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Document and Entity Information	12 Months Ended
Document and Entity Information	Dec. 31, 2018 shares
Document And Entity Information [Line Items]
Entity Registrant Name	TRANSCANADA CORP
Entity Central Index Key	0001232384
Document Type	40-F
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	918,096,439
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
TRANSCANADA PIPELINES LIMITED
Document And Entity Information [Line Items]
Entity Registrant Name	TRANSCANADA PIPELINES LTD
Entity Central Index Key	0000099070
Document Type	40-F
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	887,333,320
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY

Consolidated statement of income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues (Note 5)
Revenues	$ 13,679	$ 13,449	$ 12,547
Income from Equity Investments (Note 9)	714	773	514
Operating and Other Expenses
Plant operating costs and other	3,591	3,906	3,861
Commodity purchases resold	1,488	2,382	2,172
Property taxes	569	569	555
Depreciation and amortization	2,350	2,055	1,939
Goodwill and other asset impairment charges (Notes 8, 11 and 12)	801	1,257	1,388
Total Operating and Other Expenses	8,799	10,169	9,915
Gain/(Loss) on Assets Held for Sale/Sold (Note 26)	170	631	(833)
Financial Charges
Interest expense (Note 17)	2,265	2,069	1,998
Allowance for funds used during construction	(526)	(507)	(419)
Interest income and other	76	(184)	(103)
Total Financial Charges	1,815	1,378	1,476
Income before Income Taxes	3,949	3,306	837
Income Tax Expense/(Recovery) (Note 16)
Current	315	149	156
Deferred	284	566	196
Deferred – U.S. Tax Reform and 2018 FERC Actions	(167)	(804)	0
Income Tax (Recovery)/Expense	432	(89)	352
Net Income	3,517	3,395	485
Net (loss)/income attributable to non-controlling interests (Note 19)	(185)	238	252
Net Income Attributable to Controlling Interests	3,702	3,157	233
Preferred share dividends	163	160	109
Net Income Attributable to Common Shares	$ 3,539	$ 2,997	$ 124
Net Income per Common Share (Note 20)
Basic (in dollars per share)	$ 3.92	$ 3.44	$ 0.16
Diluted (in dollars per share)	3.92	3.43	0.16
Dividends Declared per Common Share (in dollars per share)	$ 2.76	$ 2.5	$ 2.26
Weighted Average Number of Common Shares (Note 20)
Basic (in shares)	902	872	759
Diluted (in shares)	903	874	760
Canadian Natural Gas Pipelines
Revenues (Note 5)
Revenues	$ 4,038	$ 3,693	$ 3,682
U.S. Natural Gas Pipelines
Revenues (Note 5)
Revenues	4,314	3,584	2,526
Mexico Natural Gas Pipelines
Revenues (Note 5)
Revenues	619	570	378
Liquids Pipelines
Revenues (Note 5)
Revenues	2,584	2,009	1,755
Energy
Revenues (Note 5)
Revenues	$ 2,124	$ 3,593	$ 4,206

Consolidated statement of comprehensive income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net Income	$ 3,517	$ 3,395	$ 485
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations	1,358	(749)	3
Reclassification of foreign currency translation gains on disposal of foreign operations	0	(77)	0
Change in fair value of net investment hedges	(42)	0	(10)
Change in fair value of cash flow hedges	(10)	3	30
Reclassification to net income of gains and losses on cash flow hedges	21	(2)	42
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(114)	(11)	(26)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	15	16	16
Other comprehensive income/(loss) on equity investments	86	(106)	(87)
Other comprehensive income/(loss) (Note 22)	1,314	(926)	(32)
Comprehensive Income	4,831	2,469	453
Comprehensive (loss)/income attributable to non-controlling interests	(13)	83	241
Comprehensive Income Attributable to Controlling Interests	4,844	2,386	212
Preferred share dividends	163	160	109
Comprehensive Income Attributable to Common Shares	$ 4,681	$ 2,226	$ 103

Consolidated statement of cash flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Generated from Operations
Net income	$ 3,517	$ 3,395	$ 485
Depreciation and amortization	2,350	2,055	1,939
Goodwill and other asset impairment charges (Notes 8, 11 and 12)	801	1,257	1,388
Deferred income taxes (Note 16)	284	566	196
Deferred income taxes – U.S. Tax Reform and 2018 FERC Actions (Note 16)	(167)	(804)	0
Income from equity investments (Note 9)	(714)	(773)	(514)
Distributions received from operating activities of equity investments (Note 9)	985	970	844
Employee post-retirement benefits funding, net of expense (Note 23)	(35)	(64)	(3)
(Gain)/loss on assets held for sale/sold (Note 26)	(170)	(631)	833
Equity allowance for funds used during construction	(374)	(362)	(253)
Unrealized losses/(gains) on financial instruments	220	(149)	(149)
Other	(40)	43	55
(Increase)/decrease in operating working capital (Note 25)	(102)	(273)	248
Net cash provided by operations	6,555	5,230	5,069
Investing Activities
Capital expenditures (Note 4)	(9,418)	(7,383)	(5,007)
Capital projects in development (Note 4)	(496)	(146)	(295)
Contributions to equity investments (Notes 4 and 9)	(1,015)	(1,681)	(765)
Acquisitions, net of cash acquired	0	0	(13,608)
Proceeds from sales of assets, net of transaction costs	614	4,683	6
Reimbursement of costs related to capital projects in development (Note 12)	470	634	0
Other distributions from equity investments (Note 9)	121	362	727
Deferred amounts and other	(295)	(168)	159
Net cash used in investing activities	(10,019)	(3,699)	(18,783)
Financing Activities
Notes payable issued/(repaid), net	817	1,038	(329)
Long-term debt issued, net of issue costs	6,238	3,643	12,333
Long-term debt repaid	(3,550)	(7,085)	(7,153)
Junior subordinated notes issued, net of issue costs	0	3,468	1,549
Dividends on common shares	(1,571)	(1,339)	(1,436)
Dividends on preferred shares	(158)	(155)	(100)
Distributions to non-controlling interests	(225)	(283)	(279)
Common shares issued, net of issue costs	1,148	274	7,747
Common shares repurchased (Note 20)	0	0	(14)
Preferred shares issued, net of issue costs	0	0	1,474
Partnership units of TC PipeLines, LP issued, net of issue costs	49	225	215
Common units of Columbia Pipeline Partners LP acquired	0	(1,205)	0
Net cash provided by/(used in) financing activities	2,748	(1,419)	14,007
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	73	(39)	(127)
(Decrease)/Increase in Cash and Cash Equivalents	(643)	73	166
Cash and Cash Equivalents, Beginning of year	1,089	1,016	850
Cash and Cash Equivalents, End of year	$ 446	$ 1,089	$ 1,016

Consolidated balance sheet - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 446	$ 1,089
Accounts receivable	2,535	2,522
Inventories	431	378
Assets held for sale (Note 6)	543	0
Other (Note 7)	1,180	691
Total Current Assets	5,135	4,680
Plant, Property and Equipment (Note 8)	66,503	57,277
Equity Investments (Note 9)	7,113	6,366
Regulatory Assets (Note 10)	1,548	1,376
Goodwill (Note 11)	14,178	13,084
Loan Receivable from Affiliate (Note 9)	1,315	919
Intangible and Other Assets (Note 12)	1,921	1,484
Restricted Investments	1,207	915
Total Assets	98,920	86,101
Current Liabilities
Notes payable (Note 13)	2,762	1,763
Accounts payable and other (Note 14)	5,408	4,057
Dividends payable	668	586
Accrued interest	646	605
Current portion of long-term debt (Note 17)	3,462	2,866
Total Current Liabilities	12,946	9,877
Regulatory Liabilities (Note 10)	3,930	4,321
Other Long-Term Liabilities (Note 15)	1,008	727
Deferred Income Tax Liabilities (Note 16)	6,026	5,403
Long-Term Debt (Note 17)	36,509	31,875
Junior Subordinated Notes (Note 18)	7,508	7,007
Total Liabilities	67,927	59,210
EQUITY
Common shares, no par value (Note 20)	23,174	21,167
Preferred shares (Note 21)	3,980	3,980
Additional paid-in capital	17	0
Retained earnings	2,773	1,623
Accumulated other comprehensive loss (Note 22)	(606)	(1,731)
Controlling Interests	29,338	25,039
Non-controlling interests (Note 19)	1,655	1,852
Total Equity	30,993	26,891
Total Liabilities and Equity	$ 98,920	$ 86,101

Consolidated balance sheet (Parenthetical) - shares shares in Millions	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common shares issued (in shares)	918	881
Common shares outstanding (in shares)	918	881

Consolidated statement of equity - CAD ($) $ in Millions	Total	Equity Attributable to Controlling Interests	Common Shares	Preferred Shares	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Equity Attributable to Non-Controlling Interests
Balance at beginning of year at Dec. 31, 2015			$ 12,102	$ 2,499	$ 7	$ 2,769	$ (939)	$ 1,717
Shares issued:
Under dividend reinvestment and share purchase plan			177
On exercise of stock options			74
Under public offerings, net of issue costs			7,752	1,481
Shares repurchased			(6)		(8)
Issuance of stock options, net of exercises					6
Dilution from TC PipeLines, LP units issued					24			215
Asset drop-downs to TC PipeLines, LP					(38)
Columbia Pipeline Partners LP acquisition								(40)
Reclassification of additional paid-in capital deficit to retained earnings					9
Net income attributable to controlling interests	$ 233					233
Common share dividends						(1,733)
Preferred share dividends						(122)
Reclassification of additional paid-in capital deficit to retained earnings						(9)
Other comprehensive income/(loss) attributable to controlling interests (Note 22)	(32)						(21)
Net (loss)/income attributable to non-controlling interests	(252)							252
Other comprehensive income/(loss) attributable to non-controlling interests								(11)
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					24			215
Decrease in TransCanada's ownership of TC PipeLines, LP								(40)
Distributions declared to non-controlling interests								(279)
Reclassification from/(to) common units subject to rescission or redemption (Note 19)								(1,179)
Acquisition of non-controlling interests in Columbia Pipeline Partners LP								1,051
Balance at end of year at Dec. 31, 2016	25,983	$ 24,257	20,099	3,980		1,138	(960)	1,726
Shares issued:
Under at-the-market equity issuance program, net of issue costs			216
Under dividend reinvestment and share purchase plan			790
On exercise of stock options			62
Issuance of stock options, net of exercises					6
Dilution from TC PipeLines, LP units issued					26			225
Asset drop-downs to TC PipeLines, LP					(202)
Columbia Pipeline Partners LP acquisition					(171)			(41)
Reclassification of additional paid-in capital deficit to retained earnings					341
Net income attributable to controlling interests	3,157					3,157
Common share dividends						(2,184)
Preferred share dividends						(159)
Reclassification of additional paid-in capital deficit to retained earnings						(341)
Other comprehensive income/(loss) attributable to controlling interests (Note 22)	(926)						(771)
Net (loss)/income attributable to non-controlling interests	(238)							238
Other comprehensive income/(loss) attributable to non-controlling interests								(155)
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					26			225
Decrease in TransCanada's ownership of TC PipeLines, LP					(171)			(41)
Distributions declared to non-controlling interests								(280)
Reclassification from/(to) common units subject to rescission or redemption (Note 19)								106
Impact of Columbia Pipeline Partners LP acquisition								33
Balance at end of year at Dec. 31, 2017	26,891	25,039	21,167	3,980		1,623	(1,731)	1,852
Shares issued:
Under at-the-market equity issuance program, net of issue costs			1,118
Under dividend reinvestment and share purchase plan			855
On exercise of stock options			34
Issuance of stock options, net of exercises					10
Dilution from TC PipeLines, LP units issued					7			49
Columbia Pipeline Partners LP acquisition								(9)
Net income attributable to controlling interests	3,702					3,702
Common share dividends						(2,501)
Preferred share dividends						(163)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform (Note 3)						17	(17)
Other comprehensive income/(loss) attributable to controlling interests (Note 22)	1,314						1,142
Net (loss)/income attributable to non-controlling interests	185							(185)
Other comprehensive income/(loss) attributable to non-controlling interests								172
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					7			49
Decrease in TransCanada's ownership of TC PipeLines, LP								(9)
Distributions declared to non-controlling interests								(224)
Balance at end of year at Dec. 31, 2018	$ 30,993	$ 29,338	$ 23,174	$ 3,980	$ 17	$ 2,773	$ (606)	$ 1,655

DESCRIPTION OF TRANSCANADA'S BUSINESS	12 Months Ended
DESCRIPTION OF TRANSCANADA'S BUSINESS	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
DESCRIPTION OF TRANSCANADA'S BUSINESS	DESCRIPTION OF TRANSCANADA'S BUSINESS TransCanada Corporation (TransCanada or the Company) is a leading North American energy infrastructure company which operates in five business segments, Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy, each of which offers different products and services. The Company also has a Corporate segment, consisting of corporate and administrative functions that provide governance, financing and other support to the Company's business segments. Canadian Natural Gas Pipelines The Canadian Natural Gas Pipelines segment consists of the Company's investments in 40,686 km (25,281 miles) of regulated natural gas pipelines. U.S. Natural Gas Pipelines The U.S. Natural Gas Pipelines segment consists of the Company's investments in 50,199 km (31,192 miles) of regulated natural gas pipelines, 535 Bcf of regulated natural gas storage facilities, midstream and other assets. Mexico Natural Gas Pipelines The Mexico Natural Gas Pipelines segment consists of the Company's investments in 1,670 km (1,038 miles) of regulated natural gas pipelines. Liquids Pipelines The Liquids Pipelines segment consists of the Company's investments in 4,874 km (3,030 miles) of crude oil pipeline systems which connect Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas. Energy The Energy segment primarily consists of the Company's investments in 10 power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These include assets in Alberta, Ontario, Québec, New Brunswick and Arizona. At December 31, 2018, the Coolidge generating station is classified as Assets held for sale. Refer to Note 6, Assets held for sale, for further information.

ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

ACCOUNTING POLICIES

The Company's consolidated financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles (GAAP). Amounts are stated in Canadian dollars unless otherwise indicated.

Basis of Presentation

These consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates and Judgments

In preparing these consolidated 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 judgment in making these estimates and assumptions. Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but they do not involve significant subjectivity or uncertainty. Others also have a material impact but the assumptions underlying these accounting estimates also relate to matters that are highly uncertain at the time the estimate or judgment is made or are subjective.

Significant estimates and judgments used in the preparation of the consolidated financial statements that involve assumptions that are highly uncertain or subjective include, but are not limited to:


•	fair value of plant, property and equipment and equity investments (Notes 8 and 9)


•	fair value of goodwill (Note 11)


•	fair value of intangible assets (Note 12) and


•	fair value of assets and liabilities acquired in a business combination (Note 26).

Significant estimates and judgments used in the preparation of the consolidated financial statements that are provided by an independent expert or do not involve assumptions that are highly uncertain or subjective include, but are not limited to:


•	depreciation rates of plant, property and equipment (Note 8)


•	carrying value of regulatory assets and liabilities (Note 10)


•	carrying value of asset retirement obligations (Note 15)


•	provisions for income taxes, including U.S. Tax Reform (Note 16)


•	assumptions used to measure retirement and other post-retirement obligations (Note 23)


•	fair value of financial instruments (Note 24) and


•	provisions for commitments, contingencies, guarantees (Note 27) and restructuring costs (Note 28).

Actual results could differ from these estimates.

Regulation

Certain Canadian, U.S. and Mexico natural gas pipeline and storage assets are regulated with respect to construction, operations and the determination of tolls. In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB), the Alberta Energy Regulator (AER) or the B.C. Oil and Gas Commission (OGC). In the U.S., regulated natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TransCanada's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An asset qualifies for the use of RRA when it meets three criteria:


•	a regulator must establish or approve the rates for the regulated services or activities


•	the regulated rates must be designed to recover the cost of providing the services or products and


•	it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers because of the demand for services or products and the level of direct or indirect competition.

TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexico natural gas pipelines, and regulated U.S. natural gas storage. RRA is not applicable to the Company's liquids pipelines as the regulators' decisions regarding operations and tolls on those systems generally do not have an impact on timing of recognition of revenues and expenses. Once in operation, the Coastal GasLink pipeline is not expected to apply RRA.

Revenue Recognition

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 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 return on 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.

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'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 revenues 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 and associated liquids are 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. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. 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.

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. Revenues are recognized as the services are provided. 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.

Cash and Cash Equivalents

The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

Inventories

Inventories primarily consist of materials and supplies including spare parts and fuel, crude oil in transit and natural gas inventory in storage. Inventories are carried at the lower of cost and net realizable value.

