common equity of 40 per cent as well as lower incentive earnings and a lower average investment base in 2015.

Net income for the NGTL System increased by $1 million for the three months ended March 31, 2015 compared to the same period in 2014 mainly due to a higher average investment base.

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 increased by US$33 million for the three months ended March 31, 2015 compared to the same period in 2014. This was the net effect of:


•	higher earnings from the Tamazunchale Extension which was placed in service in 2014


•	ANR's settlement with a producer for damages to ANR's pipeline, partially offset by lower storage revenue from ANR.

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FIRST QUARTER 2015

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

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $17 million for the three months ended March 31, 2015 compared to the same period in 2014 mainly because of depreciation for the Tamazunchale Extension, a higher investment base on the NGTL System and the effect of a stronger U.S. dollar.

BUSINESS DEVELOPMENT

Business development expenses were higher by $9 million for the three months ended March 31, 2015 compared to the same period in 2014 mainly due to increased business development activity.

OPERATING STATISTICS - WHOLLY OWNED PIPELINES



three months ended March 31	Canadian Mainline¹		NGTL System²		ANR³
(unaudited)	2015	2014	2015	2014	2015	2014

Average investment base (millions of $)	5,018	5,706	6,419	6,137	n/a	n/a
Delivery volumes (Bcf)
Total	529	528	1,058	1,131	509	525
Average per day	5.9	5.9	11.8	12.6	5.7	5.8


1	Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2015 were 302 Bcf (2014 – 357 Bcf). Average per day was 3.4 Bcf (2014 – 4.0 Bcf).


2	Field receipt volumes for the NGTL System for the three months ended March 31, 2015 were 1,009 Bcf (2014 – 933 Bcf). Average per day was 11.2 Bcf (2014 – 10.4 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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Liquids Pipelines

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



	three months ended March 31
(unaudited - millions of $)	2015		2014

Comparable EBITDA	309		241
Comparable depreciation and amortization¹	(63	)	(49	)
Comparable EBIT	246		192
Specific items²	—		—
Segmented earnings	246		192


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


2	There were no specific items in either of these periods.

Liquids Pipelines segmented earnings increased by $54 million for the three months ended March 31, 2015 compared to the same period in 2014 and are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below.



	three months ended March 31
(unaudited - millions of $)	2015		2014

Keystone Pipeline System	314		248
Liquids Pipelines Business Development	(5	)	(7	)
Liquids Pipelines - comparable EBITDA	309		241
Comparable depreciation and amortization	(63	)	(49	)
Liquids Pipelines - comparable EBIT	246		192

Comparable EBIT denominated as follows:
Canadian dollars	61		49
U.S. dollars	149		129
Foreign exchange impact	36		14
	246		192

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 increased by $66 million for the three months ended March 31, 2015 compared to the same period in 2014. This increase was primarily due to:


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


•	higher volumes


•	a stronger U.S. dollar and its positive effect on the foreign exchange impact.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $14 million for the three months ended March 31, 2015 compared to the same period in 2014 due to the Gulf Coast extension being placed in service and the effect of a stronger U.S. dollar.

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FIRST QUARTER 2015

Energy

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



	three months ended March 31
(unaudited - millions of $)	2015		2014

Comparable EBITDA	388		345
Comparable depreciation and amortization¹	(85	)	(77	)
Comparable EBIT	303		268
Specific items (pre-tax):
Risk management activities	(89	)	(11	)
Segmented earnings	214		257


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

Energy segmented earnings decreased by $43 million for the three months ended March 31, 2015 compared to the same period in 2014 and included the following unrealized gains and losses from changes in the fair value of derivatives:



Risk management activities	three months ended March 31
(unaudited - millions of $, pre-tax)	2015		2014

Canadian Power	(22	)	—
U.S. Power	(68	)	(2	)
Natural Gas Storage	1		(9	)
Total losses from risk management activities	(89	)	(11	)

The period over period 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 particular 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.

A significant portion of the unrealized risk management activity losses in U.S. Power for first quarter 2015 are due to the timing of recognizing certain earnings from our power marketing business. The majority of these unrealized losses will be realized in second quarter 2015. Please see the U.S. Power section of this MD&A for further discussion on these timing differences.

Canadian Power losses from risk management activities are a result of declining Alberta power prices, as discussed in the Western Power section.

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FIRST QUARTER 2015

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



	three months ended March 31
(unaudited - millions of $)	2015		2014

Canadian Power
Western Power	15		72
Eastern Power¹	131		93
Bruce Power	79		64
Canadian Power - comparable EBITDA²	225		229
Comparable depreciation and amortization	(48	)	(44	)
Canadian Power - comparable EBIT²	177		185
U.S. Power (US$)
U.S. Power - comparable EBITDA	133		86
Comparable depreciation and amortization	(27	)	(27	)
U.S. Power - comparable EBIT	106		59
Foreign exchange impact	24		5
U.S. Power - comparable EBIT (Cdn$)	130		64

Natural Gas Storage and other - comparable EBITDA	3		27
Comparable depreciation and amortization	(3	)	(3	)
Natural Gas Storage and other - comparable EBIT	—		24
Business Development comparable EBITDA and EBIT	(4	)	(5	)
Energy - comparable EBIT²	303		268


