EXHIBIT 13.2

Condensed consolidated statement of income

	three months ended June 30						six months ended June 30
(unaudited - millions of Canadian $, except per share amounts)	2017			2016			2017			2016
Revenues
Canadian Natural Gas Pipelines	922			908			1,804			1,726
U.S. Natural Gas Pipelines	879			344			1,873			773
Mexico Natural Gas Pipelines	150			62			293			128
Liquids Pipelines	501			416			973			852
Energy	765			1,021			1,665			1,775
	3,217			2,751			6,608			5,254
Income from Equity Investments	197			66			371			201
Operating and Other Expenses
Plant operating costs and other	1,014			754			2,004			1,469
Commodity purchases resold	547			375			1,090			845
Property taxes	153			128			315			269
Depreciation and amortization	516			444			1,033			898
Asset impairment charges	—			—			—			211
	2,230			1,701			4,442			3,692
Gain/(Loss) on Sale of Assets	498			—			498			(4		)
Financial Charges
Interest expense	524			514			1,024			934
Allowance for funds used during construction	(121		)	(111		)	(222		)	(212		)
Interest income and other	(89		)	(6		)	(109		)	(106		)
	314			397			693			616
Income before Income Taxes	1,368			719			2,342			1,143
Income Tax Expense
Current	55			55			122			89
Deferred	338			219			471			255
	393			274			593			344
Net Income	975			445			1,749			799
Net income attributable to non-controlling interests	55			52			145			132
Net Income Attributable to Controlling Interests	920			393			1,604			667
Preferred share dividends	39			28			80			50
Net Income Attributable to Common Shares	881			365			1,524			617
Net Income per Common Share
Basic		$1.01			$0.52			$1.76			$0.88
Diluted		$1.01			$0.52			$1.75			$0.88
Dividends Declared per Common Share		$0.625			$0.565			$1.25			$1.13
Weighted Average Number of Common Shares (millions)
Basic	870			703			868			703
Diluted	872			703			870			703

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of comprehensive income

	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $)	2017		2016		2017		2016
Net Income	975		445		1,749		799
Other Comprehensive (Loss)/Income, Net of Income Taxes
Foreign currency translation (losses)/gains on net investment in foreign operations	(269	)	5		(351	)	(207	)
Reclassification of foreign currency translation gains on net investment in foreign operations	(77	)	—		(77	)	—
Change in fair value of net investment hedges	(1	)	(6	)	(2	)	(8	)
Change in fair value of cash flow hedges	(2	)	55		3		16
Reclassification to net income of gains and losses on cash flow hedges	(1	)	(40	)	(1	)	40
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	4		4		7		8
Other comprehensive income on equity investments	—		4		3		7
Other comprehensive (loss)/income (Note 8)	(346	)	22		(418	)	(144	)
Comprehensive Income	629		467		1,331		655
Comprehensive income attributable to non-controlling interests	6		54		56		28
Comprehensive Income Attributable to Controlling Interests	623		413		1,275		627
Preferred share dividends	39		28		80		50
Comprehensive Income Attributable to Common Shares	584		385		1,195		577

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of cash flows

	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $)	2017		2016		2017		2016
Cash Generated from Operations
Net income	975		445		1,749		799
Depreciation and amortization	516		444		1,033		898
Asset impairment charges	—		—		—		211
Deferred income taxes	338		219		471		255
Income from equity investments	(197	)	(66	)	(371	)	(201	)
Distributions received from operating activities of equity investments	228		181		447		440
Employee post-retirement benefits expense, net of funding	6		(20	)	9		(9	)
(Gain)/loss on sale of assets	(498	)	—		(498	)	4
Equity allowance for funds used during construction	(78	)	(67	)	(142	)	(124	)
Unrealized losses/(gains) on financial instruments	50		(224	)	91		(153	)
Other	(4	)	18		4		23
Decrease/(increase) in operating working capital	17		218		(138	)	86
Net cash provided by operations	1,353		1,148		2,655		2,229
Investing Activities
Capital expenditures	(1,792	)	(982	)	(3,352	)	(1,818	)
Capital projects in development	(56	)	(90	)	(98	)	(157	)
Contributions to equity investments	(473	)	(114	)	(665	)	(284	)
Restricted cash	—		(13,113	)	—		(13,113	)
Acquisitions, net of cash acquired	—		(4	)	—		(999	)
Proceeds from sale of assets, net of transaction costs	4,147		—		4,147		6
Other distributions from equity investments	1		725		364		725
Deferred amounts and other	(169	)	(20	)	(254	)	32
Net cash provided by/(used in) investing activities	1,658		(13,598	)	142		(15,608	)
Financing Activities
Notes payable issued/(repaid), net	111		(853	)	781		323
Long-term debt issued, net of issue costs	817		10,335		817		12,327
Long-term debt repaid	(4,418	)	(933	)	(5,469	)	(2,290	)
Junior subordinated notes issued, net of issue costs	1,489		—		3,471		—
Dividends on common shares	(328	)	(397	)	(628	)	(762	)
Dividends on preferred shares	(38	)	(23	)	(77	)	(46	)
Distributions paid to non-controlling interests	(69	)	(62	)	(149	)	(124	)
Common shares/subscription receipts issued, net of issue costs	18		4,371		36		4,374
Common shares repurchased	—		—		—		(14	)
Preferred shares issued, net of issue costs	—		492		—		492
Partnership units of TC PipeLines, LP issued, net of issue costs	27		82		119		106
Common units of Columbia Pipeline Partners LP acquired	—		—		(1,205	)	—
Net cash (used in)/provided by financing activities	(2,391	)	13,012		(2,304	)	14,386
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(24	)	(73	)	(19	)	(130	)
Increase in Cash and Cash Equivalents	596		489		474		877
Cash and Cash Equivalents
Beginning of period	894		1,238		1,016		850
Cash and Cash Equivalents
End of period	1,490		1,727		1,490		1,727