Assets Held for Sale

The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next twelve months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, net of selling costs, and any losses are recognized in net income. Once an asset is classified as held for sale, depreciation expense is no longer recorded.

Plant, Property and Equipment

Natural Gas Pipelines

Plant, property and equipment for natural gas pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to seven per cent, and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in plant, property and equipment with a corresponding credit recognized in Allowance for funds used during construction in the Consolidated statement of income. The equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines.

Regulated natural gas storage base gas, which is valued at cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver natural gas held in storage. Base gas is not depreciated.

When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation.

Midstream and Other

Plant, property and equipment for midstream assets is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Gathering and processing facilities are depreciated at annual rates ranging from

1.7 per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income.

The Company participates as a working interest partner in the development of certain Marcellus and Utica acreage. The working interest allows the Company to invest in drilling activities in addition to receiving a royalty interest in well production. The Company uses the successful efforts method of accounting for natural gas and crude oil resulting from its portion of drilling activities. Capitalized well costs are depleted based on the units of production method.

Liquids Pipelines

Plant, property and equipment for liquids pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income.

Energy

Plant, property and equipment for Energy assets are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income.

Non-regulated natural gas storage base gas, which is valued at original cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver gas held in storage. Base gas is not depreciated.

Corporate

Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful life at average annual rates ranging from three per cent to 20 per cent.

Capitalized Project Costs

The Company capitalizes project costs once advancement of the project to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest costs for non-regulated projects in development and AFUDC for regulated projects in development. Capital projects in development are included in Intangible and other assets on the Consolidated balance sheet. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to Plant, property and equipment under construction.

Impairment of Long-Lived Assets

The Company reviews long-lived assets such as plant, property and equipment, equity investments and capital projects in development for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows that are estimated for an asset within Plant, property and equipment, or the estimated selling price of any long-lived asset is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset.

Acquisitions and Goodwill

The Company accounts for business combinations using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair values at the date of acquisition. The excess of the fair value of the consideration transferred over the estimated fair value of the net assets acquired is classified as goodwill. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that it might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company can initially assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired and if the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the Company will then perform the quantitative goodwill impairment test. The Company can elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Company compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value.

Loans and Receivables

Loans receivable from affiliates and accounts receivable are measured at cost.

Power Purchase Arrangements

A power purchase arrangement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. TransCanada has PPAs for the sale of power that are accounted for as operating leases where TransCanada is the lessor. During 2016, the Company terminated its Alberta PPAs under which it purchased power and recorded an impairment charge. Prior to their termination, substantially all of these PPAs were also accounted for as operating leases, where TransCanada was the lessee, and initial payments to acquire these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts. A portion of these PPAs was subleased to third parties under terms and conditions similar to the PPAs, and was also accounted for as operating leases with the margin earned from the subleases recorded in Revenues. Refer to Note 12, Intangible and other assets, for further information.

Restricted Investments

The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are classified as available for sale and are recorded at fair value on the Consolidated balance sheet.

As a result of the NEB’s Land Matters Consultation Initiative (LMCI), TransCanada is required to collect funds to cover estimated future pipeline abandonment costs for all NEB regulated Canadian pipelines. Funds collected are placed in trusts that hold and invest the funds and are accounted for as restricted investments. LMCI restricted investments may only be used to fund the abandonment of the NEB regulated pipeline facilities, therefore, a corresponding regulatory liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net income in the period which they occur, except for changes in balances related to regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the regulator. Deferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet.

Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.

Asset Retirement Obligations

The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Operating and other expenses.

For those AROs that the Company records, the following assumptions are used:


•	when the asset is expected to be retired


•	the scope and cost of abandonment and reclamation activities that are required and


•	appropriate inflation and discount rates.

The Company has recorded AROs related to its non-regulated natural gas storage operations, mineral rights and power generation facilities. The scope and timing of asset retirements related to most of the Company's natural gas pipelines and liquids pipelines is indeterminable because the Company intends to operate them as long as there is supply and demand. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities and certain facilities expected to be retired as part of an ongoing modernization program that will improve system integrity and enhance service reliability and flexibility on its Columbia Gas pipeline.

Environmental Liabilities

The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. These estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations, and are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.

Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and expensed when they are utilized or cancelled/retired by government agencies. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TransCanada are not attributed a value for accounting purposes. When required, TransCanada accrues emission liabilities on the Consolidated balance sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues.

Stock Options and Other Compensation Programs

TransCanada's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period with an offset to Additional paid-in capital. Upon exercise of stock options, amounts originally recorded against Additional paid-in capital are reclassified to Common shares on the Consolidated balance sheet.

The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.

Employee Post-Retirement Benefits

The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service, and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.

The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service life of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated other comprehensive income (AOCI) and into net income over the expected average remaining service life of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.

For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.

Foreign Currency Transactions and Translation

Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or reporting subsidiary operates. This is referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in net income except for exchange gains and losses of the foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI until the operations are sold, at which time the gains and losses are reclassified to net income. Asset and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt and certain derivative hedging instruments have been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar denominated debt are also reflected in OCI.

Derivative Instruments and Hedging Activities

All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions.

The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment. This includes fair value and cash flow hedges and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise.

In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over the remaining term of the original hedging relationship.

In a cash flow hedging relationship, the change in the fair value of the hedging derivative is recognized in OCI. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur.

In hedging the foreign currency exposure of a net investment in a foreign operation, the foreign exchange gains and losses on the hedging instruments are recognized in OCI. The amounts recognized previously in AOCI are reclassified to net income in the event the Company reduces its net investment in a foreign operation.

In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change.

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

Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in net income.

Long-Term Debt Transaction Costs and Issuance Costs

The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the related debt liability and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms.

Guarantees

Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of a partially-owned entity or by partially-owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments or Plant, property and equipment and a corresponding liability is recorded in Other long-term liabilities. The release from the obligation is recognized either over the term of the guarantee or upon expiration or settlement of the guarantee.

ACCOUNTING CHANGES	12 Months Ended
ACCOUNTING CHANGES	Dec. 31, 2018
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	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. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and related cash flows. The Company’s accounting policies related to revenue recognition have not substantially changed as a result of adopting the new guidance on revenue from contracts with customers. Results reported for 2018 reflect the application of the new guidance, while the 2017 and 2016 comparative results were prepared and reported under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP." Under legacy U.S. GAAP, revenues were recognized when the risk, rewards, and benefits were transferred to the customer by the Company providing the goods or services under the contract, in an amount the Company expected to collect from the customer. Under the new guidance applied in 2018, revenues are recognized when the Company satisfies its performance obligations by transferring control of the promised goods or services to its customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company has elected to utilize a practical expedient to recognize revenues from its U.S. and certain Mexico natural gas pipelines contracts as customers are invoiced. 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 5, Revenues, for further information related to the impact of adopting 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 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 intra-entity asset transfers when the transfer occurs. The new guidance was effective January 1, 2018, was applied using a modified retrospective approach, and resulted in an adjustment to retained earnings of $95 million. In February 2018, the FASB issued new guidance that allows a reclassification from AOCI to retained earnings for stranded tax effects resulting from U.S. Tax Reform. 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. This new guidance is effective January 1, 2019, however, early adoption is permitted. The Company elected to early adopt this guidance effective fourth quarter 2018 and used a portfolio approach for releasing the income tax effects from AOCI to retained earnings. The Company applied this guidance retrospectively, at the beginning of the period of adoption, resulting in an adjustment to retained earnings of $17 million. 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 period and end of period 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. 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 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. Derecognition of Nonfinancial Assets In February 2017, the FASB issued new guidance that clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset. The FASB also amended the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. This new guidance was effective January 1, 2018, was applied using the modified retrospective transition method and did not have a material impact on the Company's 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 with early adoption permitted. The Company elected to adopt this guidance effective fourth quarter 2018 as it simplified goodwill impairment testing. The guidance was applied prospectively and used in the 2018 annual goodwill impairment test. 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 lessee 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. Lessees will classify leases as finance or operating, with classification affecting the pattern of expense recognition in the statement of income. The new guidance does not make extensive changes to lessor accounting. The Company currently expects that substantially all of its leases where the Company is the lessor will continue to be classified as operating leases under the new standard. 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 it consistently to all of its existing or expired land easements not previously accounted for as leases. The Company will apply this practical expedient upon transition to the new standard. The new guidance is effective January 1, 2019, with early adoption permitted. The Company will adopt the new standard on its effective date. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application being January 1, 2019. In July 2018, the FASB issued a transition option allowing entities to not apply the new guidance, including disclosure requirements, to the comparative periods they present in their financial statements in the year of adoption. The Company will apply this transition option and use the effective date as the date of initial application. Consequently, financial information will not be updated and disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. The Company will elect the package of practical expedients which permits entities not to reassess prior conclusions about lease identification, lease classification and initial direct costs under the rules of the new standard. The Company believes that the most significant effects of adoption will relate to the recognition of new ROU assets and lease liabilities on the Company's balance sheet for its operating leases and providing significant new disclosures about the Company's leasing activities. The guidance will not impact the Company's income statement. On adoption, the Company will recognize ROU assets of approximately $606 million and additional operating lease liabilities of approximately $600 million based on the present value of the remaining minimum lease payments for existing operating leases. The new standard also provides practical expedients for a Company’s ongoing accounting. The Company will elect the short-term lease recognition exemption for all eligible leases. This means, for those leases that qualify, the Company will not recognize ROU assets or lease liabilities. The Company will also elect the practical expedient to not separate lease and non-lease components for all leases for which the Company is the lessee and for facility and liquids tank terminals for which the Company is the lessor. 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. Fair value measurement In August 2018, the FASB issued new guidance that amends certain disclosure requirements for fair value measurements. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Defined benefit plans In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to DB pension and other post retirement benefit plans. This new guidance is effective January 1, 2021, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Implementation costs of cloud computing arrangements In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting arrangement over the term of the arrangement. This guidance is effective January 1, 2020, however, early adoption is permitted. This guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Consolidation In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

SEGMENTED INFORMATION

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

SEGMENTED INFORMATION



year ended December 31, 2018	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total
(millions of Canadian $)	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total

Revenues	4,038		4,314		619		2,584		2,124		—			13,679
Intersegment revenues	—		162		—		—		56		(218	)	²	—
	4,038		4,476		619		2,584		2,180		(218	)		13,679
Income from equity investments	12		256		22		64		355		5		³	714
Plant operating costs and other	(1,405	)	(1,368	)	(34	)	(630	)	(313	)	159		²	(3,591	)
Commodity purchases resold	—		—		—		—		(1,488	)	—			(1,488	)
Property taxes	(266	)	(199	)	—		(98	)	(6	)	—			(569	)
Depreciation and amortization	(1,129	)	(664	)	(97	)	(341	)	(119	)	—			(2,350	)
Goodwill and other asset impairment charges	—		(801	)	—		—		—		—			(801	)
Gain on sale of assets	—		—		—		—		170		—			170
Segmented earnings/(losses)	1,250		1,700		510		1,579		779		(54	)		5,764
Interest expense														(2,265	)
Allowance for funds used during construction														526
Interest income and other³														(76	)
Income before income taxes														3,949
Income tax expense														(432	)
Net income														3,517
Net loss attributable to non-controlling interests														185
Net income attributable to controlling interests														3,702
Preferred share dividends														(163	)
Net income attributable to common shares														3,539

Capital spending
Capital expenditures	2,442		5,591		463		110		767		45			9,418
Capital projects in development	36		1		—		459		—		—			496
Contributions to equity investments	—		179		334		12		490		—			1,015
	2,478		5,771		797		581		1,257		45			10,929


1	Includes intersegment eliminations.

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.

Income from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. Refer to Note 9, Equity investments, for further information.



year ended December 31, 2017	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total
(millions of Canadian $)	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total

Revenues	3,693		3,584		570		2,009		3,593		—			13,449
Intersegment revenues	—		51		—		—		—		(51	)	²	—
	3,693		3,635		570		2,009		3,593		(51	)		13,449
Income/(loss) from equity investments	11		240		(9	)	(3	)	471		63		³	773
Plant operating costs and other	(1,300	)	(1,340	)	(42	)	(623	)	(550	)	(51	)	²	(3,906	)
Commodity purchases resold	—		—		—		—		(2,382	)	—			(2,382	)
Property taxes	(260	)	(181	)	—		(89	)	(39	)	—			(569	)
Depreciation and amortization	(908	)	(594	)	(93	)	(309	)	(151	)	—			(2,055	)
Goodwill and other asset impairment charges	—		—		—		(1,236	)	(21	)	—			(1,257	)
Gain on sale of assets	—		—		—		—		631		—			631
Segmented earnings/(losses)	1,236		1,760		426		(251	)	1,552		(39	)		4,684
Interest expense														(2,069	)
Allowance for funds used during construction														507
Interest income and other³														184
Income before income taxes														3,306
Income tax recovery														89
Net income														3,395
Net income attributable to non-controlling interests														(238	)
Net income attributable to controlling interests														3,157
Preferred share dividends														(160	)
Net income attributable to common shares														2,997

Capital spending
Capital expenditures	2,106		3,712		833		341		350		41			7,383
Capital projects in development	75		—		—		71		—		—			146
Contributions to equity investments	—		118		1,121		117		325		—			1,681
	2,181		3,830		1,954		529		675		41			9,210


1	Includes intersegment eliminations.

Income/(loss) from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. Refer to Note 9, Equity investments, for further information.



year ended December 31, 2016	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total
(millions of Canadian $)	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total

Revenues	3,682		2,526		378		1,755		4,206		—			12,547
Intersegment revenues	—		56		—		—		—		(56	)	²	—
	3,682		2,582		378		1,755		4,206		(56	)		12,547
Income/(loss) from equity investments	12		214		(3	)	(1	)	292		—			514
Plant operating costs and other	(1,245	)	(1,057	)	(43	)	(568	)	(884	)	(64	)	²	(3,861	)
Commodity purchases resold	—		—		—		—		(2,172	)	—			(2,172	)
Property taxes	(267	)	(120	)	—		(88	)	(80	)	—			(555	)
Depreciation and amortization	(875	)	(425	)	(45	)	(292	)	(302	)	—			(1,939	)
Goodwill and other asset impairment charges	—		—		—		—		(1,388	)	—			(1,388	)
Loss on assets held for sale/sold	—		(4	)	—		—		(829	)	—			(833	)
Segmented earnings/(losses)	1,307		1,190		287		806		(1,157	)	(120	)		2,313
Interest expense														(1,998	)
Allowance for funds used during construction														419
Interest income and other														103
Income before income taxes														837
Income tax expense														(352	)
Net income														485
Net income attributable to non-controlling interests														(252	)
Net income attributable to controlling interests														233
Preferred share dividends														(109	)
Net income attributable to common shares														124

Capital spending
Capital expenditures	1,372		1,517		944		668		473		33			5,007
Capital projects in development	153		—		—		142		—		—			295
Contributions to equity investments	—		5		198		327		235		—			765
	1,525		1,522		1,142		1,137		708		33			6,067


1	Includes intersegment eliminations.



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Total Assets by segment
Canadian Natural Gas Pipelines	18,407	16,904
U.S. Natural Gas Pipelines	44,115	35,898
Mexico Natural Gas Pipelines	7,058	5,716
Liquids Pipelines	17,352	15,438
Energy	8,475	8,503
Corporate	3,513	3,642
	98,920	86,101

Geographic Information



year ended December 31	2018	2017	2016
(millions of Canadian $)	2018	2017	2016

Revenues
Canada – domestic	4,187	3,618	3,697
Canada – export	1,075	1,255	1,177
United States	7,798	8,006	7,295
Mexico	619	570	378
	13,679	13,449	12,547



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Plant, Property and Equipment
Canada	23,226	21,632
United States	37,385	30,693
Mexico	5,892	4,952
	66,503	57,277

REVENUES

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUES

On January 1, 2018, the Company adopted new FASB guidance on revenue from contracts with customers 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 and 2016 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 tables summarizes total Revenues for the year ended December 31, 2018.



(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	4,038	3,549	614	2,079	—	10,280
Power generation	—	—	—	—	1,771	1,771
Natural gas storage and other	—	654	5	3	81	743
	4,038	4,203	619	2,082	1,852	12,794
Other revenues^1,2	—	111	—	502	272	885
	4,038	4,314	619	2,584	2,124	13,679

Other revenues include income from the Company's marketing activities, 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 24, Risk management and financial instruments, for further information on income from financial instruments.