1	Includes three solar facilities acquired in September 2014 and one solar facility acquired in December 2014.


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

Comparable EBITDA for Energy increased by $43 million for the three months ended March 31, 2015 compared to the same period in 2014 due to the net effect of:


•	higher earnings from U.S. Power mainly due to the timing of earnings recognized on certain contracts in our power marketing business, reflecting the different pricing profiles between the power prices we charge our customers and the prices we pay for volumes purchased


•	higher earnings from Eastern Power due to the sale of unused natural gas transportation, higher contractual earnings at Bécancour and incremental earnings from Ontario solar facilities acquired in 2014


•	higher earnings from Bruce Power from higher volumes as a result of fewer outage days


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


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


•	a stronger U.S. dollar and its positive effect on the foreign exchange impact.

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FIRST QUARTER 2015

CANADIAN POWER

Western and Eastern Power



	three months ended March 31
(unaudited - millions of $)	2015		2014

Revenue¹
Western Power	108		181
Eastern Power²	125		142
Other³	45		51
	278		374
Income from equity investments⁴	5		20
Commodity purchases resold	(90	)	(101	)
Plant operating costs and other	(69	)	(128	)
Exclude risk management activities¹	22		—
Comparable EBITDA	146		165
Comparable depreciation and amortization	(48	)	(44	)
Comparable EBIT	98		121

Breakdown of comparable EBITDA
Western Power	15		72
Eastern Power	131		93
Comparable EBITDA	146		165


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 three solar facilities acquired in September 2014 and one solar facility acquired in December 2014.


3	Includes revenues from the sale of unused natural gas transportation, sale of excess natural gas purchased for generation and Cancarb sales of thermal carbon black up to April 15, 2014 when it was sold.


4	Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy. Equity income does not include any earnings related to our risk management activities.

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Sales volumes and plant availability

Includes our share of volumes from our equity investments.



	three months ended March 31
(unaudited)	2015		2014

Sales volumes (GWh)
Supply
Generation
Western Power	637		609
Eastern Power¹	1,323		1,277
Purchased
Sundance A & B and Sheerness PPAs²	2,388		2,800
Other purchases	8		5
	4,356		4,691
Sales
Contracted
Western Power	1,645		2,461
Eastern Power¹	1,323		1,277
Spot
Western Power	1,388		953
	4,356		4,691
Plant availability³
Western Power⁴	97	%	96	%
Eastern Power^1,5	98	%	98	%


1	Includes three solar facilities acquired in September 2014 and one solar facility acquired in December 2014.


2	Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership.


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


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


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

Western Power

Comparable EBITDA for Western Power decreased by $57 million for the three months ended March 31, 2015 compared to the same period in 2014 due to lower realized power prices and the sale of Cancarb in April 2014.

Average spot market power prices in Alberta decreased by 53 per cent from $62/MWh to $29/MWh for the three months ended March 31, 2015 compared to the same period in 2014. The Alberta power market remained well supplied in first quarter 2015, with strong thermal fleet availability, robust wind output and new capacity from a large gas-fired power plant that entered commercial service in March 2015. Mild winter weather conditions also contributed to the lower power prices.

Lower Alberta spot power prices experienced in first quarter 2015 are expected to continue in the near term and 2015 Western Power earnings are anticipated to be lower compared to 2014. Longer-term, we expect prices to return to higher levels as excess supply is absorbed by growth in power demand and aging generation infrastructure is retired.

Fifty-four per cent of Western Power sales volumes were sold under contract in first quarter 2015 compared to 72 per cent in first quarter 2014.

Eastern Power

Comparable EBITDA for Eastern Power increased by $38 million for the three months ended March 31, 2015 compared to the same period in 2014 mainly due to the sale of unused natural gas transportation, higher contractual earnings at Bécancour and incremental earnings from solar facilities acquired in 2014.

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BRUCE POWER

Our proportionate share



	three months ended March 31
(unaudited - millions of $, unless noted otherwise)	2015			2014

Income from equity investments¹
Bruce A	56			49
Bruce B	23			15
	79			64
Comprised of:
Revenues	331			300
Operating expenses	(172		)	(157		)
Depreciation and other	(80		)	(79		)
	79			64
Bruce Power - Other information
Plant availability²
Bruce A	89		%	80		%
Bruce B	97		%	85		%
Combined Bruce Power	93		%	83		%
Planned outage days
Bruce A	39			—
Bruce B	—			49
Unplanned outage days
Bruce A	—			60
Bruce B	9			—
Sales volumes (GWh)¹
Bruce A	2,819			2,527
Bruce B	2,165			1,924
	4,984			4,451
Realized sales price per MWh³
Bruce A		$72			$71
Bruce B		$54			$56
Combined Bruce Power		$62			$63


1	Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. 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. Bruce B realized sales prices per MWh includes revenues under the floor price mechanism and revenues from contract settlements.

Equity income from Bruce A increased by $7 million for the three months ended March 31, 2015 compared to the same period in 2014. The increase was mainly due to higher volumes resulting from fewer outage days partially offset by higher operating expenses.

