EXHIBIT 13.2

Condensed consolidated statement of income

	three months ended March 31
(unaudited - millions of Canadian $, except per share amounts)	2018			2017
Revenues
Canadian Natural Gas Pipelines	884			882
U.S. Natural Gas Pipelines	1,091			994
Mexico Natural Gas Pipelines	151			143
Liquids Pipelines	623			472
Energy	675			916
	3,424			3,407
Income from Equity Investments	80			174
Operating and Other Expenses
Plant operating costs and other	874			1,006
Commodity purchases resold	597			543
Property taxes	150			162
Depreciation and amortization	535			517
	2,156			2,228
Financial Charges
Interest expense	527			500
Allowance for funds used during construction	(105		)	(101		)
Interest income and other	(63		)	(20		)
	359			379
Income before Income Taxes	989			974
Income Tax Expense
Current	50			67
Deferred	71			133
	121			200
Net Income	868			774
Net income attributable to non-controlling interests	94			90
Net Income Attributable to Controlling Interests	774			684
Preferred share dividends	40			41
Net Income Attributable to Common Shares	734			643
Net Income per Common Share
Basic and diluted		$0.83			$0.74
Dividends Declared per Common Share		$0.69			$0.625
Weighted Average Number of Common Shares (millions)
Basic	885			866
Diluted	886			868

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of comprehensive income

	three months ended March 31
(unaudited - millions of Canadian $)	2018		2017
Net Income	868		774
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations	432		(82	)
Change in fair value of net investment hedges	(2	)	(1	)
Change in fair value of cash flow hedges	7		5
Reclassification to net income of gains and losses on cash flow hedges	3		—
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	(2	)	3
Other comprehensive income on equity investments	6		3
Other comprehensive income/(loss)	444		(72	)
Comprehensive Income	1,312		702
Comprehensive income attributable to non-controlling interests	160		50
Comprehensive Income Attributable to Controlling Interests	1,152		652
Preferred share dividends	40		41
Comprehensive Income Attributable to Common Shares	1,112		611

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of cash flows

	three months ended March 31
(unaudited - millions of Canadian $)	2018		2017
Cash Generated from Operations
Net income	868		774
Depreciation and amortization	535		517
Deferred income taxes	71		133
Income from equity investments	(80	)	(174	)
Distributions received from operating activities of equity investments	234		219
Employee post-retirement benefits funding, net of expense	3		3
Equity allowance for funds used during construction	(78	)	(64	)
Unrealized losses on financial instruments	188		41
Other	(122	)	8
Increase in operating working capital	(207	)	(155	)
Net cash provided by operations	1,412		1,302
Investing Activities
Capital expenditures	(1,702	)	(1,560	)
Capital projects in development	(36	)	(42	)
Contributions to equity investments	(358	)	(192	)
Other distributions from equity investments	121		363
Deferred amounts and other	110		(85	)
Net cash used in investing activities	(1,865	)	(1,516	)
Financing Activities
Notes payable issued, net	1,812		670
Long-term debt issued, net of issue costs	93		—
Long-term debt repaid	(1,226	)	(1,051	)
Junior subordinated notes issued, net of issue costs	—		1,982
Dividends on common shares	(358	)	(300	)
Dividends on preferred shares	(39	)	(39	)
Distributions paid to non-controlling interests	(69	)	(80	)
Common shares issued, net of issue costs	340		18
Partnership units of TC PipeLines, LP issued, net of issue costs	49		92
Common units of Columbia Pipeline Partners LP acquired	—		(1,205	)
Net cash provided by financing activities	602		87
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	29		5
Increase/(Decrease) in Cash and Cash Equivalents	178		(122	)
Cash and Cash Equivalents
Beginning of period	1,089		1,016
Cash and Cash Equivalents
End of period	1,267		894

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated balance sheet

		March 31,		December 31,
(unaudited - millions of Canadian $)		2018		2017
ASSETS
Current Assets
Cash and cash equivalents		1,267		1,089
Accounts receivable		2,208		2,522
Inventories		384		378
Other		718		691
		4,577		4,680
Plant, Property and Equipment	net of accumulated depreciation of $24,416 and $23,734, respectively	59,313		57,277
Equity Investments		6,362		6,366
Regulatory Assets		1,334		1,376
Goodwill		13,483		13,084
Loan Receivable from Affiliate		1,211		919
Intangible and Other Assets		1,725		1,484
Restricted Investments		1,005		915
		89,010		86,101
LIABILITIES
Current Liabilities
Notes payable		3,658		1,763
Accounts payable and other		3,697		4,057
Dividends payable		631		586
Accrued interest		552		605
Current portion of long-term debt		3,406		2,866
		11,944		9,877
Regulatory Liabilities		4,473		4,321
Other Long-Term Liabilities		712		727
Deferred Income Tax Liabilities		5,529		5,403
Long-Term Debt		30,995		31,875
Junior Subordinated Notes		7,177		7,007
		60,830		59,210
EQUITY
Common shares, no par value		21,703		21,167
Issued and outstanding:	March 31, 2018 - 891 million shares
	December 31, 2017 - 881 million shares
Preferred shares		3,980		3,980
Additional paid-in capital		10		—
Retained earnings		1,859		1,623
Accumulated other comprehensive loss		(1,353	)	(1,731	)
Controlling Interests		26,199		25,039
Non-controlling interests		1,981		1,852
		28,180		26,891
		89,010		86,101

Contingencies and Guarantees (Note 12)

Variable Interest Entities (Note 13)