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated balance sheet

		June 30,		December 31,
(unaudited - millions of Canadian $)		2017		2016
ASSETS
Current Assets
Cash and cash equivalents		1,490		1,016
Accounts receivable		2,117		2,075
Inventories		393		368
Assets held for sale		—		3,717
Other		899		908
		4,899		8,084
Plant, Property and Equipment	net of accumulated depreciation of $23,054 and $22,263, respectively	55,951		54,475
Equity Investments		6,315		6,544
Regulatory Assets		1,306		1,322
Goodwill		13,569		13,958
Intangible and Other Assets		3,490		3,026
Restricted Investments		784		642
		86,314		88,051
LIABILITIES
Current Liabilities
Notes payable		1,559		774
Accounts payable and other		4,057		3,861
Dividends payable		557		526
Accrued interest		609		595
Liabilities related to assets held for sale		—		86
Current portion of long-term debt		3,270		1,838
		10,052		7,680
Regulatory Liabilities		2,376		2,121
Other Long-Term Liabilities		980		1,183
Deferred Income Tax Liabilities		8,054		7,662
Long-Term Debt		31,276		38,312
Junior Subordinated Notes		7,218		3,931
		59,956		60,889
Common Units Subject to Rescission or Redemption		—		1,179
EQUITY
Common shares, no par value		20,544		20,099
Issued and outstanding:	June 30, 2017 - 871 million shares
	December 31, 2016 - 864 million shares
Preferred shares		3,980		3,980
Additional paid-in capital		—		—
Retained earnings		1,251		1,138
Accumulated other comprehensive loss		(1,289	)	(960	)
Controlling Interests		24,486		24,257
Non-controlling interests		1,872		1,726
		26,358		25,983
		86,314		88,051

Commitments, Contingencies and Guarantees (Note 12)

Variable Interest Entities (Note 13)

Subsequent Event (Note 14)

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of equity

	six months ended June 30
(unaudited - millions of Canadian $)	2017		2016
Common Shares
Balance at beginning of period	20,099		12,102
Shares issued on exercise of stock options	39		29
Shares repurchased	—		(6	)
Shares issued under dividend reinvestment and share purchase plan	406		—
Balance at end of period	20,544		12,125
Preferred Shares
Balance at beginning and end of period	3,980		2,992
Additional Paid-In Capital
Balance at beginning of period	—		7
Issuance of stock options, net of exercises	2		5
Dilution impact from TC PipeLines, LP units issued	13		12
Impact of common shares repurchased	—		(8	)
Impact of asset drop downs to TC PipeLines, LP	(202	)	(38	)
Impact of Columbia Pipeline Partners LP acquisition	(171	)	—
Reclassification of Additional Paid-In Capital deficit to Retained Earnings	358		22
Balance at end of period	—		—
Retained Earnings
Balance at beginning of period	1,138		2,769
Net income attributable to controlling interests	1,604		667
Common share dividends	(1,087	)	(794	)
Preferred share dividends	(58	)	(44	)
Adjustment related to employee share-based payments (Note 2)	12		—
Reclassification of Additional Paid-In Capital deficit to Retained Earnings	(358	)	(22	)
Balance at end of period	1,251		2,576
Accumulated Other Comprehensive Loss
Balance at beginning of period	(960	)	(939	)
Other comprehensive loss	(329	)	(40	)
Balance at end of period	(1,289	)	(979	)
Equity Attributable to Controlling Interests	24,486		16,714
Equity Attributable to Non-Controlling Interests
Balance at beginning of period	1,726		1,717
Net income attributable to non-controlling interests
TC PipeLines, LP	127		110
Portland Natural Gas Transmission System	9		22
Columbia Pipeline Partners LP	9		—
Other comprehensive loss attributable to non-controlling interests	(89	)	(104	)
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs	119		106
Decrease in TransCanada's ownership of TC PipeLines, LP	(21	)	(19	)
Reclassification from/(to) common units of TC PipeLines, LP subject to rescission	106		(106	)
Distributions declared to non-controlling interests	(147	)	(125	)
Impact of Columbia Pipeline Partners LP acquisition	33		—
Balance at end of period	1,872		1,601
Total Equity	26,358		18,315

See accompanying notes to the condensed consolidated financial statements.

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Notes to condensed consolidated financial statements

(unaudited)

1. Basis of presentation

These condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TransCanada’s annual audited consolidated financial statements for the year ended December 31, 2016, except as described in Note 2, Accounting changes. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada’s 2016 Annual Report.

These condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect fairly the financial position and results of operations for the respective periods. These condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2016 audited consolidated financial statements included in TransCanada’s 2016 Annual Report. Certain comparative figures have been reclassified to conform with the current period’s presentation.

Earnings for interim periods may not be indicative of results for the fiscal year in the Company’s natural gas pipelines segments due to the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company’s Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company’s investments in electrical power generation plants and non-regulated gas storage facilities.

USE OF ESTIMATES AND JUDGEMENTS

In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies included in the consolidated financial statements for the year ended December 31, 2016, except as described in Note 2, Accounting changes.

2. Accounting changes

CHANGES IN ACCOUNTING POLICIES FOR 2017

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this guidance 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 was effective January 1, 2017, was applied prospectively and did not have a material impact on the Company's consolidated balance sheet.

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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 U.S. 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 of their debt hosts. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements.

Equity method investments

In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements.

Employee share-based payments

In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. The Company has elected to account for forfeitures when they occur. This new guidance was effective January 1, 2017 and resulted in a cumulative-effect adjustment of $12 million to opening retained earnings and the recognition of a deferred tax asset related to employee share-based payments made prior to the adoption of this guidance.

Consolidation

In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to the Company's consolidation conclusions.

FUTURE ACCOUNTING CHANGES

Revenue from contracts with customers

In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a five-step model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Company will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Company currently anticipates adopting the standard using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowable and elected practical expedients.

The Company has identified all existing customer contracts that are within the scope of the new guidance and is on schedule in the process of analyzing individual contracts or groups of contracts by operating segment to identify any significant changes in how revenues are recognized as a result of implementing the new guidance. While the Company has not identified any material differences in the amount and timing of revenue recognition for the operating segments

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that have been analyzed to date, the evaluation is not complete and the Company has not concluded on the overall impact of adopting the new guidance. The Company continues its contract analysis to obtain the information necessary to quantify the cumulative-effect adjustment, if any, on prior period revenues and revenue recognized going forward. The Company also continues to address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.