Equity income from Bruce B increased $8 million for the three months ended March 31, 2015 compared to the same period in 2014 mainly due to higher volumes resulting from fewer outage days.

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Under a contract with the IESO, all of the output from Bruce A is sold at a fixed price/MWh which is adjusted annually on April 1 for inflation.



Bruce A fixed price	per MWh

April 1, 2015 - March 31, 2016	$73.42
April 1, 2014 - March 31, 2015	$71.70
April 1, 2013 - March 31, 2014	$70.99

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



Bruce B floor price	per MWh

April 1, 2015 - March 31, 2016	$54.13
April 1, 2014 - March 31, 2015	$52.86
April 1, 2013 - March 31, 2014	$52.34

Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the average spot price in a month exceeds the floor price. We expect 2015 spot power prices to be less than the floor price throughout 2015 and therefore no amounts received under the floor price mechanism in 2015 are expected to be repaid. Amounts received above the floor price in first quarter 2014 were repaid to the IESO in January 2015.

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

The contract also 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 fixed price, floor price or spot price as applicable under the contract.

Overall plant availability percentages in 2015 are expected to be in the mid 80s for Bruce A and Bruce B. In April 2015, all Bruce B units were removed from service for approximately one month to allow for inspection of the Bruce B vacuum building as mandated by the Canadian Nuclear Safety Commission to occur approximately once every decade. Additional planned maintenance on Unit 6 will continue during second quarter 2015. Planned maintenance at Bruce A is scheduled for third quarter 2015.

U.S. POWER



	three months ended March 31
(unaudited - millions of US$)	2015		2014

Revenue
Power¹	605		743
Capacity	67		70
	672		813
Commodity purchases resold	(476	)	(549	)
Plant operating costs and other²	(117	)	(180	)
Exclude risk management activities¹	54		2
Comparable EBITDA	133		86
Comparable depreciation and amortization	(27	)	(27	)
Comparable EBIT	106		59

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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)	2015		2014

Physical sales volumes (GWh)
Supply
Generation	914		1,238
Purchased	4,670		3,207
	5,584		4,445

Plant availability^1,2	61	%	85	%


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


2	Plant availability for the three months ended March 31 was lower in 2015 than the same period in 2014 due to an unplanned outage at the Ravenswood facility.

U.S. Power - other information



	three months ended March 31
(unaudited)	2015	2014

Average Spot Power Prices (US$ per MWh)
New England	86	145
New York¹	74	134

Average New York¹ Spot Capacity Prices (US$ per KW-M)	8.34	9.64


1	Represents Zone J in New York City where the Ravenswood plant operates.

Comparable EBITDA for U.S. Power increased US$47 million for the three months ended March 31, 2015 compared to the same period in 2014 and was primarily due to the net effect of:


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


•	lower realized power prices and generation at our facilities in New York and New England partially offset by higher margins and higher sales to wholesale, commercial and industrial customers.

The timing of recognizing earnings on certain contracts in our U.S. power marketing business is impacted by different power pricing profiles between the prices we charge our customers and the prices we pay for volumes purchased to fulfill our sales obligations over the term of the contracts. The costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers include the impact of certain contracts to purchase power over multiple periods at a flat price. Because the price we charge our customers is typically shaped to the market, the impact of these two contract pricing profiles has generally resulted in higher earnings in January to March, offset by lower earnings between April and December with overall positive margins realized over the term of the contracts. Due to increased natural gas and power prices experienced during winter 2013/2014 and the impact on the pricing of our 2015 contracts in the New England market, these timing differences will be more significant in 2015. The majority of these higher earnings will be offset by lower earnings in second quarter.

Wholesale electricity prices in New York and New England were significantly lower for the three months ended March 31, 2015 compared to the same period in 2014 despite colder temperatures in the northeast U.S. in 2015. Spot power prices for the three months ended March 31, 2015 were 41 per cent lower in New England and 45 per cent lower in New York City compared to the same period in 2014. Spot capacity prices in New York City were, on

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average, 13 per cent lower for the three months ended March 31, 2015 compared to the same period in 2014. Reductions in fuel oil prices and increased availability of liquefied natural gas in winter 2015 helped to mitigate the impact of pipeline constraints and keep peak price excursions limited compared to winter 2014. Lower commodity prices and reduced price volatility in first quarter 2015 contributed to higher margins on sales to wholesale, commercial and industrial customers by reducing the costs on volumes purchased to fulfill power sales commitments to these customers.

Physical sales volumes for the three months ended March 31, 2015 were higher compared to the same period in 2014. For the three months ended March 31, 2015, purchased volumes sold to wholesale, commercial and industrial customers were higher than the same period in 2014 offset by lower generation volumes primarily at our Ravenswood and hydro facilities.

As at March 31, 2015, approximately 3,900 GWh or 44 per cent of U.S. Power’s planned generation was contracted for the remainder of 2015, and 3,500 GWh or 31 per cent for 2016. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.