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of equity

	three months ended March 31
(unaudited - millions of Canadian $)	2018		2017
Common Shares
Balance at beginning of period	21,167		20,099
Shares issued:
Under at-the-market equity issuance program, net of issue costs	327		—
Under dividend reinvestment and share purchase plan	195		190
On exercise of stock options	14		19
Balance at end of period	21,703		20,308
Preferred Shares
Balance at beginning and end of period	3,980		3,980
Additional Paid-In Capital
Balance at beginning of period	—		—
Issuance of stock options, net of exercises	3		2
Dilution from TC PipeLines, LP units issued	7		10
Columbia Pipeline Partners LP acquisition	—		(171	)
Reclassification of additional paid-in capital deficit to retained earnings	—		159
Balance at end of period	10		—
Retained Earnings
Balance at beginning of period	1,623		1,138
Net income attributable to controlling interests	774		684
Common share dividends	(614	)	(542	)
Preferred share dividends	(19	)	(18	)
Adjustment related to income tax effects of asset drop downs to TC PipeLines, LP	95		—
Adjustment related to employee share-based payments	—		12
Reclassification of additional paid-in capital deficit to retained earnings	—		(159	)
Balance at end of period	1,859		1,115
Accumulated Other Comprehensive Loss
Balance at beginning of period	(1,731	)	(960	)
Other comprehensive income/(loss)	378		(32	)
Balance at end of period	(1,353	)	(992	)
Equity Attributable to Controlling Interests	26,199		24,411
Equity Attributable to Non-Controlling Interests
Balance at beginning of period	1,852		1,726
Net income attributable to non-controlling interests	94		90
Other comprehensive income/(loss) attributable to non-controlling interests	66		(40	)
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs	49		92
Decrease in TransCanada's ownership of TC PipeLines, LP	(9	)	(17	)
Distributions declared to non-controlling interests	(71	)	(80	)
Reclassification from common units of TC PipeLines, LP subject to rescission	—		24
Impact of Columbia Pipeline Partners LP acquisition	—		33
Balance at end of period	1,981		1,828
Total Equity	28,180		26,239

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, 2017, 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 2017 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 2017 audited consolidated financial statements included in TransCanada’s 2017 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 annual audited consolidated financial statements for the year ended December 31, 2017, except as described in Note 2, Accounting changes.

2. Accounting changes

CHANGES IN ACCOUNTING POLICIES FOR 2018

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 from these contracts in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in amounts that reflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as the Company's "performance obligations." The total consideration to which the Company expects to be entitled can include fixed and variable amounts. The Company has variable revenue that is subject to factors outside the Company’s influence, such as market prices, actions of third parties and weather conditions. The Company considers this variable revenue to be "constrained" as it cannot be reliably estimated, and therefore recognizes variable revenue when the service is provided.

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The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and related cash flows.

In the application of the new guidance, significant estimates and judgments are used to determine the following:

• pattern of revenue recognition, whether the performance obligation is satisfied at a point in time versus over time within a contract

• term of the contract

• amount of variable consideration associated with a contract and timing of the associated revenue recognition.

The new guidance was effective January 1, 2018, was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition. Refer to Note 4, Revenues, for further information related to the impact of adopting the new guidance and the Company's updated accounting policies related to revenue recognition from contracts with customers.

Financial instruments

In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance changes 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 was effective January 1, 2018, and did not have a material impact on the Company's 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 was effective January 1, 2018, was applied using a modified retrospective approach, and did not have a material impact on the Company's consolidated financial statements.

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 was effective January 1, 2018, was applied retrospectively, and did not have an impact on the Company's consolidated financial statements.

Employee post-retirement benefits

In March 2017, the FASB issued new guidance that requires 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 was effective January 1, 2018 and did not have a material impact on the Company's consolidated financial statements.

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Hedge accounting

In August 2017, the FASB issued new guidance making more financial and non-financial hedging strategies eligible for hedge accounting. The new guidance also amends the presentation requirements relating to the change in fair value of a derivative and requires additional disclosures including cumulative basis adjustments for fair value hedges and the effect of hedging on individual line items in the consolidated statement of income. This new guidance is effective January 1, 2019, with early adoption permitted. This new guidance, which the Company elected to adopt effective January 1, 2018, was applied prospectively and did not have a material impact on the Company's consolidated financial statements.

FUTURE ACCOUNTING CHANGES

Leases

In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessor is required 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. 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 consolidated statement of income. The new guidance does not make extensive changes to lessor accounting.

In January 2018, the FASB issued an optional practical expedient, to be applied upon transition, to omit the evaluation of land easements not previously accounted for as leases that existed or expired prior to the entity's adoption of the new lease guidance. An entity that elects this practical expedient is required to apply the practical expedient consistently to all of its existing or expired land easements not previously accounted for as leases. The Company continues to monitor and analyze additional guidance and clarifications provided by the FASB.

The new guidance is effective 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 application of the new guidance on its consolidated financial statements. The Company has also selected a system solution and continues to assess 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 as 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.

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. The Company is currently evaluating the timing and impact of the adoption of this guidance.

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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.

Income Taxes

In February 2018, the FASB issued new guidance that allows a reclassification from AOCI to retained earnings for stranded tax effects resulting from the U.S. Tax Cuts and Jobs Act. This new guidance is effective January 1, 2019, however, early adoption is permitted. This guidance can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change is recognized. The Company is currently evaluating this guidance.