2	Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 16, 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 natural gas and liquids pipelines capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other contracts.

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 of adopting the new guidance, the Company made the adjustments described below on January 1, 2018.

Capacity Arrangements and Transportation

For certain natural gas pipeline 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, these differences were recorded as Accounts receivable. Under the new guidance, contract assets are included in Other current assets and Intangibles and other assets and contract liabilities are included in Accounts payable and other and Other long-term liabilities.

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
(millions of Canadian $)	December 31, 2017	Adjustment		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.

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 Consolidated balance sheet, as at December 31, 2018, using legacy U.S. GAAP:



	December 31, 2018
	As reported	Pro-forma using legacy U.S. GAAP
(millions of Canadian $)

Current Assets
Accounts receivable	2,535	2,694
Other	1,180	1,021

Contract Balances



(millions of Canadian $)	December 31, 2018	January 1, 2018
(millions of Canadian $)	December 31, 2018	January 1, 2018

Receivables from contracts with customers	1,684	1,736
Contract assets¹	159	79
Long-term contract assets²	21	—
Contract liabilities³	11	17
Long-term contract liabilities⁴	121	—


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


2	Recorded as part of Intangibles and other assets on the Consolidated balance sheet.


3	Comprised of deferred revenue recorded in Accounts payable and other on the Consolidated balance sheet. During the year ended December 31, 2018,

$17 million of revenue was recognized that was included in the contract liability at the beginning of the year.


4	Comprised of deferred revenue recorded in Other long-term liabilities on the Consolidated balance sheet.

Contract assets and long-term 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 these rights become unconditional and the customer is invoiced, as well as the recognition of additional revenues that remain to be invoiced. Contract liabilities and long-term contract liabilities primarily relate to force majeure fixed capacity payments received on long-term capacity arrangements in Mexico.

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.

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.

Capacity Arrangements and Transportation

As at December 31, 2018, future revenues from long-term pipeline capacity arrangements and transportation contracts extending through 2043 are approximately $30.1 billion, of which approximately $6.0 billion is expected to be recognized in 2019.

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 are allocated entirely to unsatisfied performance obligations at December 31, 2018.

The Company also applies the right to invoice practical expedient to all of its U.S. and certain of its 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 are allocated entirely to unsatisfied performance obligations at December 31, 2018.

Power Generation

The Company has long-term power generation contracts extending through 2030. 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 December 31, 2018, future revenues from long-term natural gas storage and other contracts extending through 2033 are approximately $1.2 billion, of which approximately $283 million is expected to be recognized in 2019. The Company applies the practical expedients related to contracts that are for a duration of one year or less and where it recognizes 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.

ASSETS HELD FOR SALE

12 Months Ended

Dec. 31, 2018

Discontinued Operations and Disposal Groups [Abstract]

ASSETS HELD FOR SALE

Coolidge Generating Station

On December 14, 2018, TransCanada entered into an agreement to sell its Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC for approximately US$465 million, subject to timing of the close and related adjustments. In January 2019, pursuant to the terms of the Coolidge PPA, Salt River Project Agriculture Improvement and Power District, the counterparty to this arrangement, exercised their right of first refusal on this sale.

The sale will result in an estimated gain of approximately $65 million ($50 million after tax) including the impact of an estimated $10 million of foreign currency translation gains. This gain will be recognized upon closing of the sale transaction, which is expected to occur mid-2019.

At December 31, 2018, the related assets and liabilities were classified as held for sale in the Energy segment as follows:



(millions of Canadian $)

Assets held for sale
Accounts receivable	6
Plant, property and equipment	537
Total assets held for sale	543
Liabilities related to assets held for sale
Other long-term liabilities	(3	)
Total liabilities related to assets held for sale¹	(3	)


1	Included in Accounts payable and other on the Consolidated balance sheet.

OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2018

Other Assets [Abstract]

OTHER CURRENT ASSETS



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Fair value of derivative contracts (Note 24)	737	332
Contract assets (Note 5)	159	—
Regulatory assets (Note 10)	83	23
Cash provided as collateral	55	99
Prepaid expenses	41	109
Other	105	128
	1,180	691

PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

PLANT, PROPERTY AND EQUIPMENT



	2018			2017
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Canadian Natural Gas Pipelines
NGTL System
Pipeline	10,764	4,500	6,264	10,153	4,190	5,963
Compression	3,289	1,677	1,612	3,021	1,593	1,428
Metering and other	1,247	613	634	1,188	569	619
	15,300	6,790	8,510	14,362	6,352	8,010
Under construction	2,111	—	2,111	940	—	940
	17,411	6,790	10,621	15,302	6,352	8,950
Canadian Mainline
Pipeline	10,077	6,777	3,300	9,763	6,455	3,308
Compression	3,642	2,656	986	3,605	2,499	1,106
Metering and other	652	241	411	655	207	448
	14,371	9,674	4,697	14,023	9,161	4,862
Under construction	149	—	149	156	—	156
	14,520	9,674	4,846	14,179	9,161	5,018
Other Canadian Natural Gas Pipelines¹
Other	1,842	1,420	422	1,815	1,363	452
Under construction	124	—	124	4	—	4
	1,966	1,420	546	1,819	1,363	456
	33,897	17,884	16,013	31,300	16,876	14,424
U.S. Natural Gas Pipelines
Columbia Gas
Pipeline	6,711	251	6,460	3,550	125	3,425
Compression	2,932	132	2,800	1,547	64	1,483
Metering and other	2,884	75	2,809	2,306	37	2,269
	12,527	458	12,069	7,403	226	7,177
Under construction	4,347	—	4,347	3,332	—	3,332
	16,874	458	16,416	10,735	226	10,509
ANR
Pipeline	1,600	443	1,157	1,427	365	1,062
Compression	1,978	388	1,590	1,582	286	1,296
Metering and other	1,217	324	893	961	268	693
	4,795	1,155	3,640	3,970	919	3,051
Under construction	272	—	272	358	—	358
	5,067	1,155	3,912	4,328	919	3,409



	2018			2017
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Other U.S. Natural Gas Pipelines
GTN	2,322	951	1,371	2,107	822	1,285
Great Lakes	2,180	1,251	929	1,988	1,113	875
Columbia Gulf	1,753	74	1,679	1,115	37	1,078
Midstream	1,212	91	1,121	1,085	54	1,031
Other²	1,190	474	716	1,950	574	1,376
	8,657	2,841	5,816	8,245	2,600	5,645
Under construction	846	—	846	699	—	699
	9,503	2,841	6,662	8,944	2,600	6,344
	31,444	4,454	26,990	24,007	3,745	20,262
Mexico Natural Gas Pipelines
Pipeline	3,172	301	2,871	2,872	214	2,658
Compression	506	41	465	448	30	418
Metering and other	640	91	549	573	65	508
	4,318	433	3,885	3,893	309	3,584
Under construction	1,990	—	1,990	1,368	—	1,368
	6,308	433	5,875	5,261	309	4,952
Liquids Pipelines
Keystone Pipeline System
Pipeline	9,780	1,271	8,509	9,002	992	8,010
Pumping equipment	1,065	184	881	1,022	152	870
Tanks and other³	3,598	488	3,110	3,314	385	2,929
	14,443	1,943	12,500	13,338	1,529	11,809
Under construction⁴	18	—	18	456	—	456
	14,461	1,943	12,518	13,794	1,529	12,265
Intra-Alberta Pipelines⁵
Pipeline	762	22	740	748	3	745
Pumping equipment	104	3	101	104	—	104
Tanks and other	291	8	283	259	1	258
	1,157	33	1,124	1,111	4	1,107
Under construction	84	—	84	47	—	47
	1,241	33	1,208	1,158	4	1,154
	15,702	1,976	13,726	14,952	1,533	13,419
Energy
Natural Gas⁶	2,062	708	1,354	2,645	743	1,902
Wind⁷	—	—	—	673	204	469
Natural Gas Storage and Other	741	169	572	734	156	578
	2,803	877	1,926	4,052	1,103	2,949
Under construction	1,735	—	1,735	1,028	—	1,028
	4,538	877	3,661	5,080	1,103	3,977
Corporate	448	210	238	411	168	243
	92,337	25,834	66,503	81,011	23,734	57,277


1	Includes Foothills, Ventures LP, Great Lakes Canada and Coastal GasLink.


2	Includes Portland, North Baja, Tuscarora and Crossroads as well as Bison for 2017. Bison's remaining carrying value was fully impaired at December 31, 2018.


3	Includes tanks that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $194 million and $23 million, respectively, at December 31, 2018 (2017 – $184 million and $19 million, respectively), while revenues of $15 million were recognized in 2018 (2017 – $16 million; 2016 – $16 million).


4	Certain costs related to the Keystone XL project were recorded in Plant, property and equipment at December 31, 2017. In 2018, these costs were reclassified to Capital projects in development as the Company recommenced capitalizing Keystone XL development costs.

Includes Northern Courier and White Spruce. Northern Courier is accounted for as an operating lease and was placed in service on November 1, 2017. The cost and accumulated depreciation of this facility were $1,130 million and $32 million, respectively, at December 31, 2018 (2017 – $1,111 million and $4 million, respectively), while revenues of $142 million were recognized in 2018 (2017 – $20 million).

Includes Coolidge, Grandview, Bécancour, Halton Hills and the Alberta cogeneration natural gas-fired facilities. Coolidge, Grandview and Bécancour have long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $655 million and $268 million, respectively, at December 31, 2018 (2017 – $1,264 million and $354 million, respectively). At December 31, 2018, the cost and accumulated depreciation of Coolidge were reclassified to Assets held for sale. Refer to Note 6, Assets held for sale, for further information. Revenues of $216 million were recognized in 2018 (2017 – $215 million; 2016 – $212 million) through the sale of electricity under the related PPAs for these assets.


7	The Company closed the sale of its Cartier Wind power assets on October 24, 2018. Refer to Note 26, Acquisitions and dispositions, for further information.

Bison Impairment

At December 31, 2018, the Company evaluated its investment in its Bison natural gas pipeline for impairment in connection with the termination of certain customer transportation agreements. The termination of these agreements released the Company from providing any future services. With the loss of these future cash flows and the persistence of unfavourable market conditions which have inhibited system flows on the pipeline, the Company determined that the asset’s remaining carrying value was no longer recoverable and recognized a non-cash impairment charge of $722 million pre-tax in its U.S. Natural Gas Pipelines segment. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. As Bison is a TC PipeLines, LP asset, in which the Company has a 25.5 per cent interest, the Company's share of the impairment charge, after tax and net of non-controlling interests, was $140 million.

The termination of the transportation agreements resulted in the receipt of $130 million in termination payments which were recorded in Revenues in 2018. The Company's share of this amount, after tax and net of non-controlling interests, was $25 million.

Energy East and Related Projects Impairment

On October 5, 2017, the Company informed the NEB that it will not proceed with the Energy East, Eastern Mainline and Upland projects. Based on this decision, the Company evaluated the carrying value of its Property, plant and equipment related to the Eastern Mainline project including AFUDC. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties. As a result, the Company recognized a non-cash impairment charge of $83 million ($64 million after tax) in the Liquids Pipelines segment. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income.

Energy Turbine Impairment

At December 31, 2017, the Company recognized a non-cash impairment charge of $21 million ($16 million after tax) in the Energy segment related to the remaining carrying value of certain equipment after determining that it was no longer recoverable. This turbine equipment was previously purchased for a power development project that did not proceed. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income.

EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2018

Equity Method Investments and Joint Ventures [Abstract]

EQUITY INVESTMENTS



(millions of Canadian $)	Ownership Interest at December 31, 2018		Income/(Loss) from Equity Investments						Equity Investments
			year ended December 31						at December 31
			2018		2017		2016		2018	2017

Canadian Natural Gas Pipelines
TQM	50.0	%	12		11		12		71	68
U.S. Natural Gas Pipelines
Northern Border¹	50.0	%	87		87		92		677	641
Iroquois²	50.0	%	60		59		54		291	280
Millennium³	47.5	%	75		66		33		511	291
Pennant Midstream³	47.0	%	17		11		6		256	228
Other	Various		17		17		29		113	92
Mexico Natural Gas Pipelines
Sur de Texas⁴	60.0	%	27		66		(3	)	627	399
TransGas	nil		—		(12	)	—		—	—
Liquids Pipelines
Grand Rapids⁵	50.0	%	65		17		(1	)	1,028	996
Other⁶	Various		(1	)	(20	)	—		21	20
Energy
Bruce Power⁷	48.3	%	311		434		293		3,166	2,987
Portlands Energy⁸	50.0	%	36		31		33		289	301
ASTC Power Partnership	50.0	%	—		—		(37	)	—	—
Other	Various		8		6		3		63	63
			714		773		514		7,113	6,366


1	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company was US$115 million (2017 – US$115 million) due to the fair value assessment of assets at the time of acquisition.


2	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million (2017 – US$41 million) due mainly to the fair value assessment of the assets at the time of acquisition.


3	Acquired as part of Columbia Pipeline Group, Inc. (Columbia) on July 1, 2016. Income from Equity investments reflects equity earnings from the date of acquisition.


4	TransCanada has an ownership interest of 60.0 per cent in Sur de Texas which, as a jointly controlled entity, applies the equity method of accounting. Income from equity investments includes foreign exchange gains and losses recorded in the Corporate segment which are fully offset in Interest income and other in the Consolidated statement of income.


5	Grand Rapids was placed in service in August 2017. At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $102 million (2017 – $105 million) due mainly to interest capitalized during construction and the fair value of guarantees.


6	Includes investments in Canaport Energy East Marine Terminal Limited Partnership and HoustonLink Pipeline Company LLC. At December 31, 2018 and 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil.


7	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $870 million (2017 – $902 million) due to the fair value assessment of assets at the time of acquisitions.


8	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million (2017 – $73 million) due mainly to interest capitalized during construction.

TransGas de Occidente S.A. Impairment

In August 2017, TransCanada recognized an impairment charge of $12 million on its 46.5 per cent equity investment in TransGas de Occidente S.A. (TransGas). TransGas constructed and operated a natural gas pipeline in Colombia for a 20-year contract term. As per the terms of the agreement, upon completion of the 20-year contract in August 2017, TransGas transferred its pipeline assets to Transportadora de Gas Internacional S.A. The non-cash impairment charge represented the write-down of the remaining carrying value of the equity investment which was recognized in Income from equity investments in the Consolidated statement of income.

Canaport Energy East Marine Terminal Limited Partnership Impairment

On October 5, 2017, the Company informed the NEB that it will not be proceeding with the Energy East, Eastern Mainline and Upland projects. As a result, in October 2017, the Company recognized a non-cash impairment charge of $20 million in Income from equity investments in its Liquids Pipelines segment which represented the carrying value of the equity investment in the Canaport Energy East Marine Terminal Limited Partnership. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties.

ASTC Power Partnership Impairment

In March 2016, TransCanada issued notice to the Balancing Pool of the decision to terminate its Sundance B PPA held through ASTC Power Partnership. In accordance with a provision in the PPA, a buyer was permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. As a result of changes in law surrounding the Alberta Specified Gas Emitters Regulation, the Company expected increasing costs related to carbon emissions to continue throughout the remaining term of the PPA resulting in increasing unprofitability. As a result, in first quarter 2016, the Company recognized a non-cash impairment charge of $29 million ($21 million after tax) in its Energy segment Income from equity investments which represented the carrying value of the equity investment in ASTC Partnership. The PPA termination was settled in December 2016.

Distributions and Contributions

Distributions received from equity investments for the year ended December 31, 2018 were $1,106 million (2017 – $1,332 million; 2016 – $1,571 million) of which $121 million (2017 – $362 million; 2016 – $727 million) was included in Investing activities in the Consolidated statement of cash flows with respect to distributions received from Bruce Power from its financing program.

Contributions made to equity investments for the year ended December 31, 2018 were $1,015 million (2017 – $1,681 million;

2016 – $765 million) and are included in Investing activities in the Consolidated statement of cash flows. For 2018, contributions include $179 million (2017 – $977 million) related to TransCanada's proportionate share of the Sur de Texas debt financing requirements.