NATURAL GAS STORAGE AND OTHER

Comparable EBITDA decreased $24 million for the three months ended March 31, 2015 compared to the same period in 2014 and was due to decreased storage revenues as a result of lower realized natural gas price spreads. Extreme natural gas price volatility experienced in first quarter 2014 did not repeat in first quarter 2015.

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Recent developments

NATURAL GAS PIPELINES

Canadian Regulated Pipelines

NGTL System

The NGTL System has approximately $6.7 billion of new supply and demand facilities under development. In first quarter 2015, we continued to advance several of these capital expansion projects by filing the regulatory applications with the NEB and plan to file additional facilities applications for this program throughout 2015. We have also received additional requests for firm receipt service that we anticipate will increase the overall capital spend on the NGTL System beyond the previously announced program and continue to work with our customers to best match their requirements for 2016, 2017 and 2018 in-service dates.

North Montney Mainline

On April 15, 2015, the NEB issued its report recommending the federal government approve the $1.7 billion North Montney Mainline project which will provide substantial new capacity on the NGTL System to meet the transportation requirements associated with rapidly increasing development of natural gas resources in the Montney supply basin in northeastern B.C. The project will connect Montney and other Western Canada Sedimentary Basin supply to both existing and new natural gas markets, including LNG markets.

The North Montney Mainline project will consist of two large diameter, 42-inch pipeline sections, Aitken Creek and Kahta, totaling approximately 301 km (187 miles) in length, and associated metering facilities, valve sites and compression facilities. The project will also include an interconnection with our proposed Prince Rupert Gas Transmission Project to provide natural gas supply to the proposed Pacific NorthWest (PNW) LNG liquefaction and export facility near Prince Rupert, B.C. Subject to certain conditions, including a positive final investment decision on the proposed PNW LNG project, we expect to have the Aitken Creek Section in service in 2016 and the Kahta Section in service in 2017.

The NEB also approved the applied-for rolled-in tolling design for the project costs during a transition period, subject to certain conditions which we are reviewing. Following the transition period, we will have the option of applying to the NEB for a revised tolling methodology, or the ability to implement stand-alone tolling on the project. We will engage shippers to determine an appropriate approach that best meets market requirements.

Canadian Mainline

TransCanada Mainline - 2013-2030 Mainline Settlement Application Compliance Filing

On March 31, 2015, we submitted a compliance filing in response to direction from the NEB’s RH-001-2014 Decision issued in November 2014. We are currently operating under interim tolls set out at the level proposed in the initial application and will continue until final tolls are approved through this compliance filing.

U.S. Pipelines

Sale of GTN Pipeline to TC PipeLines, LP

On April 1, 2015, we closed the sale of our remaining 30 per cent interest in Gas Transmission Northwest LLC (GTN) to our master limited partnership, TC PipeLines, LP. The US$446 million sale is comprised of US$253 million in cash, the assumption of US$98 million in proportional GTN debt and the issuance of US$95 million of new Class B units. The Class B units entitle us to a cash distribution based on 30 per cent of GTN's annual cash distribution after certain thresholds are achieved, namely, 100 per cent of distributions above US$20 million in the first five years and 25 per cent of distributions above US$20 million in subsequent years.

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LNG Pipeline Projects

Prince Rupert Gas Transmission

We anticipate decisions in second quarter 2015 from the B.C. Oil and Gas Commission (BC OGC) on the permits to build and operate the Prince Rupert Gas Transmission pipeline project.

Coastal GasLink

We anticipate decisions in second quarter 2015 from the BC OGC on the permits to build and operate the Coastal GasLink pipeline project.

LIQUIDS PIPELINES

Houston Lateral and Terminal

Construction continues on the 77 km (48 mile) Houston Lateral pipeline and tank terminal which will extend the Keystone Pipeline System to Houston, Texas refineries. The terminal is expected to have initial storage capacity for 700,000 barrels of crude oil. The pipeline and terminal are expected to be completed in fourth quarter 2015.

On April 14, 2015, we, along with Magellan Midstream Partners L.P. (Magellan), announced a joint development agreement to connect our Houston Terminal to Magellan's East Houston Terminal. We will own 50 per cent of the US$50 million pipeline project which will enhance connections to the Houston market for our Keystone Pipeline System. Subject to definitive agreements and receipt of necessary permits and approvals, the pipeline is expected to be operational in late 2016.

Keystone XL

In January 2015, the DOS re-initiated the national interest review and requested the eight federal agencies with a role in the review to complete their consideration of whether Keystone XL serves the national interest. All of the agency comments have been received.

On February 2, 2015, the U.S. Environmental Protection Agency (EPA) posted a comment letter to its website suggesting that, among other things, the FSEIS issued by the DOS has not fully and completely assessed the environmental impacts of Keystone XL and that, at lower oil prices, Keystone XL may increase the rates of oil sands production and greenhouse gas emissions. On February 10, 2015, we sent a letter to the DOS refuting these and other comments in the EPA letter but also offering to work with the DOS to ensure it has all the relevant information to allow it to reach a decision to approve Keystone XL.