3. Segmented information

three months ended March 31, 2018	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines
(unaudited - millions of Canadian $)									Energy		Corporate1			Total
Revenues	884		1,091		151		623		675		—			3,424
Intersegment revenues	—		25		—		—		42		(67	)	2	—
	884		1,116		151		623		717		(67	)		3,424
Income/(loss) from equity investments	3		67		11		15		63		(79	)	3	80
Plant operating costs and other	(323	)	(324	)	(2	)	(191	)	(99	)	65		2	(874	)
Commodity purchases resold	—		—		—		—		(597	)	—			(597	)
Property taxes	(70	)	(55	)	—		(23	)	(2	)	—			(150	)
Depreciation and amortization	(241	)	(156	)	(23	)	(83	)	(32	)	—			(535	)
Segmented Earnings/(Loss)	253		648		137		341		50		(81	)		1,348
Interest expense														(527	)
Allowance for funds used during construction														105
Interest income and other														63
Income before income taxes														989
Income tax expense														(121	)
Net Income														868
Net income attributable to non-controlling interests														(94	)
Net Income Attributable to Controlling Interests														774
Preferred share dividends														(40	)
Net Income Attributable to Common Shares														734

1 Includes intersegment eliminations.

2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

3 Income/(loss) from equity investments includes foreign exchange losses on the Company's inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture.

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three months ended March 31, 2017	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines
(unaudited - millions of Canadian $)									Energy		Corporate1			Total
Revenues	882		994		143		472		916		—			3,407
Intersegment revenues	—		11		—		—		—		(11	)	2	—
	882		1,005		143		472		916		(11	)		3,407
Income from equity investments	3		65		6		—		100		—			174
Plant operating costs and other	(312	)	(306	)	(9	)	(145	)	(212	)	(22	)	2	(1,006	)
Commodity purchases resold	—		—		—		—		(543	)	—			(543	)
Property taxes	(69	)	(47	)	—		(23	)	(23	)	—			(162	)
Depreciation and amortization	(222	)	(156	)	(22	)	(77	)	(40	)	—			(517	)
Segmented Earnings/(Loss)	282		561		118		227		198		(33	)		1,353
Interest expense														(500	)
Allowance for funds used during construction														101
Interest income and other														20
Income before income taxes														974
Income tax expense														(200	)
Net Income														774
Net income attributable to non-controlling interests														(90	)
Net Income Attributable to Controlling Interests														684
Preferred share dividends														(41	)
Net Income Attributable to Common Shares														643

1 Includes intersegment eliminations.

2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

TOTAL ASSETS

(unaudited - millions of Canadian $)	March 31, 2018	December 31, 2017
Canadian Natural Gas Pipelines	17,171	16,904
U.S. Natural Gas Pipelines	37,586	35,898
Mexico Natural Gas Pipelines	5,931	5,716
Liquids Pipelines	15,916	15,438
Energy	8,376	8,503
Corporate	4,030	3,642
	89,010	86,101

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4. Revenues

In 2014, the FASB issued new guidance on revenue from contracts with customers. The Company adopted the new guidance on January 1, 2018 using the modified retrospective transition method for all contracts that were in effect on the date of adoption. Results reported for 2018 reflect the application of the new guidance, while the 2017 comparative results were prepared and reported under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP."

DISAGGREGATION OF REVENUES

The following table summarizes total Revenues for the three months ended March 31, 2018:

three months ended March 31, 2018 (unaudited - millions of Canadian $)	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines	Energy	Total
Revenues from contracts with customers
Capacity arrangements and transportation	884	884	150	534	—	2,452
Power generation	—	—	—	—	590	590
Natural gas storage and other	—	192	1	1	30	224
	884	1,076	151	535	620	3,266
Other revenues1,2	—	15	—	88	55	158
	884	1,091	151	623	675	3,424

1 Other revenues includes income from the Company's financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 11, Risk management and financial instruments, for further information on income from financial instruments.

2 Other revenues from U.S. Natural Gas Pipelines includes the amortization of the regulatory liability resulting from U.S. Tax Reform. Refer to Note 6, Income taxes, for further information.

Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities. The Company's contracts with customers include capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other contracts.

Canadian Natural Gas Pipelines

Capacity Arrangements and Transportation

Revenues from the Company's Canadian natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed.

Revenues from the Company's Canadian natural gas pipelines are subject to regulatory decisions by the NEB. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural gas capacity for transportation services, which includes a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are generally not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future tolls. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenues are recorded when the NEB decision is received. Canadian natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers.

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U.S. Natural Gas Pipelines

Capacity Arrangements and Transportation

Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Company has elected to utilize the practical expedient to recognize revenues as invoiced.

The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers.

Natural Gas Storage and Other

Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage including specifications with regards to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores for customers.

Revenues from the Company's midstream natural gas services, including gathering, treating, conditioning, processing, compression and liquids handling services, are generated from contractual arrangements and are recognized ratably over the term of the contract. The Company also owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas is produced. Midstream natural gas service revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas for which it provides midstream services.

Mexico Natural Gas Pipelines

Capacity Arrangements and Transportation

Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. For certain firm capacity arrangements, the Company has elected to utilize the practical expedient to recognize revenues as invoiced. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Other volumes shipped on these pipelines are subject to CRE-approved tariffs and revenues are recognized when the Company has performed the transportation services. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers.

Liquids Pipelines

Capacity Arrangements and Transportation

Revenues from the Company's liquids pipelines are generated mainly from providing customers with firm capacity arrangements to transport crude oil. The performance obligation in these contracts is the reservation of a specified amount of capacity together with the transportation of crude oil on a monthly basis. Revenues earned from these arrangements are recognized ratably over the term of the contract regardless of the amount of crude oil that is transported. Revenues for interruptible or volumetric-based services are recognized when the service is performed. Liquids pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the crude oil that it transports for customers.

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Energy

Power Generation

Revenues from the Company's Energy business are primarily derived from long-term contractual commitments to provide power capacity to meet the demands of the market, and from the sale of electricity to both centralized markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are invoiced and received on a monthly basis.