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 the fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018 and a method of adoption is specified for each component of the guidance. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Leases

In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for an arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting.

The new guidance is effective on January 1, 2019, with early adoption permitted.  A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidance on its consolidated financial statements. The Company is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.

Measurement of credit losses on financial instruments

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

Income taxes

In October 2016, the FASB issued new guidance on the income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

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Restricted cash

In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents balance, and amounts generally described as restricted cash or restricted cash equivalents. Restricted cash and cash equivalents will be included with Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively, however, early adoption is permitted.

Goodwill impairment

In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating Step 2 of the impairment test, which is the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted.

Employee post-retirement benefits

In March 2017, the FASB issued new guidance that will require entities to disaggregate the current service cost component from the other components of net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance is effective January 1, 2018. The Company is currently evaluating the impact of the adoption of this guidance, however, does not expect a material impact on its consolidated financial statements.

Amortization on purchased callable debt securities

In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

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3. Segmented information

three months ended June 30, 2017	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines
(unaudited - millions of Canadian $)									Energy		Corporate		Total
Revenues	922		879		150		501		765		—		3,217
Income from equity investments	2		57		5		(1	)	142		(8	)	197
Plant operating costs and other	(328	)	(337	)	(10	)	(147	)	(160	)	(32	)	(1,014	)
Commodity purchases resold	—		—		—		—		(547	)	—		(547	)
Property taxes	(69	)	(48	)	—		(22	)	(14	)	—		(153	)
Depreciation and amortization	(222	)	(150	)	(25	)	(80	)	(39	)	—		(516	)
Gain on sale of assets	—		—		—		—		498		—		498
Segmented earnings/(loss)	305		401		120		251		645		(40	)	1,682
Interest expense													(524	)
Allowance for funds used during construction													121
Interest income and other													89
Income before income taxes													1,368
Income tax expense													(393	)
Net income													975
Net income attributable to non-controlling interests													(55	)
Net income attributable to controlling interests													920
Preferred share dividends													(39	)
Net income attributable to common shares													881

three months ended June 30, 2016	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines
(unaudited - millions of Canadian $)									Energy		Corporate		Total
Revenues	908		344		62		416		1,021		—		2,751
Income from equity investments	3		37		—		(1	)	27		—		66
Plant operating costs and other	(286	)	(110	)	(13	)	(125	)	(196	)	(24	)	(754	)
Commodity purchases resold	—		—		—		—		(375	)	—		(375	)
Property taxes	(64	)	(19	)	—		(23	)	(22	)	—		(128	)
Depreciation and amortization	(219	)	(64	)	(8	)	(69	)	(84	)	—		(444	)
Segmented earnings/(loss)	342		188		41		198		371		(24	)	1,116
Interest expense													(514	)
Allowance for funds used during construction													111
Interest income and other													6
Income before income taxes													719
Income tax expense													(274	)
Net income													445
Net income attributable to non-controlling interests													(52	)
Net income attributable to controlling interests													393
Preferred share dividends													(28	)
Net income attributable to common shares													365

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six months ended June 30, 2017	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines
(unaudited - millions of Canadian $)									Energy		Corporate		Total
Revenues	1,804		1,873		293		973		1,665		—		6,608
Income from equity investments	5		122		11		(1	)	242		(8	)	371
Plant operating costs and other	(640	)	(632	)	(19	)	(292	)	(356	)	(65	)	(2,004	)
Commodity purchases resold	—		—		—		—		(1,090	)	—		(1,090	)
Property taxes	(138	)	(95	)	—		(45	)	(37	)	—		(315	)
Depreciation and amortization	(444	)	(306	)	(47	)	(157	)	(79	)	—		(1,033	)
Gain on sale of assets	—		—		—		—		498		—		498
Segmented earnings/(loss)	587		962		238		478		843		(73	)	3,035
Interest expense													(1,024	)
Allowance for funds used during construction													222
Interest income and other													109
Income before income taxes													2,342
Income tax expense													(593	)
Net income													1,749
Net income attributable to non-controlling interests													(145	)
Net income attributable to controlling interests													1,604
Preferred share dividends													(80	)
Net income attributable to common shares													1,524

six months ended June 30, 2016	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines
(unaudited - millions of Canadian $)									Energy		Corporate		Total
Revenues	1,726		773		128		852		1,775		—		5,254
Income from equity investments	6		85		—		(1	)	111		—		201
Plant operating costs and other	(546	)	(228	)	(26	)	(254	)	(364	)	(51	)	(1,469	)
Commodity purchases resold	—		—		—		—		(845	)	—		(845	)
Property taxes	(137	)	(40	)	—		(46	)	(46	)	—		(269	)
Depreciation and amortization	(435	)	(131	)	(16	)	(141	)	(175	)	—		(898	)
Asset impairment charges	—		—		—		—		(211	)	—		(211	)
Loss on sale of assets	—		(4	)	—		—		—		—		(4	)
Segmented earnings/(loss)	614		455		86		410		245		(51	)	1,759
Interest expense													(934	)
Allowance for funds used during construction													212
Interest income and other													106
Income before income taxes													1,143
Income tax expense													(344	)
Net Income													799
Net income attributable to non-controlling interests													(132	)
Net Income attributable to controlling interests													667
Preferred share dividends													(50	)
Net Income attributable to common shares													617

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TOTAL ASSETS

(unaudited - millions of Canadian $)	June 30, 2017	December 31, 2016
Canadian Natural Gas Pipelines	16,564	15,816
U.S. Natural Gas Pipelines	34,926	34,422
Mexico Natural Gas Pipelines	5,386	5,013
Liquids Pipelines	16,789	16,896
Energy	9,181	13,169
Corporate	3,468	2,735
	86,314	88,051

4. Income taxes

The effective tax rates for the six-month periods endedJune 30, 2017 and 2016 were 25 per cent and 30 per cent, respectively. The lower effective tax rate in 2017 was primarily the result of lower flow-through taxes in 2017 on Canadian regulated pipelines and changes in the proportion of income earned between Canadian and foreign jurisdictions.