Summarized Financial Information of Equity Investments



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Income
Revenues	4,836		4,913		4,336
Operating and other expenses	(3,545	)	(2,993	)	(3,068	)
Net income	1,515		1,636		1,080
Net income attributable to TransCanada	714		773		514



at December 31	2018		2017
(millions of Canadian $)	2018		2017

Balance Sheet
Current assets	2,209		2,176
Non-current assets	20,647		17,869
Current liabilities	(2,049	)	(1,577	)
Non-current liabilities	(9,042	)	(8,217	)

Loan receivable from affiliate

TransCanada holds a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. In 2017, TransCanada entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. At December 31, 2018, the Company’s consolidated balance sheet included a MXN$18.9 billion or $1.3 billion (2017 – MXN$14.4 billion or $0.9 billion) loan receivable from the Sur de Texas joint venture which represents TransCanada’s proportionate share of long-term debt financing requirements related to the joint venture. Interest income and other included interest income of $120 million in 2018 (2017 – $34 million) from this joint venture with a corresponding proportionate share of interest expense recorded in Income from equity investments.

RATE-REGULATED BUSINESSES

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

RATE-REGULATED BUSINESSES

TransCanada's businesses that apply RRA currently include certain Canadian, U.S. and Mexico natural gas pipelines, and certain regulated U.S. natural gas storage operations. Rate-regulated businesses account for and report assets and liabilities consistent with the resulting economic impact of the regulators' established rates, provided the rates are designed to recover the costs of providing the regulated service and the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination that would otherwise be reflected in the statement of income are deferred on the balance sheet and are expected to be included in future service rates and recovered from or refunded to customers in subsequent years.

Canadian Regulated Operations

TransCanada's Canadian natural gas pipelines are regulated by the NEB under the National Energy Board Act. The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems.

TransCanada's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return on capital as approved by the NEB. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent actual costs and revenues are more or less than forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur. The Company's most significant regulated Canadian natural gas pipelines are described below.

NGTL System

NGTL's 2018 results reflect the terms of the 2018-2019 Revenue Requirement Settlement (the 2018-2019 Settlement) approved by the NEB in June 2018. This two-year settlement includes an ROE of 10.1 per cent on 40 per cent deemed common equity, a composite depreciation rate of approximately 3.5 per cent, a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration (OM&A) cost amount and flow-through treatment of all other costs.

Canadian Mainline

The Canadian Mainline currently operates under the terms of the 2015-2030 Tolls Application approved in 2014 (the NEB 2014 Decision). The terms of the settlement include an ROE of 10.1 per cent on deemed common equity of 40 per cent, an incentive mechanism that has both upside and downside risk and a $20 million after-tax annual TransCanada contribution to reduce the revenue requirement. Toll stabilization is achieved through the use of deferral accounts, namely the bridging amortization account and the long-term adjustment account (LTAA), to capture the surplus or shortfall between the Company's revenues and cost of service for each year over the 2015-2020 six-year fixed toll term of the NEB 2014 Decision. The NEB 2014 Decision also directed TransCanada to file an application to review tolls for the 2018-2020 period. In December 2018, an NEB decision was received on the 2018-2020 Tolls Review (NEB 2018 Decision) which included an accelerated amortization of the December 31, 2017 LTAA balance and an increase to the composite depreciation rate from 3.2 per cent to 3.9 per cent.

U.S. Regulated Operations

TransCanada's U.S. regulated natural gas pipelines operate under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities, including the regulation of tariffs which incorporates maximum and minimum rates for services and allows U.S. regulated natural gas pipelines to discount or negotiate rates on a non-discriminatory basis. The Company's most significant regulated U.S. natural gas pipelines, based on effective ownership and total operated pipe length, are described below.

In 2018, FERC prescribed changes (2018 FERC Actions) related to U.S. Tax Reform and income taxes for rate-making purposes in a master limited partnership (MLP) that impact future earnings and cash flows of FERC-regulated pipelines. The 2018 FERC Actions also established a process and schedule by which all FERC-regulated interstate pipelines and natural gas storage facilities had to either (i) file a new uncontested rate settlement or (ii) file a FERC Form 501-G that quantifies the isolated impact of U.S. Tax Reform on FERC-regulated pipelines and natural gas storage assets as well as the impact of the 2018 FERC Actions on pipelines held by MLPs.

The impact of the 2018 FERC Actions on the Company's more significant U.S. regulated natural gas pipelines is included below.

Columbia Gas

Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval. In 2013, the FERC approved a modernization settlement which provides for cost recovery and return on investment of up to US$1.5 billion over a five-year period to modernize the Columbia Gas system to improve system integrity and enhance service reliability and flexibility. In March 2016, an extension of this settlement was approved by the FERC, which will allow for the cost recovery and return on additional expanded scope investment of US$1.1 billion over a three-year period through 2020.

In response to the 2018 FERC Actions, Columbia Gas filed a Form 501-G including a statement explaining its rationale why the pipeline’s rates are not required to change.

ANR Pipeline

ANR Pipeline operates under rates established under a FERC-approved rate settlement in 2016. Under terms of the 2016 settlement, neither ANR Pipeline nor the settling parties could file for new rates to become effective earlier than August 1, 2019. However, ANR Pipeline is required to file for new rates to be effective no later than August 1, 2022.

In December 2018, ANR Pipeline filed a Form 501-G including a statement explaining its rationale why the pipeline’s rates are not required to change.

Columbia Gulf

Columbia Gulf’s natural gas transportation services are provided under a tariff at rates subject to FERC approval. In September 2016, FERC issued an order approving an uncontested settlement following a FERC-initiated rate proceeding pursuant to Section 5 of the NGA, which required a reduction in Columbia Gulf’s daily maximum recourse rate and addressed treatment of post-retirement benefits other than pensions, pension expense and regulatory expenses. The FERC order also required Columbia Gulf to file a general rate case under section 4 of the NGA by January 31, 2020, for rates to take effect by August 1, 2020.

In response to the 2018 FERC Actions, Columbia Gulf filed a Form 501-G including a statement explaining its rationale why the pipeline’s rates are not required to change.

TC PipeLines, LP

TransCanada owns a 25.5 per cent interest in TC PipeLines, LP, which has ownership interests in eight wholly-owned or partially-owned natural gas pipelines serving major markets in the U.S. As TC PipeLines, LP is an MLP, all pipelines it owns wholly or in part were potentially impacted by the 2018 FERC Actions which creates a presumption that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in their regulated cost-of-service rates. Additionally, to the extent an entity’s income tax allowance is eliminated from rates, it must also eliminate its existing accumulated deferred income tax (ADIT) balance from its rate base. Refer to Note 16, Income Taxes for further information regarding the impact of these changes to TransCanada.

Great Lakes

Great Lakes reached a rate settlement with its customers, which was approved by FERC on February 22, 2018, decreasing Great Lakes' maximum transportation rates by 27 per cent effective October 1, 2017. This settlement does not contain a moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022. As a result of the 2018 FERC Actions, Great Lakes made a limited Section 4 filing which had the effect of reducing rates by 2 per cent from what was in place prior to the FERC changes in 2018. The reduction in rates became effective on February 1, 2019 after the limited Section 4 filing was accepted by FERC on January 31, 2019.

Mexico Regulated Operations

TransCanada's Mexico natural gas pipelines are regulated by the CRE and operate in accordance with CRE-approved tariffs. The rates in effect on TransCanada's Mexico natural gas pipelines were established based on CRE-approved contracts that provide for the recovery of costs of providing services and a return on and of invested capital.

Regulatory Assets and Liabilities



at December 31	2018	2017	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)	2018	2017	Remaining Recovery/ Settlement Period (years)

Regulatory Assets
Deferred income taxes¹	1,051	940	n/a
Operating and debt-service regulatory assets²	12	—	1
Pensions and other post-retirement benefits^1,3	379	388	n/a
Foreign exchange on long-term debt^1,4	46	—	1-11
Other	143	71	n/a
	1,631	1,399
Less: Current portion included in Other current assets (Note 7)	83	23
	1,548	1,376

Regulatory Liabilities
Operating and debt-service regulatory liabilities²	96	188	1
Pensions and other post-retirement benefits³	53	164	n/a
ANR related post-employment and retirement benefits other than pension⁵	54	66	n/a
Long term adjustment account⁶	1,015	1,142	2-45
Bridging amortization account⁶	305	202	12
Pipeline abandonment trust balance	1,113	825	n/a
Cost of removal⁷	261	216	n/a
Deferred income taxes	165	75	n/a
Deferred income taxes – U.S. Tax Reform⁸	1,394	1,659	n/a
Other	65	47	n/a
	4,521	4,584
Less: Current portion included in Accounts payable and other (Note 14)	591	263
	3,930	4,321


1	These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.


2	Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulator for inclusion in determining tolls for the following calendar year.


3	These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates.

Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls.

This balance represents the amount ANR estimates it would be required to refund to its customers for post-retirement and post-employment benefit amounts collected through its FERC-approved rates that have not been used to pay benefits to its employees. Pursuant to a FERC-approved September 2016 rate settlement, $11 million (US$8 million) of the regulatory liability balance at December 31, 2018 (2017 – $26 million; US$21 million) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $43 million (US$32 million) balance accumulated prior to 2007 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period cannot be determined at this time.


6	These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. The 2018 LTAA balance of $1,015 million consists of $932 million to be amortized over two years with the remaining balance to be amortized over 45 years.


7	This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated operations for future costs to be incurred.


8	These balances represent the impact of U.S. Tax Reform. The regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax liabilities that gave rise to the regulatory liabilities. See Note 16, Income taxes, for further information on U.S. Tax Reform.

GOODWILL

12 Months Ended

Dec. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL

The Company has recorded the following Goodwill on its acquisitions:



(millions of Canadian $)	U.S. Natural Gas Pipelines

Balance at January 1, 2017	13,958
Columbia adjustment (Note 26)	71
Foreign exchange rate changes	(945	)
Balance at December 31, 2017	13,084
Tuscarora impairment charge	(79	)
Foreign exchange rate changes	1,173
Balance at December 31, 2018	14,178

Tuscarora

In the fourth quarter of 2018, the Company finalized its regulatory filing for Tuscarora in response to the 2018 FERC Actions and Form 501-G requirements. In January 2019, Tuscarora reached a settlement-in-principle with its customers which was filed with FERC. As a result of these developments, as well as changes to other valuation assumptions responsive to Tuscarora’s commercial environment, it was determined that the fair value of Tuscarora did not exceed its carrying value, including goodwill. The fair value of the reporting unit was determined using a discounted cash flow analysis. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. As a result, the Company recorded a goodwill impairment charge of $79 million pre-tax within the U.S. Natural Gas Pipelines segment. This non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. As Tuscarora is a TC PipeLines, LP asset, the Company's share of this amount, after tax and net of non-controlling interests, was $15 million. The goodwill balance related to Tuscarora at December 31, 2018 was US$23 million (2017 – US$82 million).

Great Lakes

At December 31, 2018, the estimated fair value of Great Lakes exceeded its carrying value by less than 10 per cent. The fair value of this reporting unit was measured using a discounted cash flow analysis in its most recent valuation. Assumptions used in the analysis regarding Great Lakes’ ability to realize long-term value in the North American energy market included the impact of its 501-G election, revenue opportunities on the system as well as changes to other valuation assumptions responsive to Great Lakes’ commercial environment. Although evolving market conditions and other factors relevant to Great Lakes’ long term financial performance have been positive, there is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in a future impairment of a portion of the goodwill balance relating to Great Lakes. The goodwill balance related to Great Lakes at December 31, 2018 was US$573 million (2017 – US$573 million).

Ravenswood

As a result of information received during the process to monetize the Company's U.S. Northeast power business in third quarter 2016, it was determined that the fair value of Ravenswood did not exceed its carrying value, including goodwill. The fair value of the reporting unit was determined using a combination of methods including a discounted cash flow analysis and a range of expected consideration from a potential sale. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. As a result, in 2016, the Company recorded a goodwill impairment charge on the full carrying value of Ravenswood goodwill of $1,085 million ($656 million after tax) within the Energy segment.

INTANGIBLE AND OTHER ASSETS

12 Months Ended

Dec. 31, 2018

Intangible Assets, Net (Excluding Goodwill) [Abstract]

INTANGIBLE AND OTHER ASSETS



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Capital projects in development	1,051	596
Deferred income tax assets (Note 16)	322	316
Employee post-retirement benefits (Note 23)	192	193
Fair value of derivative contracts (Note 24)	61	73
Other	295	306
	1,921	1,484

Capital projects in development

Keystone XL

In January 2018, the Company recommenced capitalizing development costs related to Keystone XL. In addition, certain project costs that were recorded in Plant, property and equipment at December 31, 2017 were transferred to Capital projects in development in 2018. These costs were related to the net realizable value of Keystone XL assets after an impairment charge was recorded in 2015. As a result, at December 31, 2018, Capital projects in development for this project were $0.8 billion (2017 – nil).

Reimbursement of Coastal GasLink pipeline costs

In accordance with provisions in the agreements with the LNG Canada joint venture participants, all five parties elected to reimburse TransCanada for their share of costs incurred prior to receiving the Final Investment Decision (FID) on the Coastal GasLink pipeline project. In November 2018, the Company received payments totaling $470 million which were recorded as a reduction of the carrying value of Coastal GasLink.

Prince Rupert Gas Transmission

In July 2017, the Company was notified that Pacific Northwest LNG would not be proceeding with its proposed LNG project and that Progress Energy (Progress) would be terminating its agreement with TransCanada for the development of the PRGT project effective August 10, 2017. In accordance with the terms of the agreement, all project costs incurred to advance the project, including carrying charges, were fully recoverable upon termination. In October 2017, the Company received full payment of the $634 million reimbursement from Progress.

Energy East and Related Projects Impairment

On October 5, 2017, the Company informed the NEB that it will not proceed with the Energy East, Eastern Mainline and Upland projects. Based on this decision, the Company evaluated its Capital projects in development balance related to the Energy East and Upland projects including AFUDC. As a result, the Company recognized a non-cash impairment charge of $1,153 million ($870 million after tax) in the Liquids Pipelines segment. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income.

Power Purchase Arrangements Impairment

In March 2016, TransCanada terminated its Sheerness and Sundance A PPAs. In accordance with a provision in the PPAs, a buyer was permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. The Company expected increasing costs related to carbon emissions to continue throughout the remaining terms of the PPAs resulting in increasing unprofitability. As such, in 2016, the Company recognized a non-cash impairment charge of $211 million ($155 million after tax) in its Energy segment, representing the carrying value of the PPAs which was recorded in Intangible and other assets. In December 2016, TransCanada transferred to the Balancing Pool a package of environmental credits that were being held to offset the PPA emissions costs and recorded a non-cash charge of $92 million ($68 million after tax) related to the carrying value of these environmental credits.

NOTES PAYABLE

12 Months Ended

Dec. 31, 2018

Short-term Debt [Abstract]

NOTES PAYABLE



	2018			2017
(millions of Canadian $, unless otherwise noted)	Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31		Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31

Canada	2,117	2.5	%	884	1.6	%
U.S. (2018 – US$448; 2017 – US$688)	611	3.1	%	862	2.2	%
Mexico (2018 – US$25; 2017 – MXN$275)	34	3.3	%	17	8.0	%
	2,762			1,763

At December 31, 2018, Notes payable consists of short-term borrowings in Canada by TransCanada PipeLines Limited (TCPL), in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA) and TransCanada American Investments Ltd. (TAIL), and in Mexico by a Mexican subsidiary.

At December 31, 2018, total committed revolving and demand credit facilities were $12.9 billion (2017 – $11.0 billion). When drawn, interest on these lines of credit is charged at negotiated floating rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:

at December 31

(billions of Canadian $, unless otherwise noted)

2018

2017

Borrower

Description

Matures

Total Facilities

Unused Capacity

Total Facilities

Committed, syndicated, revolving, extendible, senior unsecured credit facilities¹:

TCPL

Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes

December 2023

3.0

TCPL/TCPL USA/Columbia/TAIL

Supports TCPL, TCPL USA and TAIL's U.S. dollar commercial paper programs and is used for general corporate purposes of the borrowers, guaranteed by TCPL

December 2019

US 4.5

—

TCPL/TCPL USA/Columbia/TAIL

Used for general corporate purposes of the borrowers, guaranteed by TCPL

December 2021

US 1.0

—

TCPL

Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes

—

US 2.0

TCPL USA

Used for TCPL USA general corporate purposes, guaranteed by TCPL

—

US 1.0

Columbia

Used for Columbia general corporate purposes, guaranteed by TCPL

—

US 1.0

TAIL

Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL

—

US 0.5

Demand senior unsecured revolving credit facilities¹:

TCPL/TCPL USA

Supports the issuance of letters of credit and provides additional liquidity, TCPL USA facility guaranteed by TCPL

Demand

2.1

1.0

1.9

Mexico subsidiary

Used for Mexico general corporate purposes, guaranteed by TCPL

Demand

MXN 5.0

MXN 4.5

MXN 5.0

Provisions of various credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2018, the Company was in compliance with all debt covenants.