Natural Gas Storage and Other

Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Park and loan contracts allow for fixed injection or withdrawal volumes on specified dates for a specified price. Term storage contracts allow for a maximum amount of gas to be stored over a set period of time. Revenues from park and loan contracts are recognized and invoiced as the injection and withdrawal services are provided and revenues from term storage contracts are recognized ratably over the term of the contract. Term storage revenues are invoiced and received on a monthly basis. Revenues earned from the sale of proprietary natural gas are recognized in the month of delivery. Revenues from ancillary services are recognized as the service is provided. The Company does not take ownership of the natural gas that it stores for customers.

FINANCIAL STATEMENT IMPACT OF ADOPTING REVENUE FROM CONTRACTS WITH CUSTOMERS

The Company adopted the new guidance using the modified retrospective transition method.As a practical expedient under this transition method, the Company is not required to analyze completed contracts at the date of adoption. As a result, the Company made the following adjustments on January 1, 2018.

Capacity Arrangements and Transportation

For certain natural gas pipelines capacity contracts, amounts are invoiced to the customer in accordance with the terms of the contract, however, the related revenues are recognized when the Company satisfies its performance obligation to provide committed capacity ratably over the term of the contract. This difference in timing between revenue recognition and amounts invoiced creates a contract asset or contract liability under the new revenue recognition guidance. Under legacy U.S. GAAP, this difference was recorded as Accounts receivable.

Impact of New Revenue Recognition Guidance on Date of Adoption

The following table illustrates the impact of the adoption of the new revenue recognition guidance on the Company's previously reported consolidated balance sheet line items:

	As reported	Adjustment
(unaudited - millions of Canadian $)	December 31, 2017			January 1, 2018
Current Assets
Accounts receivable	2,522	(62	)	2,460
Other1	691	79		770
Current Liabilities
Accounts payable and other2	4,057	17		4,074

1 Adjustment relates to contract assets previously included in Accounts receivable.

2 Adjustment relates to contract liabilities previously included in Accounts receivable.

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Pro-forma Financial Statements under Legacy U.S. GAAP

As required by the new revenue recognition guidance, the following tables illustrate the pro-forma impact on the affected line items on the Condensed consolidated balance sheet, as at March 31, 2018, had legacy U.S. GAAP been applied:

	March 31, 2018
	As reported	Pro-forma using Legacy U.S. GAAP
(unaudited - millions of Canadian $)
Current Assets
Accounts receivable	2,208	2,358
Other	718	568

CONTRACT BALANCES

(unaudited - millions of Canadian $)	March 31, 2018	January 1, 2018
Receivables from contracts with customers	1,344	1,736
Contract assets1	150	79
Contract liabilities2	6	17
Long-term contract liabilities3	7	—

1 Recorded as part of Other current assets on the Condensed consolidated balance sheet.

2 Comprised of deferred revenue recorded in Accounts payable and other on the Condensed consolidated balance sheet. During the three months ended March 31, 2018, $17 million of revenue was recognized that was included in the contract liability at the beginning of the period.

3 Comprised of deferred revenue recorded in Other long-term liabilities on the Condensed consolidated balance sheet.

Contract assets primarily relate to the Company’s right to revenues for services completed but not invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in Contract assets is primarily related to the transfer to Accounts receivable when the rights become unconditional and the customer is invoiced as well as the recognition of additional revenues that remains to be invoiced.

FUTURE REVENUES FROM REMAINING PERFORMANCE OBLIGATIONS

As required by the new revenue recognition guidance, the following provides disclosure on future revenues allocated to remaining performance obligations representing contracted revenues that have not yet been recognized. Certain contracts that qualify for the use of one of the following practical expedients are excluded from the future revenues disclosures:

1) The original expected duration of the contract is one year or less.

2) The Company recognizes revenue from the contract that is equal to the amount invoiced, where the amount invoiced represents the value to the customer of the service performed to date. This is referred to as the "right to invoice" practical expedient.

3) The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time.

The following provides a discussion of the transaction price allocated to future performance obligations as well as practical expedients used by the Company.

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Capacity Arrangements and Transportation

As at March 31, 2018, future revenues from long-term capacity arrangements and transportation contracts extending through 2043 are approximately $30.5 billion, of which approximately $4.2 billion is expected to be recognized during the remainder of 2018.

Future revenues from long-term capacity arrangements and transportation contracts do not include constrained variable revenues or arrangements to which the right to invoice practical expedient has been applied. As a result, these amounts are not representative of potential total future revenues expected from these contracts.

Future revenues from the Company's Canadian natural gas pipelines' regulated firm capacity contracts include fixed revenues for the time periods that tolls under current rate settlements are in effect, which is approximately one to three years. Many of these contracts are long-term in nature and revenues from the remaining performance obligations that extend beyond the current rate settlement term are considered to be fully constrained since future tolls remain unknown. Revenues from these contracts will be recognized once the performance obligation to provide capacity has been satisfied and the regulator has approved the applicable tolls. In addition, the Company considers interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. These variable revenues are recognized on a monthly basis when the Company satisfies the performance obligation and have been excluded from the future revenues disclosure as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts is allocated entirely to unsatisfied performance obligations at March 31, 2018.

The Company also applies the right to invoice practical expedient to U.S. and certain Mexico regulated natural gas pipeline capacity arrangements and flow-through revenues. Revenues from regulated capacity arrangements are recognized based on current rates and flow-through revenues are earned from the recovery of operating expenses. These revenues are recognized on a monthly basis as the Company performs the services and are excluded from future revenues disclosures.