5. Long-term debt

LONG-TERM DEBT ISSUED

The Company issued long-term debt in the six months ended June 30, 2017 as follows:

(unaudited - millions of Canadian $, unless noted otherwise) Company	Issue date	Type	Maturity date	Amount	Interest rate
TC PIPELINES, LP
	May 2017	Senior Unsecured Notes	May 2027	US 500	3.90	%

LONG-TERM DEBT RETIRED

The Company retired long-term debt in the six months ended June 30, 2017 as follows:

(unaudited - millions of Canadian $, unless noted otherwise) Company	Retirement date	Type	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	June 2017	Acquisition Bridge Facility	US 1,513	Floating
	February 2017	Acquisition Bridge Facility	US 500	Floating
	January 2017	Medium Term Notes	300	5.10	%
TRANSCANADA PIPELINE USA LTD.
	June 2017	Acquisition Bridge Facility	US 630	Floating
	April 2017	Acquisition Bridge Facility	US 1,070	Floating

The acquisition bridge facilities were put into place to finance a portion of the Columbia acquisition. Proceeds from the sale of the U.S. Northeast power assets were used to fully retire the remaining acquisition bridge facilities in second quarter 2017.

In the three and six months endedJune 30, 2017, TransCanada capitalized interest related to capital projects of $56 million and $101 million (2016 - $46 million and $87 million).

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SECOND QUARTER 2017

6. Junior subordinated notes issued

(unaudited - millions of Canadian $, unless noted otherwise) Company	Issue date	Type	Maturity date	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED	May 2017	Junior Subordinated Notes1,2	May 2077	1,500	4.90	%
TRANSCANADA PIPELINES LIMITED	March 2017	Junior Subordinated Notes1,2	March 2077	US 1,500	5.55	%

¹  The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL.

²  The Junior subordinated notes were issued to TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL.

In May 2017, the Trust issued $1.5 billion of Trust Notes - Series 2017-B (Trust Notes) to third party investors with a fixed interest rate of 4.65 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for $1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 4.90 per cent, including a 0.25 per cent administration charge. The rate will reset commencing May 2027 until May 2047 to the three month Bankers' Acceptance rate plus 3.33 per cent per annum; from May 2047 until May 2077, the interest rate will reset to the three month Bankers' Acceptance rate plus 4.08 per cent per annum. The junior subordinated notes are callable at TCPL's option at any time on or after May 18, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

In March 2017, the Trust issued US$1.5 billion of Trust Notes - Series 2017-A (Trust Notes) to third party investors with a fixed interest rate of 5.30 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 5.55 per cent, including a 0.25 per cent administration charge. The rate will reset commencing March 2027 until March 2047 to the three month LIBOR plus 3.458 per cent per annum; from March 2047 until March 2077, the interest rate will reset to the three month LIBOR plus 4.208 per cent per annum. The junior subordinated notes are callable at TCPL's option at any time on or after March 15, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

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

7. Common units subject to rescission or redemption

Columbia Pipeline Partners LP acquisition

On February 17, 2017, the Company acquired all outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL) at a price of US$17.00 and a stub period distribution payment of US$0.10 per common unit for an aggregate transaction value of US$921 million. As this was a transaction between entities under common control, it was recognized in equity.

At December 31, 2016, the entire $1,073 million (US$799 million) of the Company's non-controlling interest in CPPL was recorded as Common units subject to rescission or redemption on the condensed consolidated balance sheet.

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SECOND QUARTER 2017

Common units of TC PipeLines, LP subject to rescission

In March 2017, rescission rights on 0.4 million TC PipeLines, LP common units expired and $24 million was reclassified to equity.

During second quarter 2017, rescission rights on the remaining 1.2 million TC PipeLines, LP common units expired and $82 million (US$63 million) was reclassified to equity. At June 30, 2017, there were no outstanding Common units subject to rescission or redemption on the condensed consolidated balance sheet (December 31, 2016 - $106 million (US$82 million)).

8. Other comprehensive loss and accumulated other comprehensive loss

Components of other comprehensive loss, including the portion attributable to non-controlling interests and related tax effects, are as follows: 

three months ended June 30, 2017			Income Tax
(unaudited - millions of Canadian $)	Before Tax Amount		Recovery/Expense		Net of Tax Amount
Foreign currency translation losses on net investment in foreign operations	(265	)	(4	)	(269	)
Reclassification of foreign currency translation gains on net investment on disposal of foreign operations	(77	)	—		(77	)
Change in fair value of net investment hedges	(1	)	—		(1	)
Change in fair value of cash flow hedges	(2	)	—		(2	)
Reclassification to net income of gains and losses on cash flow hedges	(2	)	1		(1	)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	5		(1	)	4
Other comprehensive loss	(342	)	(4	)	(346	)

three months ended June 30, 2016			Income Tax
(unaudited - millions of Canadian $)	Before Tax Amount		Recovery/Expense		Net of Tax Amount
Foreign currency translation gains on net investment in foreign operations	5		—		5
Change in fair value of net investment hedges	(7	)	1		(6	)
Change in fair value of cash flow hedges	81		(26	)	55
Reclassification to net income of gains and losses on cash flow hedges	(56	)	16		(40	)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	6		(2	)	4
Other comprehensive income on equity investments	5		(1	)	4
Other comprehensive income	34		(12	)	22

six months ended June 30, 2017			Income Tax
(unaudited - millions of Canadian $)	Before Tax Amount		Recovery/Expense		Net of Tax Amount
Foreign currency translation losses on net investment in foreign operations	(353	)	2		(351	)
Reclassification of foreign currency translation gains on net investment on disposal of foreign operations	(77	)	—		(77	)
Change in fair value of net investment hedges	(3	)	1		(2	)
Change in fair value of cash flow hedges	4		(1	)	3
Reclassification to net income of gains and losses on cash flow hedges	(2	)	1		(1	)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	10		(3	)	7
Other comprehensive income on equity investments	4		(1	)	3
Other comprehensive loss	(417	)	(1	)	(418	)