For the year ended December 31, 2018, the cost to maintain the above facilities was $12 million (2017 – $7 million; 2016 – $10 million).

At December 31, 2018, the Company's operated affiliates had an additional $0.8 billion (2017 – $0.4 billion) of undrawn capacity on committed credit facilities.

ACCOUNTS PAYABLE AND OTHER

12 Months Ended

Dec. 31, 2018

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE AND OTHER



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Trade payables	3,224	2,847
Fair value of derivative contracts (Note 24)	922	387
Unredeemed shares of Columbia	357	312
Regulatory liabilities (Note 10)	591	263
Other	314	248
	5,408	4,057

OTHER LONG-TERM LIABILITIES

12 Months Ended

Dec. 31, 2018

Deferred Costs, Noncurrent [Abstract]

OTHER LONG-TERM LIABILITIES



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Employee post-retirement benefits (Note 23)	569	389
Asset retirement obligations	90	98
Fair value of derivative contracts (Note 24)	42	72
Guarantees (Note 27)	12	16
Other	295	152
	1,008	727

INCOME TAXES

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

INCOME TAXES

U.S. Tax Reform

On December 22, 2017, the President of the United States signed H.R.1, the Tax Cuts and Jobs Act (U.S. Tax Reform or the Act) into law. As a result, among other things, the enacted U.S. federal corporate income tax rate was reduced from 35 per cent to 21 per cent effective January 1, 2018 and resulted in a remeasurement of existing deferred income tax assets and deferred income tax liabilities related to the Company's U.S. businesses to reflect the new lower income tax rate as at December 31, 2017.

For the Company’s U.S. businesses not subject to RRA, the reduction in enacted income tax rates resulted in a decrease in net deferred income tax liabilities and a deferred income tax recovery of $816 million in 2017. For the Company’s U.S. businesses subject to RRA, the reduction in income tax rates resulted in a reduction in net deferred income tax liabilities and the recognition of a net regulatory liability of $1,686 million on the Consolidated balance sheet at December 31, 2017.

Net deferred income tax liabilities related to the cumulative remeasurements of employee post-retirement benefits included in AOCI were also adjusted with a corresponding increase in deferred income tax expense of $12 million in 2017.

Given the significance of the legislation, the U.S. Securities and Exchange Commission (SEC) staff issued guidance which allowed registrants to record provisional amounts at December 31, 2017 which may be adjusted as information becomes available, prepared or analyzed during a measurement period not to exceed one year. The SEC guidance summarized a three-step process to be applied at each reporting period to identify: (1) where the accounting is complete; (2) provisional amounts where the accounting is not yet complete, but a reasonable estimate has been determined; and (3) where a reasonable estimate cannot yet be determined and therefore income taxes are reflected in accordance with law prior to the enactment of the Act.

At December 31, 2017, the Company considered amounts recorded related to U.S. Tax Reform to be reasonable estimates, however, certain amounts were provisional as the Company’s interpretation, assessment and presentation of the impact of the tax law change were further clarified with additional guidance from regulatory, tax and accounting authorities received in 2018. With additional guidance provided during the one-year measurement period and upon finalizing its 2017 annual tax return for its U.S. businesses, in fourth quarter 2018 the Company recognized further adjustments to its deferred income tax liability and net regulatory liability balances as well as a deferred income tax recovery of $52 million in fourth quarter 2018.

In addition, the 2018 FERC Actions established that, to the extent an entity’s income tax allowance should be eliminated from rates, it must also eliminate its existing ADIT balance from its rate base. In accordance with the FERC Form 501-G and uncontested rate settlement filings, the ADIT balances for all pipelines held wholly or in part by TC PipeLines, LP were eliminated from their respective rate bases. As a result, net regulatory liabilities recorded for these assets pursuant to U.S. Tax Reform were written off, resulting in a further deferred income tax recovery of $115 million in fourth quarter 2018.

Commencing January 1, 2018, the Company amortized the net regulatory liabilities, recorded per U.S. Tax Reform, using the Reverse South Georgia methodology. Under this methodology, rate-regulated entities determine and immediately begin recording amortization based on their composite depreciation rates. In 2018, amortization of these net regulatory liabilities in the amount of $58 million was recorded and included in Revenues in the Consolidated statement of income. The net regulatory liability related to U.S. Tax Reform at December 31, 2018 was $1,394 million (2017 – $1,686 million).

Further to U.S. Tax Reform, the U.S. Treasury and the U.S. Internal Revenue Service issued proposed regulations in November and December of 2018 which provided administrative guidance and clarified certain aspects of the new laws with respect to interest deductibility, base erosion and anti-abuse tax, the new dividend received deduction and anti-hybrid rules. Based on the Company's review and analysis of these proposed regulations, no material adjustments were recorded in the 2018 Consolidated financial statements. The proposed regulations are complex and comprehensive, and considerable uncertainty continues to exist until the final regulations are released, which is expected to occur later in 2019. TransCanada continues to review and analyze these proposed regulations as well as assess their potential impact on the Company.

Provision for Income Taxes



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Current
Canada	65		113		116
Foreign	250		36		40
	315		149		156
Deferred
Canada	49		(185	)	101
Foreign	235		751		95
Foreign – U.S. Tax Reform and 2018 FERC Actions	(167	)	(804	)	—
	117		(238	)	196
Income Tax Expense/(Recovery)	432		(89	)	352

Geographic Components of Income before Income Taxes



year ended December 31	2018	2017		2016
(millions of Canadian $)	2018	2017		2016

Canada	433	(339	)	219
Foreign	3,516	3,645		618
Income before Income Taxes	3,949	3,306		837

Reconciliation of Income Tax Expense/(Recovery)



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Income before income taxes	3,949		3,306		837
Federal and provincial statutory tax rate	27	%	27	%	27	%
Expected income tax expense	1,066		893		226
U.S. Tax Reform and 2018 FERC Actions	(167	)	(804	)	—
Foreign income tax rate differentials	(432	)	(81	)	(196	)
Loss/(income) from equity investments and non-controlling interests	50		(64	)	(68	)
Income tax differential related to regulated operations	(54	)	(42	)	81
Non-taxable portion of capital gains	(11	)	(42	)	—
Asset impairment charges¹	—		34		242
Non-deductible amounts	—		4		46
Other	(20	)	13		21
Income Tax Expense/(Recovery)	432		(89	)	352


1	Net of nil (2017 – nil, 2016 – $112 million) attributed to higher foreign tax rates.

Deferred Income Tax Assets and Liabilities



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Deferred Income Tax Assets
Tax loss and credit carryforwards	1,238	1,379
Difference in accounting and tax bases of impaired assets and assets held for sale	574	651
Regulatory and other deferred amounts	858	512
Unrealized foreign exchange losses on long-term debt	491	216
Financial instruments	—	10
Other	292	227
	3,453	2,995
Less: valuation allowance	1,159	832
	2,294	2,163
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,449	6,240
Equity investments	1,069	632
Taxes on future revenue requirement	300	238
Other	180	140
	7,998	7,250
Net Deferred Income Tax Liabilities	5,704	5,087

The above deferred tax amounts have been classified in the Consolidated balance sheet as follows:



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Deferred Income Tax Assets
Intangible and other assets (Note 12)	322	316
Deferred Income Tax Liabilities
Deferred income tax liabilities	6,026	5,403
Net Deferred Income Tax Liabilities	5,704	5,087

At December 31, 2018, the Company has recognized the benefit of unused non-capital loss carryforwards of $1,867 million (2017 – $1,280 million) for federal and provincial purposes in Canada, which expire from 2030 to 2038. The Company has not recognized the benefit of capital loss carry forwards of $821 million (2017 – $668 million) for federal and provincial purposes in Canada. The Company also has recognized the benefit of Ontario minimum tax credits of $91 million (2017 – $82 million), which expire from 2026 to 2038.

At December 31, 2018, the Company has recognized the benefit of unused net operating loss carryforwards of US$889 million (2017 – US$1,800 million) for federal purposes in the U.S., which expire from 2029 to 2037. The Company has not recognized the benefit of unused net operating loss carryforwards of US$706 million (2017 – US$710 million) for federal purposes in the U.S. The Company also has recognized the benefit of alternative minimum tax credits of US$1 million (2017 – US$56 million).

At December 31, 2018, the Company has recognized the benefit of unused net operating loss carryforwards of US$3 million (2017 – US$7 million) in Mexico, which expire from 2024 to 2028.

Unremitted Earnings of Foreign Investments

Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2018 by approximately $619 million (2017 – $569 million) if there had been a provision for these taxes.

Income Tax Payments

Income tax payments of $338 million, net of refunds, were made in 2018 (2017 – payments, net of refunds, of $247 million; 2016 – payments, net of refunds, of $105 million).

Reconciliation of Unrecognized Tax Benefit

Below is the reconciliation of the annual changes in the total unrecognized tax benefit:



at December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Unrecognized tax benefit at beginning of year	15		18		17
Gross increases – tax positions in prior years	13		—		3
Gross decreases – tax positions in prior years	(5	)	(1	)	—
Gross increases – tax positions in current year	—		2		2
Settlement	—		—		(1	)
Lapse of statutes of limitations	(4	)	(4	)	(3	)
Unrecognized Tax Benefit at End of Year	19		15		18

Subject to the results of audit examinations by taxing authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on its financial statements.

TransCanada and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2010. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2011.

TransCanada's practice is to recognize interest and penalties related to income tax uncertainties in Income tax expense. Income tax expense for the year ended December 31, 2018 reflects $1 million of interest recovery and nil for penalties (2017 – nil of interest expense and nil for penalties; 2016 – nil of interest expense and nil for penalties). At December 31, 2018, the Company had $3 million accrued for interest expense and nil accrued for penalties (December 31, 2017 – $4 million accrued for interest expense and nil accrued for penalties).

LONG-TERM DEBT

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

LONG-TERM DEBT



		2018			2017
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate¹		Outstanding at December 31	Interest Rate¹
(millions of Canadian $, unless otherwise noted)	Maturity Dates	Outstanding at December 31	Interest Rate¹		Outstanding at December 31	Interest Rate¹

TRANSCANADA PIPELINES LIMITED
Debentures
Canadian	2019 to 2020	350	11.4	%	500	10.8	%
U.S. (2018 and 2017 – US$400)	2021	546	9.9	%	501	9.9	%
Medium Term Notes
Canadian	2019 to 2048	7,504	4.8	%	6,504	4.9	%
Senior Unsecured Notes
U.S. (2018 – US$17,192; 2017 – US$14,892)	2019 to 2049	23,456	5.1	%	18,644	5.1	%
		31,856			26,149
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian	2024	100	9.9	%	100	9.9	%
U.S. (2018 and 2017 – US$200)	2023	273	7.9	%	250	7.9	%
Medium Term Notes
Canadian	2025 to 2030	504	7.4	%	504	7.4	%
U.S. (2018 and 2017 – US$33)	2026	44	7.5	%	41	7.5	%
		921			895
COLUMBIA PIPELINE GROUP, INC.
Senior Unsecured Notes
U.S. (2018 – US$2,250; 2017 – US$2,750)²	2020 to 2045	3,070	4.4	%	3,443	4.0	%
TC PIPELINES, LP
Unsecured Loan Facility
U.S. (2018 – US$40; 2017 – US$185)	2021	55	3.8	%	232	2.7	%
Unsecured Term Loan
U.S. (2018 – US$500; 2017 – US$670)³	2022	682	3.6	%	839	2.7	%
Senior Unsecured Notes
U.S. (2018 and 2017 – US$1,200)	2021 to 2027	1,637	4.4	%	1,502	4.4	%
		2,374			2,573
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2018 and 2017 – US$672)	2021 to 2026	918	7.2	%	842	7.2	%
GAS TRANSMISSION NORTHWEST LLC
Unsecured Term Loan
U.S. (2018 – US$35; 2017 – US$55)	2019	48	3.3	%	69	1.1	%
Senior Unsecured Notes
U.S. (2018 and 2017 – US$250)	2020 to 2035	341	5.6	%	313	5.6	%
		389			382
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2018 – US$240; 2017 – US$259)	2021 to 2030	327	7.7	%	324	7.7	%



		2018				2017
Outstanding amounts	Maturity Dates	Outstanding at December 31		Interest Rate¹		Outstanding at December 31		Interest Rate¹
(millions of Canadian $, unless otherwise noted)	Maturity Dates	Outstanding at December 31		Interest Rate¹		Outstanding at December 31		Interest Rate¹

PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Unsecured Loan Facility
U.S. (2018 – US$19; 2017 – nil)	2023	26		3.6	%	—		—
Senior Secured Notes⁴
U.S. (2018 – nil; 2017 – US$30)		—		—		38		6.0	%
		26				38
TUSCARORA GAS TRANSMISSION COMPANY
Unsecured Term Loan
U.S. (2018 – US$24; 2017 – US$25)	2020	33		3.5	%	31		1.1	%
NORTH BAJA PIPELINE, LLC
Unsecured Term Loan
U.S. (2018 – US$50; 2017 – nil)	2021	68		3.5	%	—		—
		39,982				34,677
Current portion of long-term debt		(3,462	)			(2,866	)
Unamortized debt discount and issue costs		(241	)			(174	)
Fair value adjustments⁵		230				238
		36,509				31,875

Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premium and discounts. Weighted average and effective interest rates are stated as at the respective outstanding dates.


2	Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia’s obligations is required to comply with covenants under the debt indenture and in the event of default, the guarantors would be obligated to pay the principal and related interest.


3	The US$500 million term loan facility was amended in September 2017 to extend the maturity dates from 2018 to 2022.


4	These notes were secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.


5	The fair value adjustments include $232 million (2017 – $242 million) related to the acquisition of Columbia. The fair value adjustments also include a decrease of $2 million (2017 – $4 million) related to hedged interest rate risk. Refer to Note 24, Risk management and financial instruments, for further information.

Principal Repayments

At December 31, 2018, principal repayments for the next five years on the Company's long-term debt are approximately as follows:



(millions of Canadian $)	2019	2020	2021	2022	2023

Principal repayments on long-term debt	3,465	2,834	2,098	2,100	1,930

Long-Term Debt Issued

The Company issued long-term debt over the three years ended December 31, 2018 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Issue Date

Type

Maturity Date

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

October 2018

Senior Unsecured Notes

March 2049

US 1,000

5.10

October 2018

Senior Unsecured Notes

May 2028

US 400

4.25

July 2018

Medium Term Notes

July 2048

800

4.18

July 2018

Medium Term Notes

March 2028

200

3.39

May 2018

Senior Unsecured Notes

May 2028

US 1,000

4.25

May 2018

Senior Unsecured Notes

May 2048

US 1,000

4.875

May 2018

Senior Unsecured Notes

May 2038

US 500

4.75

November 2017

Senior Unsecured Notes

November 2019

US 550

Floating

November 2017

Senior Unsecured Notes

November 2019

US 700

2.125

September 2017

Medium Term Notes

March 2028

300

3.39

September 2017

Medium Term Notes

September 2047

700

4.33

June 2016

Acquisition Bridge Facility³

June 2018

US 5,213

Floating

June 2016

Medium Term Notes

July 2023

300

3.69

⁴

June 2016

Medium Term Notes

June 2046

700

4.35

January 2016

Senior Unsecured Notes

January 2026

US 850

4.875

January 2016

Senior Unsecured Notes

January 2019

US 400

3.125

NORTH BAJA PIPELINE, LLC

December 2018

Unsecured Term Loan

December 2021

US 50

Floating

PORTLAND NATURAL GAS TRANSMISSION SYSTEM

April 2018

Unsecured Loan Facility

April 2023

US 19

Floating

TUSCARORA GAS TRANSMISSION COMPANY

August 2017

Unsecured Term Loan

August 2020

US 25

Floating

April 2016

Unsecured Term Loan

April 2019

US 10

Floating

TC PIPELINES, LP

May 2017

Senior Unsecured Notes

May 2027

US 500

3.90

TRANSCANADA PIPELINE USA LTD.

June 2016

Acquisition Bridge Facility³

June 2018

US 1,700

Floating

ANR PIPELINE COMPANY

June 2016

Senior Unsecured Notes

June 2026

US 240

4.14


1	Reflects coupon rate on re-opening of a pre-existing senior unsecured notes issue. The notes were issued at a discount to par, resulting in a re-issuance yield of 4.439 per cent.


2	Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at a discount to par, resulting in a re-issuance yield of 3.41 per cent.


3	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the issuance of common shares in fourth quarter 2016 and 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.


4	Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent.