Revenues from liquids pipelines capacity arrangements have a variable component based on volumes transported. As a result, these variable revenues are excluded from the future revenues disclosures as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts is allocated entirely to unsatisfied performance obligations at March 31, 2018.

Power Generation

The Company has long-term power generation contracts extending through 2032. Revenues from power generation have a variable component related to market prices that are subject to factors outside the Company’s influence. These revenues are considered to be fully constrained and are recognized on a monthly basis when the Company satisfies the performance obligation. The Company applies the practical expedient related to variable revenues to these contracts. As a result, future revenues from these contracts are excluded from the disclosures.

Natural Gas Storage and Other

As at March 31, 2018, future revenues from long-term natural gas storage and other contracts extending through 2033, are approximately $1.4 billion, of which approximately $378 million is expected to be recognized during the remainder of 2018. The Company applies the practical expedients related to contracts that are for a duration of one year or less and where we have variable consideration, and therefore excludes the related revenues from the future revenues disclosure. As a result, this amount is lower than the potential total future revenues from these contracts.

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5. Plant, Property and Equipment, Equity Investments and Goodwill

The Company reviews plant, property and equipment and equity investments for impairment whenever events or changes in circumstances indicate the carrying value of the asset may not be recoverable.

Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstance indicate that it might be impaired. The Company can initially make this assessment based on qualitative factors. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, then an impairment test is not performed.

On March 15, 2018, FERC proposed changes related to U.S. Tax Reform and income taxes for ratemaking purposes in a master limited partnership (MLP) that may have an impact on the future earnings and cash flows of FERC-regulated pipelines. Until these pronouncements are finalized and implementation requirements are clarified, including the applicability to assets partially-owned by a MLP or held in non-MLP structures, and the Company and TC PipeLines, LP have fully evaluated their respective alternatives to minimize the impact of the proposed FERC changes, the Company believes that it is not more likely than not that the fair value of any of its reporting units is less than its respective carrying value. Therefore, a goodwill impairment test was not performed. Also, the Company has determined there is no indication that the carrying values of plant, property and equipment and equity investments potentially impacted by FERC's proposals are not recoverable. The Company will continue to monitor developments and assess its goodwill for impairment. The Company will also review its plant, property and equipment and equity investments for recoverability as new information becomes available.

At December 31, 2017, the estimated fair value of Great Lakes exceeded its carrying value by less than 10 per cent. There is a risk that the recent FERC developments, once finalized, could result in a goodwill impairment charge. The goodwill balance related to Great Lakes is US$573 million at March 31, 2018 (December 31, 2017 – US$573 million). There is also a risk that the goodwill balance related to Tuscarora of US$82 million at March 31, 2018 (December 31, 2017 – US$82 million) could be negatively impacted by the recent FERC developments.

6. Income taxes

U.S. Tax Reform

Pursuant to the enactment of U.S. Tax Reform, we recorded net regulatory liabilities and a corresponding reduction in net deferred income tax liabilities in the amount of $1,686 million at December 31, 2017 related to the Company's U.S. natural gas pipelines subject to rate-regulated accounting. Such amounts remain provisional as the Company's interpretation, assessment and presentation of the impact of U.S. Tax Reform may be further clarified with additional guidance from regulatory, tax and accounting authorities. Should additional guidance be provided by these authorities or other sources during the one-year measurement period permitted by the SEC, the Company will review the provisional amounts and adjust as appropriate. Other than the amortizations discussed below, no adjustments were made to these amounts during first quarter 2018. On March 15, 2018, FERC proposed changes related to U.S. Tax Reform and income taxes for ratemaking purposes in MLPs. There may be prospective adjustments to regulatory liabilities once these proposed changes are finalized and take effect.

Commencing January 1, 2018, the regulatory liabilities are being amortized using the Reverse South Georgia methodology. Under this methodology, rate-regulated entities determine amortization based on their composite depreciation rate and immediately begin recording amortization. Amortization of the net regulatory liability in the amount of $9 million was recorded in the three months ended March 31, 2018 and included in Revenues in the Condensed consolidated statement of income. 

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Effective Tax Rates

The effective tax rates for the three-month periods endedMarch 31, 2018 and 2017 were 12 per cent and 21 per cent, respectively. The lower effective tax rate in 2018 was primarily the result of the rate change resulting from U.S. Tax Reform and lower flow-through tax in Canadian rate-regulated pipelines.

7. Long-term debt

LONG-TERM DEBT RETIRED

The Company retired long-term debt in the three months ended March 31, 2018 as follows:

(unaudited - millions of Canadian $, unless noted otherwise) Company	Retirement date	Type	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	March 2018	Debentures	150	9.45	%
	January 2018	Senior Unsecured Notes	US 500	1.875	%
	January 2018	Senior Unsecured Notes	US 250	Floating
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
	March 2018	Senior Unsecured Notes	US 9	6.73	%

In the three months endedMarch 31, 2018, TransCanada capitalized interest related to capital projects of $26 million (2017 – $45 million).

8. Common shares

TRANSCANADA CORPORATION ATM EQUITY ISSUANCE PROGRAM

In the three months endedMarch 31, 2018, the Company issued 5.8 million common shares under the TransCanada ATM program at an average price of $56.51 per common share, for gross proceeds of $329 million. Related commissions and fees totaled approximately $3 million, resulting in net proceeds of $326 million. Subsequent to March 31, 2018, the Company issued an additional 1.6 million common shares at an average price of $52.52 per common share, for gross proceeds of $86 million.