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SECOND QUARTER 2017

six months ended June 30, 2016			Income Tax
(unaudited - millions of Canadian $)	Before Tax Amount		Recovery/Expense		Net of Tax Amount
Foreign currency translation losses on net investment in foreign operations	(205	)	(2	)	(207	)
Change in fair value of net investment hedges	(10	)	2		(8	)
Change in fair value of cash flow hedges	27		(11	)	16
Reclassification to net income of gains and losses on cash flow hedges	64		(24	)	40
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	11		(3	)	8
Other comprehensive income on equity investments	9		(2	)	7
Other comprehensive loss	(104	)	(40	)	(144	)

The changes in AOCI by component are as follows:

three months ended June 30, 2017	Currency				Pension and
(unaudited - millions of Canadian $)	Translation Adjustments		Cash Flow Hedges		OPEB Plan Adjustments		Equity Investments		Total1
AOCI balance at April 1, 2017	(418	)	(24	)	(205	)	(345	)	(992	)
Other comprehensive loss before reclassifications2	(221	)	(2	)	—		—		(223	)
Amounts reclassified from accumulated other comprehensive loss	(77	)	(1	)	4		—		(74	)
Net current period other comprehensive (loss)/income	(298	)	(3	)	4		—		(297	)
AOCI balance at June 30, 2017	(716	)	(27	)	(201	)	(345	)	(1,289	)

¹  All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

²  Other comprehensive loss before reclassifications on currency translation adjustments is net of non-controlling interest losses of $49 million.

six months ended June 30, 2017	Currency				Pension and
(unaudited - millions of Canadian $)	Translation Adjustments		Cash Flow Hedges		OPEB Plan Adjustments		Equity Investments		Total1
AOCI balance at January 1, 2017	(376	)	(28	)	(208	)	(348	)	(960	)
Other comprehensive (loss)/income before reclassifications2	(263	)	2		—		—		(261	)
Amounts reclassified from accumulated other comprehensive loss	(77	)	(1	)	7		3		(68	)
Net current period other comprehensive (loss)/income3	(340	)	1		7		3		(329	)
AOCI balance at June 30, 2017	(716	)	(27	)	(201	)	(345	)	(1,289	)

¹  All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

²  Other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $90 million and gains of $1 million, respectively.

³  Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $9 million ($6 million, net of tax) at June 30, 2017. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

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SECOND QUARTER 2017

Details about reclassifications out of AOCI into the consolidated statement of income are as follows: 

	Amounts reclassified from accumulated other comprehensive loss1								Affected line item in the condensed consolidated statement of income
	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $)	2017		2016		2017		2016
Cash flow hedges
Commodities	7		21		11		(61	)	Revenue (Energy)
Foreign exchange	—		39		—		5		Interest income and other
Interest rate	(5	)	(4	)	(9	)	(8	)	Interest expense
	2		56		2		(64	)	Total before tax
	(1	)	(16	)	(1	)	24		Income tax expense
	1		40		1		(40	)	Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial loss	(4	)	(6	)	(8	)	(11	)	Plant operating costs 2
	1		2		3		3		Income tax expense
	(3	)	(4	)	(5	)	(8	)	Net of tax
Equity investments
Equity income	—		(5	)	(4	)	(9	)	Income from equity investments
	—		1		1		2		Income tax expense
	—		(4	)	(3	)	(7	)	Net of tax
Currency translation adjustments
Realization of foreign currency translation gain on disposal of foreign operations	77		—		77		—		Gain/(loss) on sale of assets
	—		—		—		—		Income tax expense
	77		—		77		—		Net of tax

¹  All amounts in parentheses indicate expenses to the condensed consolidated statement of income.

²  These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 9 for additional detail.

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SECOND QUARTER 2017

9. Employee post-retirement benefits

The net benefit cost recognized for the Company’s defined benefit pension plans (DB Plan) and other post-retirement benefit plans is as follows:

	three months ended June 30								six months ended June 30
	Pension benefit plans				Other post-retirement benefit plans				Pension benefit plans				Other post-retirement benefit plans
(unaudited - millions of Canadian $)	2017		2016		2017		2016		2017		2016		2017		2016
Service cost	27		25		1		—		56		51		2		1
Interest cost	28		29		3		3		62		59		7		5
Expected return on plan assets	(39	)	(39	)	(6	)	(1	)	(89	)	(79	)	(11	)	(1	)
Amortization of actuarial loss	4		6		—		—		8		10		—		1
Amortization of regulatory asset	1		5		1		—		7		9		1		—
Amortization of transitional obligation related to regulated business	—		—		—		1		—		—		—		1
Net benefit cost recognized	21		26		(1	)	3		44		50		(1	)	7

Effective April 1, 2017, the Company closed its U.S. DB Plan to non-union new entrants. As of April 1, 2017, all non-union hires will participate in the existing defined contribution plan (DC Plan). Non-union U.S. employees who currently participate in the DC Plan will have one final election opportunity to become a member of the DB Plan as of January 1, 2018.

10. Risk management and financial instruments 

RISK MANAGEMENT OVERVIEW

TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings and cash flow.

COUNTERPARTY CREDIT RISK

TransCanada’s maximum counterparty credit exposure with respect to financial instruments at June 30, 2017, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At June 30, 2017, there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the period.

LOAN RECEIVABLE FROM AFFILIATE

Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

TransCanada holds a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline for which it accounts as an equity investment. On April 21, 2017, TransCanada issued a peso-denominated unsecured revolving credit facility to the joint venture. This $1 billion facility bears interest at a floating interest rate per annum. As at June 30, 2017, Intangible and other assets on the Company’s condensed consolidated balance sheet included a $341 million loan receivable from the Sur de Texas joint venture (December 31, 2016 - nil). This loan receivable represents TransCanada’s proportionate share of its affiliate’s debt financing requirements and is included in Contributions to equity investments on the Company's condensed consolidated statement of cash flows.

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SECOND QUARTER 2017

Interest income and other included $3 million in the three and six months ended June 30, 2017 as a result of inter-affiliate lending to the Sur de Texas joint venture (2016 - nil and nil).

NET INVESTMENT IN FOREIGN OPERATIONS

The Company hedges its 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 and options.