Long-Term Debt Retired

The Company retired/repaid long-term debt over the three years ended December 31, 2018 as follows:



(millions of Canadian $, unless otherwise noted)
Company	Retirement/Repayment Date	Type	Amount	Interest Rate

TRANSCANADA PIPELINES LIMITED
	August 2018	Senior Unsecured Notes	US 850	6.50	%
	March 2018	Debentures	150	9.45	%
	January 2018	Senior Unsecured Notes	US 500	1.875	%
	January 2018	Senior Unsecured Notes	US 250	Floating
	December 2017	Debentures	100	9.80	%
	November 2017	Senior Unsecured Notes	US 1,000	1.625	%
	June 2017	Acquisition Bridge Facility¹	US 1,513	Floating
	February 2017	Acquisition Bridge Facility¹	US 500	Floating
	January 2017	Medium Term Notes	300	5.10	%
	November 2016	Acquisition Bridge Facility¹	US 3,200	Floating
	October 2016	Medium Term Notes	400	4.65	%
	June 2016	Senior Unsecured Notes	US 84	7.69	%
	June 2016	Senior Unsecured Notes	US 500	Floating
	January 2016	Senior Unsecured Notes	US 750	0.75	%
TC PIPELINES, LP
	December 2018	Unsecured Term Loan	US 170	Floating
COLUMBIA PIPELINE GROUP, INC.
	June 2018	Senior Unsecured Notes	US 500	2.45	%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
	May 2018	Senior Secured Notes	US 18	5.90	%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
	March 2018	Senior Unsecured Notes	US 9	6.73	%
TUSCARORA GAS TRANSMISSION COMPANY
	August 2017	Senior Secured Notes	US 12	3.82	%
TRANSCANADA PIPELINE USA LTD.
	June 2017	Acquisition Bridge Facility¹	US 630	Floating
	April 2017	Acquisition Bridge Facility¹	US 1,070	Floating
NOVA GAS TRANSMISSION LTD.
	February 2016	Debentures	225	12.20	%


1	These facilities were put in place to finance a portion of the Columbia acquisition and were fully retired in second quarter 2017.

Interest Expense

Interest expense in the three years ended December 31 was as follows:



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Interest on long-term debt	1,877		1,794		1,765
Interest on junior subordinated notes	391		348		180
Interest on short-term debt	73		33		18
Capitalized interest	(124	)	(173	)	(176	)
Amortization and other financial charges¹	48		67		211
	2,265		2,069		1,998

Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to changes in interest rates. In 2016, this amount includes dividend equivalent payments of $109 million on the subscription receipts issued to partially fund the Columbia acquisition. Refer to Note 20, Common shares, for further information.

The Company made interest payments of $2,156 million in 2018 (2017 – $1,987 million; 2016 – $1,721 million) on long-term debt, junior subordinated notes and short-term debt, net of interest capitalized.

JUNIOR SUBORDINATED NOTES

12 Months Ended

Dec. 31, 2018

Junior Subordinated Notes [Abstract]

JUNIOR SUBORDINATED NOTES



		2018				2017
Outstanding loan amount	Maturity Date	Outstanding at December 31		Effective Interest Rate¹		Outstanding at December 31		Effective Interest Rate¹
(millions of Canadian $, unless otherwise noted)	Maturity Date	Outstanding at December 31		Effective Interest Rate¹		Outstanding at December 31		Effective Interest Rate¹

TRANSCANADA PIPELINES LIMITED²
US$1,000 notes issued 2007at 6.35%³	2067	1,364		5.6	%	1,252		5.0	%
US$750 notes issued 2015 at 5.875%^4,5	2075	1,024		6.5	%	939		5.9	%
US$1,200 notes issued 2016 at 6.125%^4,5	2076	1,637		7.2	%	1,502		6.6	%
US$1,500 notes issued 2017 at 5.55%^4,5	2077	2,047		6.2	%	1,878		5.6	%
$1,500 notes issued 2017 at 4.90%^4,5	2077	1,500		5.5	%	1,500		5.1	%
		7,572				7,071
Unamortized debt discount and issue costs		(64	)			(64	)
		7,508				7,007


1	The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for loan fees and discounts.


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


3	In May 2017, Junior subordinated notes of US$1 billion converted from a fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three month LIBOR plus 2.21 per cent.

The Junior subordinated notes were issued to TransCanada 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 since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL.


5	The coupon rate is initially a fixed interest rate for the first ten years and converts to a floating rate thereafter.

In March 2017, TransCanada Trust (the Trust) issued US$1.5 billion of Trust Notes – Series 2017-A 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 then three month LIBOR plus 3.458 per cent per annum; from March 2047 until March 2077, the interest rate will reset to the then three month LIBOR plus 4.208 per cent per annum. The junior subordinated notes are redeemable 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.

In May 2017, the Trust issued $1.5 billion of Trust Notes – Series 2017-B 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 then 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 then three month Bankers' Acceptance rate plus 4.08 per cent per annum. The junior subordinated notes are redeemable 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 August 2016, the Trust issued US$1.2 billion of Trust Notes – Series 2016-A to third party investors at a fixed interest rate of 5.875 per cent for the first ten years, converting to a floating rate thereafter. All of the issuance proceeds of the Trust were loaned to TCPL for US$1.2 billion of junior subordinated notes of TCPL at an initial fixed rate of 6.125 per cent, including a 0.25 per cent administration charge. The rate will reset commencing August 2026 until August 2046 to the then three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the then three month LIBOR plus 5.64 per cent per annum. The junior subordinated notes are redeemable at TCPL's option at any time on or after August 15, 2026 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

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.

NON-CONTROLLING INTERESTS

12 Months Ended

Dec. 31, 2018

Noncontrolling Interest [Abstract]

NON-CONTROLLING INTERESTS

The Company's Non-controlling interests included in the Consolidated balance sheet are as follows:



at December 31	2018	2017
(millions of Canadian $)

Non-controlling interest in TC PipeLines, LP	1,655	1,852

The Company's Net (loss)/income attributable to non-controlling interests included in the Consolidated statement of income are as follows:



year ended December 31	2018		2017	2016
(millions of Canadian $)	2018		2017	2016

Non-controlling interest in TC PipeLines, LP	(185	)	220	215
Non-controlling interest in Portland Natural Gas Transmission System¹	—		9	20
Non-controlling interest in Columbia Pipeline Partners LP²	—		9	17
	(185	)	238	252


1	Non-controlling interest in 2017 for the period January 1 to May 31 when TransCanada sold its remaining interest in Portland to TC PipeLines, LP. Refer to Note 26, Acquisitions and dispositions for further information.


2	Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of Columbia Pipeline Partners LP.

TC PipeLines, LP

During 2018, the non-controlling interest in TC PipeLines, LP increased from 74.3 per cent to 74.5 per cent due to periodic issuances of common units in TC PipeLines, LP to third parties under an at-the-market issuance program. In 2017, the non-controlling interest in TC PipeLines, LP ranged between 73.2 per cent and 74.3 per cent, and in 2016, between 72.0 per cent and 73.2 per cent.

Portland Natural Gas Transmission System

On June 1, 2017, TransCanada sold its remaining 11.81 per cent directly held interest in Portland to TC PipeLines, LP and, as a result, at December 31, 2017 and 2018, non-controlling interest in Portland was nil. On January 1, 2016, TransCanada sold 49.9 per cent of Portland to TC PipeLines, LP. Refer to Note 26, Acquisitions and dispositions for further information.

Columbia Pipeline Partners LP

On July 1, 2016, TransCanada acquired Columbia, which included a 53.5 per cent non-controlling interest in Columbia Pipeline Partners LP (CPPL). On February 17, 2017, TransCanada acquired all outstanding publicly held common units of 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 TransCanada's non-controlling interest in CPPL was recorded as Common units subject to rescission or redemption on the Consolidated balance sheet. The Company classified this non-controlling interest outside of equity as the potential redemption rights of the units were not within the control of the Company.

Common Units of TC PipeLines, LP Subject to Rescission

In connection with a late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the TC PipeLines, LP at-the-market issuance program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to TC PipeLines, LP within one year of purchase.

As a result, at December 31, 2016, $106 million (US$82 million) was recorded as Common units subject to rescission or redemption on the Consolidated balance sheet. The Company classified these 1.6 million common units outside equity because the potential rescission rights of the units were not within the control of the Company. At December 31, 2017, all rescission rights previously classified outside of equity had lapsed and been reclassified to equity. These rights expired one year from the date of purchase of each unit and no unitholder claimed or attempted to exercise any of these rescission rights while they remained outstanding.

COMMON SHARES

12 Months Ended

Dec. 31, 2018

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

COMMON SHARES



	Number of Shares		Amount
	(thousands)		(millions of Canadian $)

Outstanding at January 1, 2016	702,614		12,102
Issued under public offerings¹	156,825		7,752
Dividend reinvestment and share purchase plan	2,942		177
Exercise of options	1,683		74
Repurchase of shares	(305	)	(6	)
Outstanding at December 31, 2016	863,759		20,099
Dividend reinvestment and share purchase plan	12,824		790
At-the-market equity issuance program¹	3,462		216
Exercise of options	1,331		62
Outstanding at December 31, 2017	881,376		21,167
At-the-market equity issuance program¹	20,050		1,118
Dividend reinvestment and share purchase plan	15,937		855
Exercise of options	734		34
Outstanding at December 31, 2018	918,097		23,174


1	Net of issue costs and deferred income taxes.

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares without par value.

Dividend Reinvestment and Share Purchase Plan

Effective July 1, 2016, the Company re-initiated the issuance of common shares from treasury under its Dividend Reinvestment Plan (DRP) and Share Purchase Plan. Under these plans, eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Under the DRP, common shares were issued from treasury at a discount of two per cent.

TransCanada Corporation At-the-Market Equity Issuance Program

In June 2017, the Company established an At-the-Market Equity Issuance Program (ATM program) that allows, from time to time, for the issuance of common shares from treasury at the prevailing market price when sold through the Toronto Stock Exchange (TSX), the New York Stock Exchange (NYSE) or any other existing trading market for TransCanada common shares in Canada or the United States. The ATM program, which is effective for a 25-month period, is utilized as appropriate in order to manage the Company's capital structure over time. Under the original ATM program, the Company could issue up to $1.0 billion in common shares or the U.S. dollar equivalent.

In 2017, 3.5 million common shares were issued under the ATM program at an average price of $63.03 per share for proceeds of $216 million, net of approximately $2 million of related commissions and fees.

In June 2018, the Company replenished the capacity available under its existing ATM program. This allows for the issuance of additional common shares from treasury for an aggregate gross sales price of up to $1.0 billion, for a revised total of $2.0 billion or its U.S. dollar equivalent. The ATM program, as amended, is effective to July 23, 2019.

In 2018, 20 million common shares were issued under the ATM program at an average price of $56.13 per share for proceeds of $1.1 billion, net of approximately $10 million of related commissions and fees.

Common Share Public Offering and Subscription Receipts

To partially fund the Columbia acquisition, in April 2016, the Company issued 96.6 million subscription receipts at a price of $45.75 each for gross proceeds of approximately $4.4 billion. Holders of subscription receipts received one common share in exchange for each subscription receipt on July 1, 2016 upon closing of the acquisition. Holders of record at close of business on April 15, 2016 and June 30, 2016 received a cash payment per subscription receipt that was equal in amount to dividends declared on each common share. For the year ended December 31, 2016, $109 million of dividend equivalent payments on these subscription receipts were recorded as Interest expense.

In November 2016, the Company issued 60.2 million common shares at a price of $58.50 each for gross proceeds of approximately $3.5 billion. Proceeds from this offering were used to repay a portion of the US$6.9 billion acquisition bridge facilities which were used to partially fund the Columbia acquisition.

Common Shares Repurchased

In November 2015, the Company received approval from the TSX for a normal course issuer bid (NCIB) allowing it to repurchase, for cancellation, up to 21 million of its common shares representing three per cent of its then issued and outstanding common shares. Under the NCIB, which expired in November 2016, the Company purchased these common shares through the facilities of the TSX and other designated exchanges and published markets in Canada, or through off-exchange block purchases by way of private agreement.

In January 2016, the Company repurchased 305,407 of its common shares at an average price of $44.90 for a total of $14 million. These shares had a weighted average cost of $6 million with the difference of $8 million between the total price paid and the weighted average cost recorded in Additional paid-in capital.

Basic and Diluted Net Income per Common Share

Net income per common share is calculated by dividing Net income attributable to common shares by the weighted average number of common shares outstanding. The higher weighted average number of shares for the diluted earnings per share calculation is due to options exercisable under TransCanada's Stock Option Plan and shares issuable under the DRP.



Weighted Average Common Shares Outstanding
(millions)	2018	2017	2016

Basic	902	872	759
Diluted	903	874	760

Stock Options



	Number of Options (thousands)		Weighted Average Exercise Prices	Weighted Average Remaining Contractual Life (years)
Options outstanding at January 1, 2018	11,026		$51.38
Options granted	2,250		$56.89
Options exercised	(734	)	$42.65
Options forfeited/expired	(138	)	$57.23
Options Outstanding at December 31, 2018	12,404		$52.83	3.6
Options Exercisable at December 31, 2018	8,189		$50.72	2.6

At December 31, 2018, an additional 9,790,373 common shares were reserved for future issuance from treasury under TransCanada's Stock Option Plan. The contractual life of options granted is seven years. Options may be exercised at a price determined at the time the option is awarded and vest on the anniversary date in each of the three years following the award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation or termination of the option holder's employment.

The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions:



year ended December 31	2018		2017		2016

Weighted average fair value	$5.80		$7.22		$5.67
Expected life (years)¹	5.7		5.7		5.8
Interest rate	2.1	%	1.2	%	0.7	%
Volatility²	16	%	18	%	21	%
Dividend yield	4.2	%	3.6	%	4.9	%
Forfeiture rate³	—		—		5	%


1	Expected life is based on historical exercise activity.


2	Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.


3	On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance.

The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $13 million in 2018 (2017 – $12 million; 2016 – $15 million). At December 31, 2018, unrecognized compensation costs related to non-vested stock options was $16 million. The cost is expected to be fully recognized over a three-year period.

The following table summarizes additional stock option information:



year ended December 31	2018	2017	2016
(millions of Canadian $, unless otherwise noted)	2018	2017	2016

Total intrinsic value of options exercised	10	28	31
Fair value of options that have vested	101	140	126
Total options vested	2.1 million	2.3 million	2.1 million

As at December 31, 2018, the aggregate intrinsic value of the total options exercisable was $8 million and the total intrinsic value of options outstanding was $9 million.

Shareholder Rights Plan

TransCanada's Shareholder Rights Plan is designed to provide the Board of Directors with sufficient time to explore and develop alternatives for maximizing shareholder value in the event of a takeover offer for the Company and to encourage the fair treatment of shareholders in connection with any such offer. Attached to each common share is one right that, under certain circumstances, entitles certain holders to purchase an additional common share of the Company for half the then current market price of one common share.

PREFERRED SHARES

12 Months Ended

Dec. 31, 2018

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

PREFERRED SHARES



at December 31	Number of Shares Outstanding	Current Yield		Annual Dividend Per Share		Redemption Price Per Share		Redemption and Conversion Option Date	Right to Convert Into^1,2	2018	2017	2016
	(thousands)									(millions of Canadian $)³

Cumulative First Preferred Shares
Series 1	9,498	3.266	%		$0.8165		$25.00	December 31, 2019	Series 2	233	233	233
Series 2	12,502	Floating⁴		Floating			$25.00	December 31, 2019	Series 1	306	306	306
Series 3	8,533	2.152	%		$0.538		$25.00	June 30, 2020	Series 4	209	209	209
Series 4	5,467	Floating⁴		Floating			$25.00	June 30, 2020	Series 3	134	134	134
Series 5	12,714	2.263	%		$0.56575		$25.00	January 30, 2021	Series 6	310	310	310
Series 6	1,286	Floating⁴		Floating			$25.00	January 30, 2021	Series 5	32	32	32
Series 7	24,000	4.00	%		$1.00		$25.00	April 30, 2019	Series 8	589	589	589
Series 9	18,000	4.25	%		$1.0625		$25.00	October 30, 2019	Series 10	442	442	442
Series 11	10,000	3.80	%		$0.95		$25.00	November 30, 2020	Series 12	244	244	244
Series 13	20,000	5.50	%		$1.375		$25.00	May 31, 2021	Series 14	493	493	493
Series 15	40,000	4.90	%		$1.225		$25.00	May 31, 2022	Series 16	988	988	988
Carrying value										3,980	3,980	3,980

Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), 2.96 per cent (Series 12), 4.69 per cent (Series 14) and 3.85 per cent (Series 16). These rates reset quarterly with the then current T-Bill rate.