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9. Other comprehensive income/(loss) and accumulated other comprehensive loss

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

three months ended March 31, 2018			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	416		16		432
Change in fair value of net investment hedges	(3	)	1		(2	)
Change in fair value of cash flow hedges	6		1		7
Reclassification to net income of gains and losses on cash flow hedges	4		(1	)	3
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	4		(6	)	(2	)
Other comprehensive income on equity investments	7		(1	)	6
Other comprehensive income	434		10		444

three months ended March 31, 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	(88	)	6		(82	)
Change in fair value of net investment hedges	(2	)	1		(1	)
Change in fair value of cash flow hedges	6		(1	)	5
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	5		(2	)	3
Other comprehensive income on equity investments	4		(1	)	3
Other comprehensive loss	(75	)	3		(72	)

The changes in AOCI by component are as follows:

three months ended March 31, 2018	Currency				Pension and
(unaudited - millions of Canadian $)	Translation Adjustments		Cash Flow Hedges		OPEB Plan Adjustments		Equity Investments		Total1
AOCI balance at January 1, 2018	(1,043	)	(31	)	(203	)	(454	)	(1,731	)
Other comprehensive income/(loss) before reclassifications2,3	373		(2	)	—		—		371
Amounts reclassified from accumulated other comprehensive loss	—		3		(2	)	6		7
Net current period other comprehensive income/(loss)	373		1		(2	)	6		378
AOCI balance at March 31, 2018	(670	)	(30	)	(205	)	(448	)	(1,353	)

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

2 Other comprehensive income/(loss) before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest gains of $57 million and $9 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 $22 million ($16 million, net of tax) at March 31, 2018. 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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Details about reclassifications out of AOCI into the Condensed consolidated statement of income are as follows: 

	Amounts Reclassified From AOCI1				Affected Line Item in the Condensed Consolidated Statement of Income
	three months ended March 31
(unaudited - millions of Canadian $)	2018		2017
Cash flow hedges
Commodities	1		4		Revenues (Energy)
Interest	(5	)	(4	)	Interest expense
	(4	)	—		Total before tax
	1		—		Income tax expense
	(3	)	—		Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial gains and losses	(4	)	(4	)	Plant operating costs and other2
	6		2		Income tax expense
	2		(2	)	Net of tax
Equity investments
Equity income	(7	)	(4	)	Income from equity investments
	1		1		Income tax expense
	(6	)	(3	)	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 10, Employee post-retirement benefits, for further information.

10. Employee post-retirement benefits

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

	three months ended March 31
	Pension benefit plans				Other post-retirement benefit plans
(unaudited - millions of Canadian $)	2018		2017		2018		2017
Service cost1	30		29		1		1
Other components of net benefit cost1
Interest cost	33		34		3		4
Expected return on plan assets	(55	)	(50	)	(4	)	(5	)
Amortization of actuarial loss	4		4		—		—
Amortization of regulatory asset	5		6		—		—
	(13	)	(6	)	(1	)	(1	)
Net Benefit Cost	17		23		—		—

1 Service cost and other components of net benefit cost are included in Plant operating costs and other on the Condensed consolidated statement of income.

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11. 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 March 31, 2018, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets, derivative assets and loans receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At March 31, 2018, 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.

The Company holds a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. The Company accounts for the joint venture as an equity investment. On April 21, 2017, the Company entered into a MXN$13.6 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. On December 6, 2017, an amended agreement was entered into to increase the credit facility to MXN$21.3 billion. Draws on the credit facility result in a loan receivable from the joint venture representing the Company's proportionate share of the debt financing requirements advanced to the joint venture. At March 31, 2018, the balance of the Company's loan receivable from the joint venture totaled $1.2 billion (December 31, 2017 – $919 million) and Interest income and other included of $27 million for the three months endedMarch 31, 2018 (2017 – nil). Interest income and other is offset by a corresponding proportionate share of interest expense recorded in Income from equity investments.

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.

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

	March 31, 2018			December 31, 2017
(unaudited - millions of Canadian $, unless noted otherwise)	Fair value1,2		Notional amount	Fair value1,2		Notional amount
U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019)3	(132	)	US 800	(199	)	US 1,200
U.S. dollar foreign exchange options (maturing 2018)	(2	)	US 300	5		US 500
	(134	)	US 1,100	(194	)	US 1,700

1 Fair values equal carrying values.

2 No amounts have been excluded from the assessment of hedge effectiveness.

3 In the three months endedMarch 31, 2018, Net income includes net realized gains of $1 million (2017 – $1 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense.

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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)	March 31, 2018	December 31, 2017
Notional amount	26,200 (US 20,300)	25,400 (US 20,200)
Fair value	29,000 (US 22,500)	28,900 (US 23,100)

FINANCIAL INSTRUMENTS

Non-derivative financial instruments

Fair value of non-derivative financial instruments

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. Each of these instruments are 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.

Balance sheet presentation of non-derivative financial instruments

The following table details the fair value of the Company's non-derivative financial instruments, excluding those where carrying amounts approximate fair value, which are classified in Level II of the fair value hierarchy: 

	March 31, 2018				December 31, 2017
(unaudited - millions of Canadian $)	Carrying amount		Fair value		Carrying amount		Fair value
Long-term debt including current portion1,2	(34,401	)	(38,789	)	(34,741	)	(40,180	)
Junior subordinated notes	(7,177	)	(7,264	)	(7,007	)	(7,233	)
	(41,578	)	(46,053	)	(41,748	)	(47,413	)

1 Long-term debt is recorded at amortized cost except for US$1.2 billion (December 31, 2017 – US$1.1 billion) that is attributed to hedged risk and recorded at fair value.