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

The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows:

(unaudited - millions of Canadian $, unless noted otherwise)	June 30, 2017	December 31, 2016
Notional amount	25,000 (US 19,300)	26,600 (US 19,800)
Fair value	28,500 (US 22,000)	29,400 (US 21,900)

Derivatives designated as a net investment hedge

The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows:

	June 30, 2017			December 31, 2016
(unaudited - millions of Canadian $, unless noted otherwise)	Fair value1		Notional or principal amount	Fair value1		Notional or principal amount
U.S. dollar cross-currency interest rate swaps (maturing 2017 to 2019)2	(240	)	US 1,500	(425	)	US 2,350
U.S. dollar foreign exchange forward contracts	—		—	(7	)	US 150
	(240	)	US 1,500	(432	)	US 2,500

¹  Fair values equal carrying values.

²  In the three and six months endedJune 30, 2017, net realized gains of $1 million and $2 million, respectively, (2016 - gains of $2 million and $4 million, respectively) related to the interest component of cross-currency swap settlements are included in interest expense.

FINANCIAL INSTRUMENTS

Non-derivative financial instruments

Fair value of non-derivative financial instruments

The fair value of Long-term debt and Junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers.

Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in 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 also be classified in Level II of the fair value hierarchy.

Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

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Balance sheet presentation of non-derivative financial instruments

The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy: 

	June 30, 2017				December 31, 2016
(unaudited - millions of Canadian $)	Carrying amount		Fair value		Carrying amount		Fair value
Notes receivable1	—		—		165		211
Long-term debt including current portion2,3	(34,546	)	(39,892	)	(40,150	)	(45,047	)
Junior subordinated notes	(7,218	)	(7,505	)	(3,931	)	(3,825	)
	(41,764	)	(47,397	)	(43,916	)	(48,661	)

¹  Notes receivable was included in Assets held for sale at December 31, 2016 on the condensed consolidated balance sheet. The fair value was calculated based on the original contract terms.

²  Long-term debt is recorded at amortized cost except for US$850 million (December 31, 2016 - US$850 million) that is attributed to hedged risk and recorded at fair value.

³  Consolidated net income for the three and six months endedJune 30, 2017 included unrealized losses of $1 million and unrealized gains of $1 million, respectively, (2016 - unrealized losses of $1 million and $13 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of long-term debt at June 30, 2017 (December 31, 2016 - US$850 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

Available for sale assets summary

The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets:

	June 30, 2017		December 31, 2016
(unaudited - millions of Canadian $)	LMCI restricted investments	Other restricted investments2	LMCI restricted investments	Other restricted investments2
Fair Values1
Fixed income securities (maturing within 1 year)	—	30	—	19
Fixed income securities (maturing within 1-5 years)	—	107	—	117
Fixed income securities (maturing within 5-10 years)	15	—	9	—
Fixed income securities (maturing after 10 years)	659	—	513	—
	674	137	522	136

¹  Available for sale assets are recorded at fair value and included in other current assets and restricted investments on the condensed consolidated balance sheet.

²  Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

	June 30, 2017			June 30, 2016
(unaudited - millions of Canadian $)	LMCI restricted investments1		Other restricted investments2	LMCI restricted investments1	Other restricted investments2
Net unrealized gains in the period
three months ended	13		—	17	—
six months ended	15		—	22	1
Net realized losses in the period
three months ended	(1	)	—	—	—
six months ended	(1	)	—	—	—

¹  Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities.

²  Unrealized gains and losses on other restricted investments are included in OCI.

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Derivative instruments

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 commodity 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. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the 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 as at June 30, 2017 is as follows:

at June 30, 2017	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments1
(unaudited - millions of Canadian $)
Other current assets
Commodities2	4		—		—		268		272
Foreign exchange	—		—		3		42		45
Interest rate	2		—		—		1		3
	6		—		3		311		320
Intangible and other assets
Commodities2	1		—		—		121		122
Foreign exchange	—		—		4		—		4
	1		—		4		121		126
Total Derivative Assets	7		—		7		432		446
Accounts payable and other
Commodities2	(1	)	—		—		(354	)	(355	)
Foreign exchange	—		—		(162	)	(13	)	(175	)
Interest rate	—		(2	)	—		—		(2	)
	(1	)	(2	)	(162	)	(367	)	(532	)
Other long-term liabilities
Commodities2	—		—		—		(162	)	(162	)
Foreign exchange	—		—		(85	)	—		(85	)
Interest rate	—		(1	)	—		—		(1	)
	—		(1	)	(85	)	(162	)	(248	)
Total Derivative Liabilities	(1	)	(3	)	(247	)	(529	)	(780	)
Total Derivatives	6		(3	)	(240	)	(97	)	(334	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power, natural gas and liquids.

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The balance sheet classification of the fair value of the derivative instruments as at December 31, 2016 is as follows:

at December 31, 2016	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments1
(unaudited - millions of Canadian $)
Other current assets
Commodities2	6		—		—		351		357
Foreign exchange	—		—		6		10		16
Interest rate	1		1		—		1		3
	7		1		6		362		376
Intangible and other assets
Commodities2	4		—		—		118		122
Foreign exchange	—		—		10		—		10
Interest rate	1		—		—		—		1
	5		—		10		118		133
Total Derivative Assets	12		1		16		480		509
Accounts payable and other
Commodities2	—		—		—		(330	)	(330	)
Foreign exchange	—		—		(237	)	(38	)	(275	)
Interest rate	(1	)	(1	)	—		—		(2	)
	(1	)	(1	)	(237	)	(368	)	(607	)
Other long-term liabilities
Commodities2	—		—		—		(118	)	(118	)
Foreign exchange	—		—		(211	)	—		(211	)
Interest rate	—		(1	)	—		—		(1	)
	—		(1	)	(211	)	(118	)	(330	)
Total Derivative Liabilities	(1	)	(2	)	(448	)	(486	)	(937	)
Total Derivatives	11		(1	)	(432	)	(6	)	(428	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power, natural gas and liquids.

The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.