On February 12, 2015, Nebraska county courts granted temporary injunctions that were negotiated between us and landowners’ counsel which prevent Keystone from proceeding with condemnation cases until the underlying constitutional litigation is resolved. A renewed challenge to the constitutionality of the statute under which the Governor approved the re-route in the state is pending in a Nebraska District Court.

On February 24, 2015, U.S. President Obama vetoed Congressional legislation that would have granted us authority to construct Keystone XL across the international border. The U.S. President stated that the legislation circumvented a final DOS assessment. The timing and ultimate resolution of Keystone XL’s pending application for a Presidential Permit remains uncertain.

The South Dakota Public Utility Commission has scheduled a hearing in third quarter 2015 on our request to certify our existing permit authority in that state.

The estimated capital cost for Keystone XL is expected to be approximately US$8.0 billion. As of March 31, 2015, we have invested US$2.4 billion in the project and have also capitalized interest in the amount of US$0.4 billion.

Energy East Pipeline

On April 2, 2015, we announced that the marine and associated tank terminal in Cacouna, Québec will not be built as a result of the potential reclassification of beluga whales as an endangered species. We are currently evaluating other options and discussing those options with our shippers. Amendments to the project are expected to be

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submitted to the NEB in fourth quarter 2015. The alteration to the project scope and further refinement of the project schedule is expected to result in an in-service date of 2020.

Binding long term contracts of approximately one million Bbl/d for the 1.1 million Bbl/d pipeline have been secured. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets.

Upland Pipeline

On April 22, 2015, we filed an application to obtain a U.S. Presidential Permit for the Upland Pipeline. The $600 million Upland Pipeline is a 400 km (240 mile) crude oil pipeline which will provide transportation from, and between, multiple points in North Dakota and interconnect with the Energy East Pipeline at Moosomin, Saskatchewan.

Subject to regulatory approvals, we anticipate the Upland Pipeline to be in service in 2020. The commercial contracts we have executed for Upland Pipeline are conditioned on Energy East proceeding.

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Other income statement items

The following are reconciliations and related analyses of our non-GAAP measures to the equivalent GAAP measures for other income statement items.



	three months ended March 31
(unaudited - millions of $)	2015		2014

Comparable interest on long-term debt (including interest on junior subordinated notes)
Canadian-dollar denominated	(109	)	(114	)
U.S. dollar-denominated (US$)	(218	)	(207	)
Foreign exchange impact	(48	)	(22	)
	(375	)	(343	)
Other interest and amortization expense	(13	)	(10	)
Capitalized interest	70		79
Comparable interest expense	(318	)	(274	)
Specific items¹	—		—
Interest expense	(318	)	(274	)


1	There were no specific items in either of these periods.

Comparable interest expense increased by $44 million for the three months ended March 31, 2015 compared to the same period in 2014 because of the following:


•	higher interest expense due to debt issues of:


◦	US$750 million in January 2015


◦	US$1.25 billion in February 2014


◦	partially offset by Canadian and U.S. dollar-denominated debt maturities


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


•	lower capitalized interest primarily due to the completion of the Gulf Coast extension of the Keystone Pipeline System in first quarter 2014.



	three months ended March 31
(unaudited - millions of $)	2015		2014

Comparable interest income and other expense	15		(6	)
Specific items (pre-tax):
Risk management activities	(29	)	(2	)
Interest income and other expense	(14	)	(8	)

Comparable interest income and other expense increased by $21 million for the three months ended March 31, 2015 compared to the same period in 2014. This is the net result of:


•	increased AFUDC related to our rate-regulated projects primarily the Energy East Pipeline and our Mexico pipelines


•	higher realized losses in 2015 compared to 2014 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income


•	the impact of a strengthening U.S. dollar on the translation of foreign currency denominated working capital.

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	three months ended March 31
(unaudited - millions of $)	2015		2014

Comparable income tax expense	(247	)	(224	)
Specific items:
Risk management activities	40		3
Income tax expense	(207	)	(221	)

Comparable income tax expense increased by $23 million for the three months ended March 31, 2015 compared to the same period in 2014. The increase was mainly the result of higher pre-tax earnings in 2015 compared to 2014 and changes in the proportion of income earned between Canadian and foreign jurisdictions partially offset by lower flow-through taxes in 2015 on Canadian regulated pipelines.



	three months ended March 31
(unaudited - millions of $)	2015		2014

Net income attributable to non-controlling interests	(59	)	(54	)
Preferred share dividends	(23	)	(23	)

Net income attributable to non-controlling interests increased by $5 million for the three months ended March 31, 2015 compared to the same period in 2014 primarily due to the sale of our remaining 30 per cent direct interest in Bison to TC PipeLines, LP in October 2014 and the positive impact of a strong U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP.

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, proceeds from the sale of U.S. natural gas pipeline assets 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 $)	2015		2014

Funds generated from operations¹	1,153		1,102
Increase in operating working capital	(393	)	(123	)
Net cash provided by operations	760		979


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

At March 31, 2015, our current assets were $5.1 billion and current liabilities were $8.2 billion, leaving us with a working capital deficit of $3.1 billion compared to $4.0 billion at December 31, 2014. 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 $6.0 billion of unutilized, unsecured credit facilities.