2 Net income for the three months endedMarch 31, 2018 included unrealized gains of $5 million (2017 – $2 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.2 billion of long-term debt at March 31, 2018 (December 31, 2017 – US$1.1 billion). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

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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:

	March 31, 2018		December 31, 2017
(unaudited - millions of Canadian $)	LMCI restricted investments	Other restricted investments1	LMCI restricted investments	Other restricted investments1
Fair values of fixed income securities2
Maturing within 1 year	—	25	—	23
Maturing within 1-5 years	—	123	—	107
Maturing within 5-10 years	71	—	14	—
Maturing after 10 years	801	—	790	—
	872	148	804	130

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

2 Available for sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Condensed consolidated balance sheet.

	March 31, 2018		March 31, 2017
(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	2	1	2	—

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 Interest income and other.

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.

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Balance sheet presentation of derivative instruments

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

at March 31, 2018	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	—		—		—		103		103
Foreign exchange	—		—		4		20		24
Interest rate	5		—		—		—		5
	5		—		4		123		132
Intangible and other assets
Commodities2	—		—		—		59		59
Foreign exchange	—		—		2		—		2
Interest rate	11		—		—		—		11
	11		—		2		59		72
Total Derivative Assets	16		—		6		182		204
Accounts payable and other
Commodities2	(9	)	—		—		(120	)	(129	)
Foreign exchange	—		—		(126	)	(38	)	(164	)
Interest rate	—		(8	)	—		—		(8	)
	(9	)	(8	)	(126	)	(158	)	(301	)
Other long-term liabilities
Commodities2	(2	)	—		—		(62	)	(64	)
Foreign exchange	—		—		(14	)	—		(14	)
Interest rate	—		(2	)	—		—		(2	)
	(2	)	(2	)	(14	)	(62	)	(80	)
Total Derivative Liabilities	(11	)	(10	)	(140	)	(220	)	(381	)
Total Derivatives	5		(10	)	(134	)	(38	)	(177	)

1 Fair value equals carrying value.

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

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at December 31, 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	1		—		—		249		250
Foreign exchange	—		—		8		70		78
Interest rate	3		—		—		1		4
	4		—		8		320		332
Intangible and other assets
Commodities2	—		—		—		69		69
Interest rate	4		—		—		—		4
	4		—		—		69		73
Total Derivative Assets	8		—		8		389		405
Accounts payable and other
Commodities2	(6	)	—		—		(208	)	(214	)
Foreign exchange	—		—		(159	)	(10	)	(169	)
Interest rate	—		(4	)	—		—		(4	)
	(6	)	(4	)	(159	)	(218	)	(387	)
Other long-term liabilities
Commodities2	(2	)	—		—		(26	)	(28	)
Foreign exchange	—		—		(43	)	—		(43	)
Interest rate	—		(1	)	—		—		(1	)
	(2	)	(1	)	(43	)	(26	)	(72	)
Total Derivative Liabilities	(8	)	(5	)	(202	)	(244	)	(459	)
Total Derivatives	—		(5	)	(194	)	145		(54	)

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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Derivatives in fair value hedging relationships

The following table details amounts recorded on the Condensed consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities:

	Carrying amount				Fair value hedging adjustments1
(unaudited - millions of Canadian $)	March 31, 2018		December 31, 2017		March 31, 2018	December 31, 2017
Current portion of long-term debt	(1,091	)	(688	)	6	1
Long-term debt	(448	)	(685	)	4	4
	(1,539	)	(1,373	)	10	5

1 At March 31, 2018, the balance includes adjustments for discontinued hedging relationships of nil (December 31, 2017 – nil).

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 March 31, 2018	Power	Natural Gas	Liquids	Foreign Exchange	Interest
(unaudited)
Purchases1	46,005	101	11	—	—
Sales1	31,648	107	14	—	—
Millions of U.S. dollars	—	—	—	US 3,137	US 2,400
Maturity dates	2018-2022	2018-2021	2018	2018-2019	2018-2028

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

at December 31, 2017	Power	Natural Gas	Liquids	Foreign Exchange	Interest
(unaudited)
Purchases1	66,132	133	6	—	—
Sales1	42,836	135	7	—	—
Millions of U.S. dollars	—	—	—	US 2,931	US 2,300
Millions of Mexican pesos	—	—	—	MXN 100	—
Maturity dates	2018-2022	2018-2021	2018	2018	2018-2022

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

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Unrealized and realized (losses)/gains on derivative instruments

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

	three months ended March 31
(unaudited - millions of Canadian $)	2018		2017
Derivative Instruments Held for Trading1
Amount of unrealized (losses)/gains in the period
Commodities2	(109	)	(56	)
Foreign exchange	(79	)	15
Interest rate	—		1
Amount of realized gains/(losses) in the period
Commodities	110		(48	)
Foreign exchange	15		(4	)
Derivative Instruments in Hedging Relationships
Amount of realized gains in the period
Commodities	3		6
Foreign exchange	—		5
Interest rate	1		1

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 In the three months endedMarch 31, 2018, 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 (2017 – nil).