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SECOND QUARTER 2017

Notional and Maturity Summary

The maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows:

at June 30, 2017	Power	Natural Gas	Liquids	Foreign Exchange	Interest
(unaudited)
Purchases1	103,510	186	12	—	—
Sales1	65,642	167	13	—	—
Millions of U.S. dollars	—	—	—	US 2,722	US 1,550
Millions of Mexican pesos	—	—	—	MXN 300	—
Maturity dates	2017-2021	2017-2020	2017	2017-2018	2017-2019

¹  Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.

at December 31, 2016	Power	Natural Gas	Liquids	Foreign Exchange	Interest
(unaudited)
Purchases1	86,887	182	6	—	—
Sales1	58,561	147	6	—	—
Millions of U.S. dollars	—	—	—	US 2,394	US 1,550
Maturity dates	2017-2021	2017-2020	2017	2017	2017-2019

¹  Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.

Unrealized and Realized (Losses)/Gains of Derivative Instruments

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

	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $)	2017		2016		2017		2016
Derivative instruments held for trading1
Amount of unrealized (losses)/gains in the period
Commodities2	(91	)	187		(147	)	120
Foreign exchange	41		20		56		47
Interest rate	—		—		—		—
Amount of realized (losses)/gains in the period
Commodities	(37	)	(47	)	(85	)	(142	)
Foreign exchange	(5	)	13		(9	)	57
Derivative instruments in hedging relationships
Amount of realized gains/(losses) in the period
Commodities	7		(67	)	13		(140	)
Foreign exchange	—		(43	)	5		(106	)
Interest rate	—		1		1		3

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 derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively.

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

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SECOND QUARTER 2017

Derivatives in cash flow hedging relationships

The components of OCI (Note 8) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: 

	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $, pre-tax)	2017		2016		2017		2016
Change in fair value of derivative instruments recognized in OCI (effective portion)1
Commodities	(2	)	42		3		26
Foreign exchange	—		40		—		5
Interest rate	—		(1	)	1		(4	)
	(2	)	81		4		27
Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)1
Commodities2	(7	)	(21	)	(11	)	61
Foreign exchange3	—		(39	)	—		(5	)
Interest rate4	5		4		9		8
	(2	)	(56	)	(2	)	64
Gains/(losses) on derivative instruments recognized in net income (ineffective portion)
Commodities2	—		43		—		(15	)
	—		43		—		(15	)

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.

Offsetting of derivative instruments

The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:

at June 30, 2017	Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative - Asset
Commodities	394		(313	)	81
Foreign exchange	49		(43	)	6
Interest rate	3		(1	)	2
Total	446		(357	)	89
Derivative - Liability
Commodities	(517	)	313		(204	)
Foreign exchange	(260	)	43		(217	)
Interest rate	(3	)	1		(2	)
Total	(780	)	357		(423	)

¹  Amounts available for offset do not include cash collateral pledged or received.

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SECOND QUARTER 2017

The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2016:

at December 31, 2016	Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative - Asset
Commodities	479		(362	)	117
Foreign exchange	26		(26	)	—
Interest rate	4		(1	)	3
Total	509		(389	)	120
Derivative - Liability
Commodities	(448	)	362		(86	)
Foreign exchange	(486	)	26		(460	)
Interest rate	(3	)	1		(2	)
Total	(937	)	389		(548	)

¹  Amounts available for offset do not include cash collateral pledged or received.

With respect to the derivative instruments presented above as at June 30, 2017, the Company provided cash collateral of $381 million (December 31, 2016 - $305 million) and letters of credit of $7 million (December 31, 2016 - $27 million) to its counterparties. The Company held nil (December 31, 2016 - nil) in cash collateral and $3 million (December 31, 2016 - $3 million) in letters of credit from counterparties on asset exposures at June 30, 2017. 

Credit risk related contingent features of derivative instruments

Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company’s credit rating to non-investment grade.

Based on contracts in place and market prices at June 30, 2017, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $11 million (December 31, 2016 - $19 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2016 - nil). If the credit-risk-related contingent features in these agreements were triggered on June 30, 2017, the Company would have been required to provide additional collateral of $11 million (December 31, 2016 - $19 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these contingent obligations should they arise.

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SECOND QUARTER 2017

FAIR VALUE HIERARCHY

The Company’s financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy.

Levels	How fair value has been determined
Level I	Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
Level II	Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly.  Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers.  This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances.
Level III	Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category mainly includes long-dated commodity transactions in certain markets where liquidity is low and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions. Valuation of options is based on the Black-Scholes pricing model.   Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which significant inputs are considered to be observable. As contracts near maturity and observable market data become available, they are transferred out of Level III and into Level II.

The fair value of the Company’s derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2017, are categorized as follows:

at June 30, 2017	Quoted prices in active markets		Significant other observable inputs		Significant unobservable inputs
(unaudited - millions of Canadian $)	(Level I)1		(Level II)1		(Level III)1		Total
Derivative instrument assets:
Commodities	42		325		27		394
Foreign exchange	—		49		—		49
Interest rate	—		3		—		3
Derivative instrument liabilities:
Commodities	(42	)	(457	)	(18	)	(517	)
Foreign exchange	—		(260	)	—		(260	)
Interest rate	—		(3	)	—		(3	)
	—		(343	)	9		(334	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the six months endedJune 30, 2017.

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SECOND QUARTER 2017

The fair value of the Company’s derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2016, are categorized as follows:

at December 31, 2016	Quoted prices in active markets (Level I)1		Significant other observable inputs (Level II)1		Significant unobservable inputs (Level III)1
(unaudited - millions of Canadian $)							Total
Derivative instrument assets:
Commodities	134		326		19		479
Foreign exchange	—		26		—		26
Interest rate	—		4		—		4
Derivative instrument liabilities:
Commodities	(102	)	(343	)	(3	)	(448	)
Foreign exchange	—		(486	)	—		(486	)
Interest rate	—		(3	)	—		(3	)
	32		(476	)	16		(428	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016.