The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then five-year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), 2.96 per cent (Series 11), 4.69 per cent, subject to a minimum of 5.50 per cent (Series 13) and 3.85 per cent, subject to a minimum of 4.90 per cent (Series 15).


3	Net of underwriting commissions and deferred income taxes.

The floating quarterly dividend rate for the Series 2 preferred shares is 3.633 per cent and for the Series 4 preferred shares is 2.993 per cent for the period starting December 31, 2018 to, but excluding, March 29, 2019. The floating quarterly dividend rate for the Series 6 preferred shares is 3.086 per cent for the period starting October 30, 2018 to, but excluding, January 30, 2019. These rates will reset each quarter going forward.

In February 2016, holders of 1,285,739 Series 5 cumulative redeemable first preferred shares exercised their option to convert to Series 6 cumulative redeemable first preferred shares.

In April 2016, the Company completed a public offering of 20 million Series 13 cumulative redeemable minimum rate reset first preferred shares at $25 per share, resulting in gross proceeds of $500 million.

In November 2016, the Company completed a public offering of 40 million Series 15 cumulative redeemable minimum rate reset first preferred shares at $25 per share, resulting in gross proceeds of $1.0 billion.

The holders of preferred shares are entitled to receive a fixed cumulative quarterly preferential dividend as and when declared by the Board with the exception of Series 2, Series 4 and Series 6 preferred shares. The holders of Series 2, Series 4 and Series 6 preferred shares are entitled to receive quarterly floating rate cumulative preferential dividends as and when declared by the Board. The holders will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter.

TransCanada may, at its option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. In addition, Series 2, Series 4 and Series 6 preferred shares are redeemable by TransCanada at any time other than on a designated date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS

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



year ended December 31, 2018	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount

Foreign currency translation gains on net investment in foreign operations	1,323		35		1,358
Change in fair value of net investment hedges	(57	)	15		(42	)
Change in fair value of cash flow hedges	(14	)	4		(10	)
Reclassification to net income of gains and losses on cash flow hedges	27		(6	)	21
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(153	)	39		(114	)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	20		(5	)	15
Other comprehensive income on equity investments	113		(27	)	86
Other Comprehensive Income	1,259		55		1,314



year ended December 31, 2017	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount

Foreign currency translation losses on net investment in foreign operations	(746	)	(3	)	(749	)
Reclassification of foreign currency translation gains on disposal of foreign operations	(77	)	—		(77	)
Change in fair value of cash flow hedges	3		—		3
Reclassification to net income of gains and losses on cash flow hedges	(3	)	1		(2	)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(14	)	3		(11	)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	21		(5	)	16
Other comprehensive loss on equity investments	(141	)	35		(106	)
Other Comprehensive Loss	(957	)	31		(926	)



year ended December 31, 2016	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
Foreign currency translation gains on net investment in foreign operations	3		—		3
Change in fair value of net investment hedges	(14	)	4		(10	)
Change in fair value of cash flow hedges	44		(14	)	30
Reclassification to net income of gains and losses on cash flow hedges	71		(29	)	42
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(38	)	12		(26	)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	22		(6	)	16
Other comprehensive loss on equity investments	(117	)	30		(87	)
Other Comprehensive Loss	(29	)	(3	)	(32	)

The changes in AOCI by component are as follows:



	Currency Translation Adjustments		Cash Flow Hedges		Pension and Other Post-Retirement Benefit Plan Adjustments		Equity Investments		Total¹

AOCI balance at January 1, 2016	(383	)	(97	)	(198	)	(261	)	(939	)
Other comprehensive income/(loss) before reclassifications²	7		27		(26	)	(101	)	(93	)
Amounts reclassified from AOCI	—		42		16		14		72
Net current period other comprehensive income/(loss)	7		69		(10	)	(87	)	(21	)
AOCI balance at December 31, 2016	(376	)	(28	)	(208	)	(348	)	(960	)
Other comprehensive (loss)/income before reclassifications^2,3	(590	)	(1	)	(11	)	(117	)	(719	)
Amounts reclassified from AOCI	(77	)	(2	)	16		11		(52	)
Net current period other comprehensive (loss)/income	(667	)	(3	)	5		(106	)	(771	)
AOCI balance at December 31, 2017	(1,043	)	(31	)	(203	)	(454	)	(1,731	)
Other comprehensive income/(loss) before reclassifications²	1,150		(9	)	(114	)	72		1,099
Amounts reclassified from AOCI^4,5	—		16		15		12		43
Net current period other comprehensive income/(loss)	1,150		7		(99	)	84		1,142
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	—		1		(12	)	(6	)	(17	)
AOCI balance at December 31, 2018	107		(23	)	(314	)	(376	)	(606	)


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


2	In 2018, other comprehensive income before reclassifications on currency translation adjustments and cash flow hedges are net of non-controlling interest gains of $166 million (2017 – $159 million losses; 2016 – $14 million losses) and losses of $1 million (2017 – $4 million gains and 2016 – $3 million gains), respectively.


3	Other comprehensive (loss)/income before reclassification on pension and other post-retirement benefit plan adjustments includes a $27 million reduction on settlements and curtailments.

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 $15 million ($11 million, net of tax) at December 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.


5	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million and $2 million, respectively.

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



	Amounts Reclassified From AOCI¹						Affected Line Item in the Consolidated Statement of Income
year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Cash flow hedges
Commodities	(4	)	20		(57	)	Revenues (Energy)
Interest	(18	)	(17	)	(14	)	Interest expense
	(22	)	3		(71	)	Total before tax
	6		(1	)	29		Income tax expense
	(16	)	2		(42	)	Net of tax^1,3
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial gains and losses	(16	)	(15	)	(22	)	Plant operating costs and other²
Settlement charge	(4	)	(2	)	—		Plant operating costs and other²
	(20	)	(17	)	(22	)	Total before tax
	5		5		6		Income tax expense
	(15	)	(12	)	(16	)	Net of tax¹
Equity investments
Equity income	(16	)	(15	)	(19	)	Income from equity investments
	4		4		5		Income tax expense
	(12	)	(11	)	(14	)	Net of tax^1,3
Currency translation adjustments
Realization of foreign currency translation gains on disposal of foreign operations	—		77		—		Gain/(loss) on assets held for sale/sold
	—		—		—		Income tax expense
	—		77		—		Net of tax¹


1	Amounts in parentheses indicate expenses to the Consolidated statement of income.


2	These AOCI components are included in the computation of net benefit cost. Refer to Note 23, Employee post-retirement benefits for further information.


3	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million (2017 – nil , 2016 – nil) and $2 million (2017 – nil, 2016 – nil), respectively.

EMPLOYEE POST-RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

EMPLOYEE POST-RETIREMENT BENEFITS

The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining service life of employees, which is approximately nine years at December 31, 2018 (2017 and 2016 – nine years).

On December 31, 2017, the Columbia DB Plan merged with TransCanada's U.S. DB Plan. Members accruing benefits in the Columbia DB Plan as of December 31, 2017 were provided an option to either continue receiving benefits in the Columbia DB Plan or instead participate in the existing U.S. DC plan. In addition, on January 1, 2018, the Columbia other post-retirement benefit plan merged with TransCanada's U.S. other post-retirement benefit plan.

The Company also provides its employees with a savings plan in Canada, DC Plans consisting of 401(k) Plans in the U.S., and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Net actuarial gains or losses for the plans are amortized out of AOCI over the expected average remaining service life of employees, which was approximately 12 years at December 31, 2018 (2017 and 2016 – 12 years). In 2018, the Company expensed $59 million (2017 – $42 million; 2016 – $52 million) for the savings and DC Plans.

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 participate in the existing DC plan. Non-union U.S. employees who participated in the DC Plan, had one final election opportunity to become a member of the U.S. DB Plan as of January 1, 2018.

Total cash contributions by the Company for employee post-retirement benefits were as follows:



year ended December 31	2018	2017	2016
(millions of Canadian $)	2018	2017	2016

DB Plans	103	163	111
Other post-retirement benefit plans	23	7	8
Savings and DC Plans	59	42	52
	185	212	171

Current Canadian pension legislation allows for partial funding of solvency requirements over a number of years through letters of credit in lieu of cash contributions, up to certain limits. As such, in addition to the cash contributions noted above, the Company provided a $17 million letter of credit to the Canadian DB Plan in 2018 (2017 – $27 million; 2016 – $20 million), resulting in a total of $277 million provided to the Canadian DB Plan under letters of credit at December 31, 2018.

The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2018 and the next required valuation will be as at January 1, 2019.

In December 2018, the Company recorded a settlement resulting from lump sum payments made in 2018 to certain terminated non-union vested participants in the Company's U.S. DB Plan related to voluntary cash settlement options available to these participants. The impact of the settlement was determined using assumptions consistent with those employed at December 31, 2017. The settlement reduced the Company's U.S. DB Plan's unrealized actuarial losses by $4 million which was included in OCI and resulted in a settlement charge of $4 million which was recorded in net benefit costs in 2018. Effective December 1, 2018, the plan was amended to include this unlimited lump sum payment option for certain union employees who were not previously eligible.

In 2017, as a result of settlements and curtailments that occurred upon the completion of the U.S. Northeast power generation asset sales, interim remeasurements were performed on TransCanada’s U.S. DB Plan and other post-retirement benefit plans using a weighted average discount rate of 4.10 per cent. All other assumptions were consistent with those employed at December 31, 2016. The impact of these remeasurements reduced the U.S. DB Plan's unrealized actuarial losses by $3 million, which was included in OCI, and resulted in a settlement charge of $2 million which was recorded in net benefit cost in 2017. These remeasurements had no impact on the other post-retirement benefit plan's unrealized actuarial losses.

Also in 2017, lump sum payouts exceeded service and interest costs for the Columbia DB Plan. As a result, an interim remeasurement was performed on the Columbia DB Plan at September 30, 2017 using a discount rate of 3.70 per cent. The interim remeasurement of the Columbia DB Plan increased the Company’s unrealized actuarial gains by $16 million, of which $14 million was recorded in Regulatory assets and $2 million was recorded in OCI. All other assumptions were consistent with those employed at December 31, 2016.

The Company's funded status at December 31 is comprised of the following:



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2018		2017		2018		2017

Change in Benefit Obligation¹
Benefit obligation – beginning of year	3,646		3,456		375		372
Service cost	121		113		4		4
Interest cost	134		135		14		14
Employee contributions	5		5		—		3
Benefits paid	(177	)	(166	)	(23	)	(19	)
Actuarial (gain)/loss	(92	)	253		43		19
Curtailment	—		(14	)	—		(2	)
Settlement	(71	)	(66	)	—		—
Foreign exchange rate changes	87		(70	)	17		(16	)
Benefit obligation – end of year	3,653		3,646		430		375
Change in Plan Assets
Plan assets at fair value – beginning of year	3,451		3,208		365		354
Actual return on plan assets	(73	)	358		(15	)	45
Employer contributions²	103		163		23		7
Employee contributions	5		5		—		3
Benefits paid	(176	)	(166	)	(27	)	(19	)
Settlement	(71	)	(57	)	—		—
Foreign exchange rate changes	82		(60	)	30		(25	)
Plan assets at fair value – end of year	3,321		3,451		376		365
Funded Status – Plan Deficit	(332	)	(195	)	(54	)	(10	)


1	The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation.


2	Excludes a $17 million letter of credit provided to the Canadian DB Plan for funding purposes (2017 – $27 million).

The amounts recognized in the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans are as follows:



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2018		2017		2018		2017

Intangible and other assets (Note 12)	—		—		192		193
Accounts payable and other	(1	)	(1	)	(8	)	(8	)
Other long-term liabilities (Note 15)	(331	)	(194	)	(238	)	(195	)
	(332	)	(195	)	(54	)	(10	)

Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded:



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2018		2017		2018		2017

Projected benefit obligation¹	(3,653	)	(3,646	)	(246	)	(203	)
Plan assets at fair value	3,321		3,451		—		—
Funded Status – Plan Deficit	(332	)	(195	)	(246	)	(203	)


1	The projected benefit obligation for the pension benefit plans differ from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels.

The funded status based on the accumulated benefit obligation for all DB Plans is as follows:



at December 31	2018		2017
(millions of Canadian $)	2018		2017

Accumulated benefit obligation	(3,347	)	(3,372	)
Plan assets at fair value	3,321		3,451
Funded Status	(26	)	79

Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded.



at December 31	2018		2017
(millions of Canadian $)	2018		2017

Accumulated benefit obligation	(3,347	)	(944	)
Plan assets at fair value	3,321		925
Funded Status – Plan Deficit	(26	)	(19	)

The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:



	Percentage of Plan Assets				Target Allocations
at December 31	2018		2017		2018

Debt securities	33	%	30	%	25% to 45%
Equity securities	56	%	64	%	40% to 70%
Alternatives	11	%	6	%	5% to 15%
	100	%	100	%

Debt and equity securities include the Company's debt and common shares as follows:



at December 31			Percentage of Plan Assets
(millions of Canadian $)	2018	2017	2018		2017

Debt securities	8	7	0.3	%	0.2	%
Equity securities	7	3	0.2	%	0.1	%

Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities, as well as alternative assets such as infrastructure, private equity, real estate and derivatives to diversify risk. Derivatives are not used for speculative purposes and the use of leveraged derivatives is prohibited.

All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted basis and by comparison to similar assets which are publicly traded. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets that the Company has the ability to access at the measurement date. In Level II, the fair value of assets is determined using valuation techniques, such as option pricing models and extrapolation using significant inputs which are observable directly or indirectly. In Level III, the fair value of assets is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement.

The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. For further information on the fair value hierarchy, refer to Note 24, Risk management and financial instruments.



at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $)	2018	2017	2018	2017	2018	2017	2018	2017	2018	2017

Asset Category
Cash and Cash Equivalents	48	44	—	17	—	—	48	61	1	2
Equity Securities:
Canadian	355	410	138	151	—	—	493	561	13	15
U.S.	460	543	116	354	—	—	576	897	16	24
International	40	45	281	322	—	—	321	367	9	10
Global	116	—	268	301	—	—	384	301	10	8
Emerging	8	8	138	147	—	—	146	155	4	4
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	186	193	—	—	186	193	5	5
Provincial	—	—	198	194	—	—	198	194	5	5
Municipal	—	—	8	8	—	—	8	8	1	—
Corporate	—	—	112	122	—	—	112	122	3	3
U.S. Bonds:
Federal	350	—	—	244	—	—	350	244	9	6
State	—	—	—	41	—	—	—	41	—	1
Municipal	—	—	—	4	—	—	—	4	—	—
Corporate	145	—	51	234	—	—	196	234	5	6
International:
Government	6	—	4	4	—	—	10	4	1	—
Corporate	19	—	18	5	—	—	37	5	1	—
Mortgage backed	128	—	—	73	—	—	128	73	3	2
Other Investments:
Real estate	—	—	—	—	196	140	196	140	5	4
Infrastructure	—	—	—	—	163	70	163	70	4	2
Private equity funds	—	—	—	—	3	6	3	6	1	—
Funds held on deposit	142	136	—	—	—	—	142	136	4	3
	1,817	1,186	1,518	2,414	362	216	3,697	3,816	100	100

The following table presents the net change in the Level III fair value category:



(millions of Canadian $, pre-tax)

Balance at December 31, 2016	199
Purchases and sales	11
Realized and unrealized gains	6
Balance at December 31, 2017	216
Purchases and sales	127
Realized and unrealized gains	19
Balance at December 31, 2018	362

The Company's expected funding contributions in 2019 are approximately $113 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $61 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $17 million letter of credit to the Canadian DB Plan for the funding of solvency requirements.

The following are estimated future benefit payments, which reflect expected future service:



(millions of Canadian $)	Pension Benefits	Other Post- Retirement Benefits

2019	190	24
2020	193	23
2021	198	23
2022	203	23
2023	207	23
2024 to 2028	1,081	114

The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of corporate AA bond yields at December 31, 2018. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:



	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31	2018		2017		2018		2017

Discount rate	3.90	%	3.60	%	4.10	%	3.70	%
Rate of compensation increase	3.00	%	3.00	%	—		—

The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:



	Pension Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2018		2017		2016		2018		2017		2016

Discount rate	3.60	%	3.95	%	4.20	%	3.70	%	4.15	%	4.30	%
Expected long-term rate of return on plan assets	6.70	%	6.50	%	6.70	%	4.00	%	6.05	%	5.95	%
Rate of compensation increase	3.00	%	1.20	%	0.80	%	—		—		—

The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan.