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CASH USED IN INVESTING ACTIVITIES



	three months ended March 31
(unaudited - millions of $)	2015		2014

Capital expenditures	(806	)	(744	)
Capital projects under development	(201	)	(104	)
Equity investments	(93	)	(89	)
Deferred amounts and other	263		47
Net cash used in investing activities	(837	)	(890	)

Capital expenditures in 2015 were primarily related to:


•	the expansion of the NGTL System


•	construction of the Northern Courier pipeline


•	construction of the Napanee power project


•	continued work on the ANR pipeline expansion


•	construction of Mexico pipelines.

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

CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES



	three months ended March 31
(unaudited - millions of $)	2015		2014

Long-term debt issued, net of issue costs	2,277		1,364
Repayment of long-term debt	(1,016	)	(777	)
Notes payable issued/(repaid), net	279		(747	)
Dividends and distributions paid	(417	)	(390	)
Common shares issued, net of issue costs	10		10
Partnership units of subsidiary issued, net of issue costs	4		—
Preferred shares issued, net of issue costs	243		440
Preferred shares of subsidiary redeemed	—		(200	)
Net cash provided by/(used in) financing activities	1,380		(300	)

LONG-TERM DEBT ISSUED



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

TRANSCANADA PIPELINES LIMITED
	March 2015	Senior Unsecured Notes	March 2045	US 750	4.60%
	January 2015	Senior Unsecured Notes	January 2018	US 500	1.875%
	January 2015	Senior Unsecured Notes	January 2018	US 250	Floating
TC PIPELINES, LP
	March 2015	Senior Unsecured Notes	March 2025	US 350	4.375%

LONG-TERM DEBT RETIRED



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

TRANSCANADA PIPELINES LIMITED
	March 2015	Senior Unsecured Notes	US 500	0.875%
	January 2015	Senior Unsecured Notes	US 300	4.875%

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PREFERRED SHARE ISSUANCE

In March 2015, we completed a public offering of 10 million Series 11 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $250 million. Investors are entitled to receive fixed cumulative dividends at an annual rate of $0.95 per share, payable quarterly. The dividend rate will reset on November 30, 2020 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 2.96 per cent. The preferred shares are redeemable by us on November 30, 2020 and on the last business day in November of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends. The Series 11 preferred shareholders will have the right to convert their shares into Series 12 cumulative redeemable first preferred shares on November 30, 2020 and on the last business day in November of every fifth year thereafter. The holders of Series 12 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annualized rate equal to the then 90-day Government of Canada treasury bill rate and 2.96 per cent.

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

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

In first quarter 2015, fifty-five thousand common units were issued under the ATM program generating net proceeds of approximately US$3 million. Our ownership interest in TC PipeLines, LP will decrease as a result of the ATM program.

DIVIDENDS

On April 30, 2015, we declared quarterly dividends as follows:



Quarterly dividend on our common shares

$0.52 per share
Payable on July 31, 2015 to shareholders of record at the close of business on June 30, 2015



Quarterly dividends on our preferred shares

Series 1	$0.2041
Series 2	$0.1488
Series 3	$0.25
Payable on June 30, 2015 to shareholders of record at the close of business on June 1, 2015
Series 5	$0.275
Series 7	$0.25
Series 9	$0.2656
Payable on July 30, 2015 to shareholders of record at the close of business on June 30, 2015
Series 11	$0.229
Payable on May 29, 2015 to shareholders of record at the close of business on May 12, 2015

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SHARE INFORMATION



as at April 27, 2015

Common shares	Issued and outstanding
	709 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	14 million	Series 4 preferred shares
Series 5	14 million	Series 6 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

Options to buy common shares	Outstanding	Exercisable
	6 million	10 million

CREDIT FACILITIES

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

At March 31, 2015, we had approximately $7 billion in unsecured credit facilities, including:



Amount	Unused capacity	Subsidiary	Description and use	Matures

$3.0 billion	$3.0 billion	TCPL	Committed, syndicated, revolving, extendible credit facility that supports TCPL’s Canadian commercial paper program	December 2019
US$1.0 billion	US$1.0 billion	TCPL USA	Committed, syndicated, revolving, extendible credit facility that is used for TCPL USA general corporate purposes	November 2015
US$1.0 billion	US$1.0 billion	TransCanada American Investments Ltd. (TAIL)	Committed, syndicated, revolving, extendible credit facility that supports TAIL's U.S. commercial paper program in the U.S.	November 2015
$1.4 billion	$0.5 billion	TCPL, TCPL USA	Demand lines for issuing letters of credit and as a source of additional liquidity. At March 31, 2015, we had $0.9 billion outstanding in letters of credit under these lines	Demand

At March 31, 2015, our operated affiliates had $0.4 billion of undrawn capacity on committed credit facilities.

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

CONTRACTUAL OBLIGATIONS

Our capital commitments have decreased by approximately $0.4 billion since December 31, 2014 primarily due to the completion or advancement of capital projects. Our other purchase obligations have increased by approximately $0.2 billion since December 31, 2014 primarily due to an increase in commodity purchase obligations and information technology and communication contracts. There were no other material changes to our contractual obligations in first quarter 2015 or to payments due in the next five years or after. See the MD&A in our 2014 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.