Derivatives in cash flow hedging relationships

The components of OCI related to the change in fair value of derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: 

	three months ended March 31
(unaudited - millions of Canadian $)	2018		2017
Change in fair value of derivative instruments recognized in OCI1
Commodities	(3	)	5
Interest rate	9		1
	6		6

1 Amounts presented are pre-tax. No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI.

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Effect of fair value and cash flow hedging relationships

The following table details amounts presented on the Condensed consolidated statement of income in which the effects of fair value or cash flow hedging relationships are recorded.

	three months ended March 31
	Revenues (Energy)				Interest Expense
(unaudited - millions of Canadian $)	2018		2017		2018		2017
Total Amount Presented in the Condensed Consolidated Statement of Income	675		916		(527	)	(500	)
Fair Value Hedges
Interest rate contracts
Hedged items	—		—		(20	)	(19	)
Derivatives designated as hedging instruments	—		—		—		1
Cash Flow Hedges
Reclassification of gains/(losses) on derivative instruments from AOCI to net income
Interest rate contracts1	—		—		1		—
Commodity contracts2	(1	)	(4	)	—		—
Reclassification of gains on derivative instruments from AOCI to net income as a result of forecasted transactions that are no longer probable of occurring
Interest rate contracts1	—		—		4		4

1 Refer to Note 9, Other comprehensive income/(loss) and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.

2 There are no amounts recognized in earnings that were excluded from effectiveness testing.

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 on the Condensed consolidated balance sheet had the Company elected to present these contracts on a net basis:

at March 31, 2018	Gross derivative instruments		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative instrument assets
Commodities	162		(94	)	68
Foreign exchange	26		(22	)	4
Interest rate	16		(2	)	14
	204		(118	)	86
Derivative instrument liabilities
Commodities	(193	)	94		(99	)
Foreign exchange	(178	)	22		(156	)
Interest rate	(10	)	2		(8	)
	(381	)	118		(263	)

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

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FIRST QUARTER 2018                                        

at December 31, 2017	Gross derivative instruments		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative instrument assets
Commodities	319		(198	)	121
Foreign exchange	78		(56	)	22
Interest rate	8		(1	)	7
	405		(255	)	150
Derivative instrument liabilities
Commodities	(242	)	198		(44	)
Foreign exchange	(212	)	56		(156	)
Interest rate	(5	)	1		(4	)
	(459	)	255		(204	)

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

With respect to the derivative instruments presented above as at March 31, 2018, the Company provided cash collateral of $198 million (December 31, 2017 – $165 million) and letters of credit of $12 million (December 31, 2017 – $30 million) to its counterparties. The Company held nil (December 31, 2017 – nil) in cash collateral and $1 million (December 31, 2017 – $3 million) in letters of credit from counterparties on asset exposures at March 31, 2018. 

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 March 31, 2018, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $2 million (December 31, 2017 – $2 million), for which the Company did not provide collateral in the normal course of business at March 31, 2018 or December 31, 2017. If the credit-risk-related contingent features in these agreements were triggered on March 31, 2018, the Company would have been required to provide collateral of $2 million (December 31, 2017 – $2 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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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. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis.
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 are categorized as follows:

at March 31, 2018	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	20		137		5		162
Foreign exchange	—		26		—		26
Interest rate	—		16		—		16
Derivative instrument liabilities
Commodities	(26	)	(144	)	(23	)	(193	)
Foreign exchange	—		(178	)	—		(178	)
Interest rate	—		(10	)	—		(10	)
	(6	)	(153	)	(18	)	(177	)

1 There were no transfers from Level I to Level II or from Level II to Level III for the three months endedMarch 31, 2018.

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FIRST QUARTER 2018                                        

at December 31, 2017	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	21		283		15		319
Foreign exchange	—		78		—		78
Interest rate	—		8		—		8
Derivative instrument liabilities
Commodities	(27	)	(193	)	(22	)	(242	)
Foreign exchange	—		(212	)	—		(212	)
Interest rate	—		(5	)	—		(5	)
	(6	)	(41	)	(7	)	(54	)

1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2017.

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 March 31
(unaudited - millions of Canadian $)	2018		2017
Balance at beginning of period	(7	)	16
Total losses included in Net income	(2	)	—
Settlements	(9	)	—
Sales	—		(2	)
Transfers out of Level III	—		(4	)
Balance at end of period1	(18	)	10

1 For the three months endedMarch 31, 2018, revenues include unrealized losses of $11 million attributed to derivatives in the Level III category that were still held at March 31, 2018 (2017– unrealized losses of less than $1 million).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $1 million increase or decrease, respectively, in the fair value of outstanding derivative instruments included in Level III as at March 31, 2018. 

12. Contingencies and guarantees

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.

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.

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FIRST QUARTER 2018                                        

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 on the Condensed consolidated balance sheet. Information regarding the Company’s guarantees is as follows:

		at March 31, 2018		at December 31, 2017
(unaudited - millions of Canadian $)	Term	Potential exposure1	Carrying value	Potential exposure1	Carrying value
Sur de Texas	ranging to 2020	199	1	315	2
Bruce Power	ranging to 2019	88	—	88	1
Other jointly-owned entities	ranging to 2059	105	12	104	13
		392	13	507	16

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

13. Variable interest entities

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 is the primary beneficiary. As the primary beneficiary, 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 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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FIRST QUARTER 2018                                        

	March 31,	December 31,
(unaudited - millions of Canadian $)	2018	2017
ASSETS
Current Assets
Cash and cash equivalents	88	41
Accounts receivable	61	63
Inventories	24	23
Other	15	11
	188	138
Plant, Property and Equipment	3,617	3,535
Equity Investments	944	917
Goodwill	482	490
Intangible and Other Assets	11	3
	5,242	5,083
LIABILITIES
Current Liabilities
Accounts payable and other	128	137
Dividends payable	3	1
Accrued interest	31	23
Current portion of long-term debt	86	88
	248	249
Regulatory Liabilities	36	34
Other Long-Term Liabilities	3	3
Deferred Income Tax Liabilities	13	13
Long-Term Debt	3,304	3,244
	3,604	3,543

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 entities 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:

	March 31,	December 31,
(unaudited - millions of Canadian $)	2018	2017
Balance sheet
Equity investments	4,306	4,372
Off-balance sheet
Potential exposure to guarantees	172	171
Maximum exposure to loss	4,478	4,543