The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy:

	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $)	2017		2016		2017		2016
Balance at beginning of period	10		9		16		9
Settlements	5		(4	)	5		(3	)
Sales	(3	)	—		(5	)	(1	)
Total (losses)/gains included in net income	(2	)	7		(2	)	10
Transfers out of Level III	(1	)	—		(5	)	(3	)
Balance at end of period1	9		12		9		12

¹  For the three and six months endedJune 30, 2017, revenues include unrealized losses of $1 million and gains of $1 million, respectively, attributed to derivatives in the Level III category that were still held at June 30, 2017 (2016 - gains of $6 million and $8 million, respectively).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $1 millionincrease or $3 milliondecrease, respectively, in the fair value of outstanding derivative instruments included in Level III as at June 30, 2017. 

11. Acquisitions & Dispositions

U.S. Natural Gas Pipelines

Iroquois Gas Transmission System and Gas Transmission Northwest LLC

On June 1, 2017, TransCanada completed the sale of its 49.34 per cent interest in Iroquois and its remaining 11.81 per cent interest in PNGTS to TC PipeLines LP, valued at US$765 million. Proceeds were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and PNGTS debt.

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SECOND QUARTER 2017

Columbia Pipeline Group

In second quarter 2017, the Company completed its procedures over measuring the volume of base gas acquired as part of the acquisition of Columbia. As a result, the Company prospectively decreased the fair value of base gas by $116 million (US$90 million). This impacted the purchase price equation by decreasing property, plant and equipment by $116 million (US$90 million), decreasing deferred tax liabilities by $45 million (US$35 million) and increasing goodwill by $71 million (US$55 million). This adjustment did not impact the Company's net income.

Energy

U.S. Northeast Power Assets

On June 2, 2017, TransCanada completed the sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power for proceeds of approximatelyUS$2.029 billion, subject to post-closing adjustments. The Company recorded an additional loss on sale of $219 million ($176 million after tax) which included $2 million in foreign currency translation gains. The additional loss was primarily related to an adjustment to the purchase price and repair costs for an unplanned outage at Ravenswood prior to close. In 2016, the Company recorded a loss of approximately $829 million ($863 million after tax) which included the impact of an estimated $70 million of foreign currency translation gains. The actual foreign currency translation gains of $72 million were reclassified from AOCI to Net income on closing of the transaction.

On April 19, 2017, the Company completed the sale of TC Hydro for gross proceeds of US$1.07 billion, subject to post-closing adjustments. As a result, the Company recorded a gain on sale of approximately $717 million ($441 million after tax) including the impact of an estimated $5 million of foreign currency translation gains which were reclassified from AOCI to net income.

Gains and losses from these sales are included in Gain/(loss) on sale of assets in the condensed consolidated statement of income. The proceeds received from the sale of the U.S. Northeast Power Assets were used to fully repay the outstanding balances on the Company's acquisition bridge facilities that partially funded the acquisition of Columbia.

12. Commitments, contingencies and guarantees

COMMITMENTS

TransCanada's operating lease commitments at December 31, 2016 included future payments related to our U.S. Northeast power assets. As a result of the completion of the thermal sale on June 2, 2017, the remaining future obligations included at December 31, 2016 have decreased by: $2 million in 2017, $52 million in 2018, $34 million in 2019 and $102 million in 2022 and beyond.

CONTINGENCIES

TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company’s consolidated financial position or results of operations.

In March 2017, the U.S. Department of State issued a U.S. Presidential Permit authorizing construction of the U.S./Canada border crossing facilities of the Keystone XL pipeline. TransCanada discontinued the claim under Chapter 11 of the North American Free Trade Agreement and has also withdrawn the U.S. Constitutional challenge.

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SECOND QUARTER 2017

GUARANTEES

TransCanada and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the obligations for construction services during the construction of the pipeline.

TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services.

The Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, construction services and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

The carrying value of these guarantees has been included in other long-term liabilities. Information regarding the Company’s guarantees is as follows:

		at June 30, 2017		at December 31, 2016
(unaudited - millions of Canadian $)	Term	Potential exposure1	Carrying value	Potential exposure1	Carrying value
Sur de Texas	ranging to 2020	571	6	805	53
Bruce Power	ranging to 2018	88	1	88	1
Other jointly owned entities	ranging to 2059	107	14	87	28
		766	21	980	82

¹  TransCanada’s share of the potential estimated current or contingent exposure.

13. Variable interest entities

The Company consolidates a number of entities that are considered to be VIEs. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity.

In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are considered non-consolidated VIEs and are accounted for as equity investments.

Consolidated VIEs

The Company's consolidated VIEs consist of legal entities where the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE.

A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The assets and liabilities of the consolidated VIEs whose assets cannot be used for purposes other than the settlement of the VIE’s obligations are as follows:

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SECOND QUARTER 2017

	June 30,	December 31,
(unaudited - millions of Canadian $)	2017	2016
ASSETS
Current Assets
Cash and cash equivalents	66	77
Accounts receivable	59	71
Inventories	24	25
Other	8	10
	157	183
Plant, Property and Equipment	3,704	3,685
Equity Investments	861	606
Goodwill	508	525
Intangible and Other Assets	—	1
	5,230	5,000
LIABILITIES
Current Liabilities
Accounts payable and other	67	80
Accrued interest	23	21
Current portion of long-term debt	99	76
	189	177
Regulatory Liabilities	33	34
Other Long-Term Liabilities	3	4
Deferred Income Tax Liabilities	13	7
Long-Term Debt	3,353	2,827
	3,591	3,049

Non-Consolidated VIEs

The Company’s non-consolidated VIEs consist of legal entities where the Company does not have the power to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid.

The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows:

	June 30,	December 31,
(unaudited - millions of Canadian $)	2017	2016
Balance sheet
Equity investments	4,393	4,964
Off-balance sheet
Potential exposure to guarantees	173	163
Maximum exposure to loss	4,566	5,127

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SECOND QUARTER 2017

14. Subsequent event

On July 25, 2017, the Company was notified that PNW LNG would not be proceeding with their proposed LNG project.  As part of the PRGT agreement, following receipt of a termination notice, TransCanada would be reimbursed for the full costs and carrying charges incurred to advance the PRGT project. At June 30, 2017, approximately $0.5 billion was included in Intangible and other assets on the Company's condensed consolidated balance sheet.