See our 2014 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2014.

LIQUIDITY RISK

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

COUNTERPARTY CREDIT RISK

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


•	accounts receivable


•	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, 2015, we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration due from a counterparty of $241 million (US$190 million) and $258 million (US$222 million) at March 31, 2015 and December 31, 2014, respectively. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.

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 and floating rate preferred shares (Series 2) which subject us to interest rate cash flow risk. We use interest rate swaps to help manage this risk.

Average exchange rate - U.S. to Canadian dollars



First quarter 2015	1.24
First quarter 2014	1.11

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

TRANSCANADA [29

FIRST QUARTER 2015

Significant U.S. dollar-denominated amounts



	three months ended March 31
(unaudited - millions of US$)	2015		2014

U.S. and International Natural Gas Pipelines comparable EBIT	241		211
U.S. Liquids Pipelines comparable EBIT	149		129
U.S. Power comparable EBIT	106		59
Interest expense on U.S. dollar-denominated long-term debt	(218	)	(207	)
Capitalized interest on U.S. dollar-denominated capital expenditures	31		52
U.S. non-controlling interests and other	(79	)	(79	)
	230		165

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 and foreign exchange forward contracts. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:



	March 31, 2015			December 31, 2014
(unaudited - millions of $)	Fair value¹		Notional or principal amount	Fair value¹		Notional or principal amount

Asset/(liability)
U.S. dollar cross-currency interest rate swaps
(maturing 2015 to 2019)²	(670	)	US 2,700	(431	)	US 2,900
U.S. dollar foreign exchange forward contracts
(maturing 2015)	(91	)	US 3,500	(28	)	US 1,400
	(761	)	US 6,200	(459	)	US 4,300


1	Fair values equal carrying values.


2	Net income in the three months ended March 31, 2015 included net realized gains of $3 million (2014 - gains of $6 million) related to the interest component of cross-currency swaps settlements.

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



(unaudited - millions of $)	March 31, 2015	December 31, 2014

Carrying value	19,500 (US 15,400)	17,000 (US 14,700)
Fair value	22,700 (US 17,900)	19,000 (US 16,400)

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



(unaudited - millions of $)	March 31, 2015		December 31, 2014

Other current assets	63		5
Intangible and other assets	2		1
Accounts payable and other	(370	)	(155	)
Other long-term liabilities	(456	)	(310	)
	(761	)	(459	)

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.

TRANSCANADA [30

FIRST QUARTER 2015

Non-derivative financial instruments

Fair value of non-derivative financial instruments

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

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

Derivative instruments

We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify and are designated for hedge accounting treatment. The 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 expense 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.

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

Fair value of derivative instruments

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

Balance sheet presentation of derivative instruments

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



(unaudited - millions of $)	March 31, 2015		December 31, 2014

Other current assets	543		409
Intangible and other assets	153		93
Accounts payable and other	(1,039	)	(749	)
Other long-term liabilities	(662	)	(411	)
	(1,005	)	(658	)

TRANSCANADA [31

FIRST QUARTER 2015

The effect of derivative instruments on the condensed consolidated statement of income

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



	three months ended March 31
(unaudited - millions of $, pre-tax)	2015		2014

Derivative instruments held for trading¹
Amount of unrealized (losses)/gains in the period
Power	(26	)	9
Natural gas	—		(7	)
Foreign exchange	(29	)	(2	)
Amount of realized (losses)/gains in the period
Power	(10	)	(28	)
Natural gas	11		50
Foreign exchange	(43	)	(17	)
Derivative instruments in hedging relationships^2,3
Amount of realized gains in the period
Power	16		192
Interest	2		1
Losses on ineffective portion in the period
Power	(63	)	(13	)


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


2	For the three months ended March 31, 2015, net realized gains on fair value hedges were $2 million (2014 - $1 million) and were included in interest expense. For the three months ended March 31, 2015 and 2014, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other expense as appropriate, as the original hedged item settles. For the three months ended March 31, 2015 and 2014, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

Derivatives in cash flow hedging relationships

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



	three months ended March 31
(unaudited - millions of $, pre-tax)	2015		2014

Change in fair value of derivative instruments recognized in OCI (effective portion)¹
Power	21		41
Foreign exchange	—		10
	21		51
Reclassification of gains/(losses) on derivative instruments from AOCI to net income (effective portion)¹
Power²	69		(108	)
Interest³	4		5
	73		(103	)
Losses on derivative instruments recognized in net income (ineffective portion)
Power	(63	)	(13	)
	(63	)	(13	)


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


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


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

TRANSCANADA [32

FIRST QUARTER 2015

Credit risk related contingent features of derivative instruments

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

Based on contracts in place and market prices at March 31, 2015, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $31 million (December 31, 2014 - $15 million), with collateral provided in the normal course of business of nil (December 31, 2014 – nil). If the credit-risk-related contingent features in these agreements had been triggered on March 31, 2015, we would have been required to provide collateral of $31 million (December 31, 2014 – $15 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

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

Other information

CONTROLS AND PROCEDURES

Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at March 31, 2015, 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 2015 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 2014 Annual Report.

Our significant accounting policies have remained unchanged since December 31, 2014 other than described below. You can find a summary of our significant accounting policies in our 2014 Annual Report.

Changes in accounting policies for 2015

Reporting discontinued operations

In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance was applied prospectively from January 1, 2015 and there was no impact on the Company’s consolidated financial statements as a result of applying this new standard.

Future accounting changes

Revenue from contracts with customers

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

TRANSCANADA [33

FIRST QUARTER 2015

In April 2015, the FASB proposed deferring the effective date to January 1, 2018 and proposed permitting early adoption of the standard but not before the original effective date.

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

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 is effective from January 1, 2016 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

Consolidation

In February 2015, the FASB issued new guidance on consolidation analysis. This update requires that entities reevaluate whether they should consolidate certain legal entities, and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance is effective from January 1, 2016 and will be applied retrospectively. We are currently evaluating the impact of the adoption of this ASU and have not yet determined the effect on our consolidated financial statements.

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 is effective January 1, 2016 and will be applied retrospectively. The application of this amendment will result in a reclassification of debt issuance costs currently recorded in intangible and other assets to an offset of their respective debt liabilities.

TRANSCANADA [34

FIRST QUARTER 2015

Reconciliation of non-GAAP measures



	three months ended March 31
(unaudited - millions of $, except per share amounts)	2015			2014

EBITDA	1,442			1,385
Non-comparable risk management activities affecting EBITDA	89			11
Comparable EBITDA	1,531			1,396
Comparable depreciation and amortization	(434		)	(393		)
Comparable EBIT	1,097			1,003
Other income statement items
Comparable interest expense	(318		)	(274		)
Comparable interest income and other expense	15			(6		)
Comparable income tax expense	(247		)	(224		)
Net income attributable to non-controlling interests	(59		)	(54		)
Preferred share dividends	(23		)	(23		)
Comparable earnings	465			422
Specific items (net of tax):
Risk management activities¹	(78		)	(10		)
Net income attributable to common shares	387			412

Comparable depreciation and amortization	(434		)	(393		)
Specific items²	—			—
Depreciation and amortization	(434		)	(393		)

Comparable interest expense	(318		)	(274		)
Specific items²	—			—
Interest expense	(318		)	(274		)

Comparable interest income and other expense	15			(6		)
Specific items:
Risk management activities¹	(29		)	(2		)
Interest income and other expense	(14		)	(8		)

Comparable income tax expense	(247		)	(224		)
Specific items:
Risk management activities¹	40			3
Income tax expense	(207		)	(221		)

Comparable earnings per common share		$0.66			$0.60
Specific items (net of tax):
Risk management activities¹	(0.11		)	(0.02		)
Net income per common share		$0.55			$0.58



1	Risk management activities	three months ended March 31
	(unaudited - millions of $)	2015		2014

	Canadian Power	(22	)	—
	U.S. Power	(68	)	(2	)
	Natural Gas Storage	1		(9	)
	Foreign exchange	(29	)	(2	)
	Income tax attributable to risk management activities	40		3
	Total losses from risk management activities	(78	)	(10	)


2	There were no specific items in either of these periods.

TRANSCANADA [35

FIRST QUARTER 2015

Comparable EBITDA and EBIT by business segment



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

EBITDA	874		309		299		(40	)	1,442
Non-comparable risk management activities affecting EBITDA	—		—		89		—		89
Comparable EBITDA	874		309		388		(40	)	1,531
Comparable depreciation and amortization	(279	)	(63	)	(85	)	(7	)	(434	)
Comparable EBIT	595		246		303		(47	)	1,097



three months ended March 31, 2014	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total

EBITDA	848		241		334		(38	)	1,385
Non-comparable risk management activities affecting EBITDA	—		—		11		—		11
Comparable EBITDA	848		241		345		(38	)	1,396
Comparable depreciation and amortization	(262	)	(49	)	(77	)	(5	)	(393	)
Comparable EBIT	586		192		268		(43	)	1,003

Quarterly results

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA



	2015		2014								2013
(unaudited - millions of $, except per share amounts)	First		Fourth		Third		Second		First		Fourth		Third		Second

Revenues	2,874		2,616		2,451		2,234		2,884		2,332		2,204		2,009
Net income attributable to common shares	387		458		457		416		412		420		481		365
Comparable earnings	465		511		450		332		422		410		447		357
Share statistics
Net income per common share - basic and diluted		$0.55		$0.72		$0.63		$0.59		$0.58		$0.59		$0.68		$0.52
Comparable earnings per share		$0.66		$0.65		$0.64		$0.47		$0.60		$0.58		$0.63		$0.51
Dividends declared per common share		$0.52		$0.48		$0.48		$0.48		$0.48		$0.46		$0.46		$0.46

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT

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

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


•	regulatory decisions


•	negotiated settlements with shippers


•	acquisitions and divestitures


•	developments outside of the normal course of operations


•	newly constructed assets being placed in service.

TRANSCANADA [36

FIRST QUARTER 2015

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

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER

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

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

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

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