A six per cent weighted average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019 measurement purposes. The rate was assumed to decrease gradually to 4.50% by 2028 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects:



(millions of Canadian $)	Increase	Decrease

Effect on total of service and interest cost components	1	(1	)
Effect on post-retirement benefit obligation	25	(21	)

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



at December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
(millions of Canadian $)	2018		2017		2016		2018		2017		2016

Service cost¹	121		108		107		4		4		3
Other components of net benefit cost¹
Interest cost	134		122		127		14		14		13
Expected return on plan assets	(221	)	(178	)	(175	)	(16	)	(21	)	(11	)
Amortization of actuarial loss	15		14		20		1		1		2
Amortization of regulatory asset	18		37		27		—		1		1
Amortization of transitional obligation related to regulated business	—		—		—		—		—		2
Settlement charge – regulatory asset	—		2		—		—		—		—
Settlement charge – AOCI	4		2		—		—		—		—
	(50	)	(1	)	(1	)	(1	)	(5	)	7
Net Benefit Cost Recognized	71		107		106		3		(1	)	10


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

Pre-tax amounts recognized in AOCI were as follows:



	2018		2017		2016
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)
Net loss	364	53	273	11	270	21

The estimated net loss for the DB Plans and for the other post-retirement benefit plans that will be amortized from AOCI into net periodic benefit cost in 2019 is $12 million and $2 million, respectively.

Pre-tax amounts recognized in OCI were as follows:



	2018				2017				2016
at December 31	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits
(millions of Canadian $)	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits

Amortization of net loss from AOCI to net income	(15	)	(1	)	(18	)	(1	)	(20	)	(2	)
Curtailment	—		—		(14	)	(2	)	—		—
Settlement	(4	)	—		(11	)	—		—		—
Funded status adjustment	110		43		46		(7	)	43		(5	)
	91		42		3		(10	)	23		(7	)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2018

Risk Management and Financial Instruments [Abstract]

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, cash flow and shareholder value.

Risk management strategies, policies and limits are designed to ensure TransCanada's risks and related exposures are in line with the Company's business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits established by the Company's Board of Directors, implemented by senior management and monitored by the Company's risk management and internal audit groups. The Board of Directors' Audit Committee oversees how management monitors compliance with market risk and counterparty credit risk management policies and procedures, and oversees management's review of the adequacy of the risk management framework.

Market Risk

The Company constructs and invests in energy infrastructure projects, purchases and sells commodities, issues short-term and long-term debt, including amounts in foreign currencies, and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings and the value of the financial instruments it holds. The Company assesses contracts used to manage market risk to determine whether all, or a portion, meets the definition of a derivative.

Derivative contracts the Company uses to assist in managing the exposure to market risk may consist of the following:


•	Forwards and futures contracts – agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future


•	Swaps – agreements between two parties to exchange streams of payments over time according to specified terms


•	Options – agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period.

Commodity price risk

The following strategies may be used to manage exposure to commodity price risk in the Company's non-regulated businesses:


•	In the Company's power generation business, TransCanada manages the exposure to fluctuating commodity prices through long-term contracts and hedging activities including selling and purchasing power and natural gas in forward markets


•	In the Company's non-regulated natural gas storage business, TransCanada's exposure to seasonal natural gas price spreads is managed with a portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in forward markets to lock in future positive margins


•	In the Company's liquids marketing business, TransCanada enters into pipeline and storage terminal capacity contracts. TransCanada fixes a portion of its exposure on these contracts by entering into derivative instruments to manage its variable price fluctuations that arise from physical liquids transactions.

The Company's exposure to electricity price risk has been greatly reduced following the sales of its U.S. Northeast power generation assets in 2017 and its U.S. Northeast power retail contracts on March 1, 2018 as well as the continued wind-down of its remaining U.S. Power marketing contracts.

Interest rate risk

TransCanada utilizes short-term and long-term debt to finance its operations which exposes the Company to interest rate risk. TransCanada typically pays fixed rates of interest on its long-term debt and floating rates on its commercial paper programs and amounts drawn on its credit facilities. A small portion of TransCanada's long-term debt is at floating interest rates. In addition, the Company is exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. The Company manages its interest rate risk using a combination of interest rate swaps and option derivatives.

Foreign exchange risk

TransCanada generates revenues and incurs expenses that are denominated in currencies other than Canadian dollars. As a result, the Company's earnings and cash flows are exposed to currency fluctuations.

A portion of TransCanada's businesses generate earnings in U.S. dollars, but since its financial results are reported in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect its net income. As the Company's U.S. dollar-denominated operations continue to grow, this exposure increases. A portion of this risk is offset by interest expense on U.S. dollar-denominated debt. The balance of the exposure is hedged on a rolling one-year basis using foreign exchange derivatives, but the exposure remains beyond that period.

Net investment hedges

The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency swaps and foreign exchange options.

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



	2018			2017
at December 31	Fair Value^1,2		Notional Amount	Fair Value^1,2		Notional Amount
(millions of Canadian $, unless otherwise noted)	Fair Value^1,2		Notional Amount	Fair Value^1,2		Notional Amount

U.S. dollar cross-currency interest rate swaps (maturing 2019)³	(43	)	US 300	(199	)	US 1,200
U.S. dollar foreign exchange options (maturing 2019 to 2020)	(47	)	US 2,500	5		US 500
	(90	)	US 2,800	(194	)	US 1,700


1	Fair value equals carrying value.


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


3	In 2018, Net income includes net realized gains of $2 million (2017 – gains of $4 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense.

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



at December 31	2018	2017
(millions of Canadian $, unless otherwise noted)	2018	2017

Notional amount	31,000 (US 22,700)	25,400 (US 20,200)
Fair value	31,700 (US 23,200)	28,900 (US 23,100)

Counterparty Credit Risk

TransCanada's maximum counterparty credit exposure with respect to financial instruments at December 31, 2018, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available-for-sale assets, derivative assets and a loan receivable.

Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the related contract or agreement with the Company.

The Company manages its exposure to this potential loss by dealing with creditworthy counterparties, obtaining financial assurances such as guarantees, letters of credit or cash where considered necessary, and setting limits on the amount TransCanada can transact with any one counterparty. There is no guarantee that these techniques will protect the Company from material losses.

The Company monitors its counterparties and regularly reviews its accounts receivable. The Company records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2018 and 2017, there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the year.

TransCanada has significant credit and performance exposures to financial institutions as they hold cash deposits and provide committed credit lines and letters of credit that help manage the Company's exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.

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 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 financial instruments.

Balance Sheet Presentation of Non-Derivative Financial Instruments

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



	2018				2017
at December 31	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions of Canadian $)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term debt, including current portion^1,2 (Note 17)	(39,971	)	(42,284	)	(34,741	)	(40,180	)
Junior subordinated notes (Note 18)	(7,508	)	(6,665	)	(7,007	)	(7,233	)
	(47,479	)	(48,949	)	(41,748	)	(47,413	)


1	Long-term debt is recorded at amortized cost, except for US$750 million (2017 – US$1.1 billion) that is attributed to hedged risk and recorded at fair value.

Net income in 2018 included unrealized losses of $2 million (2017 – gains of $4 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$750 million of long-term debt at December 31, 2018 (2017 – US$1.1 billion). 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:



	2018		2017
at December 31	LMCI Restricted Investments	Other Restricted Investments¹	LMCI Restricted Investments	Other Restricted Investments¹
(millions of Canadian $)	LMCI Restricted Investments	Other Restricted Investments¹	LMCI Restricted Investments	Other Restricted Investments¹

Fair value of fixed income securities²
Fixed income securities (maturing within 1 year)	—	22	—	23
Fixed income securities (maturing within 1-5 years)	—	110	—	107
Fixed income securities (maturing within 5-10 years)	140	—	14	—
Fixed income securities (maturing after 10 years)	952	—	790	—
	1,092	132	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 Company's Consolidated balance sheet.



	2018			2017			2016
year ended December 31 (millions of Canadian $)	LMCI restricted investments¹		Other restricted investments	LMCI restricted investments¹		Other restricted investments	LMCI restricted investments¹		Other restricted investments

Net unrealized gains/(losses)	11		—	(3	)	1	(28	)	(1	)
Net realized losses²	(4	)	—	(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	The realized gains and losses on the sale of LMCI restricted investment securities are determined using the average cost basis.

Fair Value of Derivative Instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using a market approach. The market approach bases the fair value measures on a comparable transaction using quoted market prices, or in the absence of quoted market prices, third-party broker quotes or other valuation techniques. 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. Unrealized gains and losses on derivative instruments are not necessarily representative of the amounts that will be realized on settlement.

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.

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

Balance Sheet Presentation of Derivative Instruments

The balance sheet classification of the fair value of derivative instruments as at December 31, 2018 is as follows:



at December 31, 2018	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments¹
(millions of Canadian $)	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments¹

Other current assets (Note 7)
Commodities²	1		—		—		716		717
Foreign exchange	—		—		16		1		17
Interest rate	3		—		—		—		3
	4		—		16		717		737
Intangible and other assets (Note 12)
Commodities²	1		—		—		50		51
Foreign exchange	—		—		1		—		1
Interest rate	8		1		—		—		9
	9		1		1		50		61
Total Derivative Assets	13		1		17		767		798

Accounts payable and other (Note 14)
Commodities²	(4	)	—		—		(622	)	(626	)
Foreign exchange	—		—		(105	)	(188	)	(293	)
Interest rate	—		(3	)	—		—		(3	)
	(4	)	(3	)	(105	)	(810	)	(922	)
Other long-term liabilities (Note 15)
Commodities²	—		—		—		(28	)	(28	)
Foreign exchange	—		—		(2	)	—		(2	)
Interest rate	(11	)	(1	)	—		—		(12	)
	(11	)	(1	)	(2	)	(28	)	(42	)
Total Derivative Liabilities	(15	)	(4	)	(107	)	(838	)	(964	)
Total Derivatives	(2	)	(3	)	(90	)	(71	)	(166	)


1	Fair value equals carrying value.


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

The balance sheet classification of the fair value of derivative instruments as at December 31, 2017 is as follows:



at December 31, 2017	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments¹
(millions of Canadian $)	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments¹

Other current assets (Note 7)
Commodities²	1		—		—		249		250
Foreign exchange	—		—		8		70		78
Interest rate	3		—		—		1		4
	4		—		8		320		332
Intangible and other assets (Note 12)
Commodities²	—		—		—		69		69
Interest rate	4		—		—		—		4
	4		—		—		69		73
Total Derivative Assets	8		—		8		389		405

Accounts payable and other (Note 14)
Commodities²	(6	)	—		—		(208	)	(214	)
Foreign exchange	—		—		(159	)	(10	)	(169	)
Interest rate	—		(4	)	—		—		(4	)
	(6	)	(4	)	(159	)	(218	)	(387	)
Other long-term liabilities (Note 15)
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.

Derivatives in fair value hedging relationships

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



at December 31	Carrying amount				Fair value hedging adjustments¹
(millions of Canadian $)	2018		2017		2018	2017

Current portion of long-term debt	(748	)	(688	)	3	1
Long-term debt	(273	)	(685	)	—	4
	(1,021	)	(1,373	)	3	5


1	At December 31, 2018 and 2017, adjustments for discontinued hedging relationships included in these balances were nil.

Notional and Maturity Summary

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



at December 31, 2018	Power	Natural Gas	Liquids	Foreign Exchange	Interest Rate

Purchases¹	23,865	44	59	—	—
Sales¹	17,689	56	79	—	—
Millions of U.S. dollars	—	—	—	3,862	1,650
Maturity dates	2019-2023	2019-2027	2019	2019	2019-2030


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 Rate

Purchases¹	66,132	133	6	—	—
Sales¹	42,836	135	7	—	—
Millions of U.S. dollars	—	—	—	2,931	2,300
Millions of Mexican pesos	—	—	—	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.

Unrealized and Realized Gains/(Losses) on Derivative Instruments

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



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Derivative instruments held for trading¹
Amount of unrealized gains/(losses) in the year
Commodities²	28		62		123
Foreign exchange	(248	)	88		25
Interest rate	—		(1	)	—
Amount of realized gains/(losses) in the year
Commodities	351		(107	)	(204	)
Foreign exchange	(24	)	18		62
Interest rate	—		1		—
Derivative instruments in hedging relationships
Amount of realized (losses)/gains in the year
Commodities	(1	)	23		(167	)
Foreign exchange	—		5		(101	)
Interest rate	(1	)	1		4


1	Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively.


2	In 2018 and 2017, 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 (2016 – net loss of $42 million).

Derivatives in cash flow hedging relationships

The components of OCI (Note 22) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows:



year ended December 31	2018		2017		2016
(millions of Canadian $, pre-tax)	2018		2017		2016

Change in fair value of derivative instruments recognized in OCI¹
Commodities	(1	)	(1	)	39
Interest rate	(13	)	4		5
	(14	)	3		44


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

Effect of fair value and cash flow hedging relationships

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



year ended December 31	Revenues (Energy)				Interest Expense
(millions of Canadian $)	2018	2017		2016	2018		2017		2016

Total Amount Presented in the Consolidated Statement of Income	2,124	3,593		4,206	(2,265	)	(2,069	)	(1,998	)
Fair Value Hedges
Interest rate contracts
Hedged items	—	—		—	(71	)	(74	)	(74	)
Derivatives designated as hedging instruments	—	—		—	(4	)	1		8
Cash Flow Hedges
Reclassification of gains/(losses) on derivative instruments from AOCI to net income^1,2
Interest rate contracts	—	—		—	22		17		14
Commodity contracts	5	(20	)	57	—		—		—


1	Refer to Note 22, 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 Consolidated 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 as at December 31, 2018:



at December 31, 2018	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts

Derivative – Asset
Commodities	768		(626	)	142
Foreign exchange	18		(18	)	—
Interest rate	12		(4	)	8
	798		(648	)	150
Derivative – Liability
Commodities	(654	)	626		(28	)
Foreign exchange	(295	)	18		(277	)
Interest rate	(15	)	4		(11	)
	(964	)	648		(316	)


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

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, 2017:



at December 31, 2017	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts

Derivative – Asset
Commodities	319		(198	)	121
Foreign exchange	78		(56	)	22
Interest rate	8		(1	)	7
	405		(255	)	150
Derivative – Liability
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, the Company provided cash collateral of $143 million and letters of credit of $22 million (2017 – $165 million and $30 million) to its counterparties. At December 31, 2018, the Company held nil in cash collateral and $1 million in letters of credit (2017 – nil and $3 million) from counterparties on asset exposures.

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. The company may also need to provide collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits.

Based on contracts in place and market prices at December 31, 2018, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $6 million (2017 – $2 million), for which the Company has provided no collateral in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on December 31, 2018, the Company would have been required to provide collateral of $6 million (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 bank lines to meet these contingent obligations should they arise.

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 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 becomes 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 2018, are categorized as follows:



at December 31, 2018	Quoted Prices in Active Markets (Level I)¹		Significant Other Observable Inputs (Level II)¹		Significant Unobservable Inputs (Level III)¹		Total
(millions of Canadian $)	Quoted Prices in Active Markets (Level I)¹		Significant Other Observable Inputs (Level II)¹		Significant Unobservable Inputs (Level III)¹		Total

Derivative Instrument Assets:
Commodities	581		187		—		768
Foreign exchange	—		18		—		18
Interest rate	—		12		—		12
Derivative Instrument Liabilities:
Commodities	(555	)	(95	)	(4	)	(654	)
Foreign exchange	—		(295	)	—		(295	)
Interest rate	—		(15	)	—		(15	)
	26		(188	)	(4	)	(166	)


1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2018.

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 December 31, 2017	Quoted Prices in Active Markets (Level I)¹		Significant Other Observable Inputs (Level II)¹		Significant Unobservable Inputs (Level III)¹		Total
(millions of Canadian $)	Quoted Prices in Active Markets (Level I)¹		Significant Other Observable Inputs (Level II)¹		Significant Unobservable Inputs (Level III)¹		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 in Level III of the fair value hierarchy:



(millions of Canadian $, pre-tax)	2018		2017

Balance at beginning of year	(7	)	16
Transfers out of Level III	5		(19	)
Total gains/(losses) included in Net income	8		(17	)
Settlements	(9	)	18
Sales	—		(5	)
Foreign exchange	(1	)	—
Balance at end of year¹	(4	)	(7	)


1	Revenues include unrealized losses of $5 million attributed to derivatives in the Level III category that were still held at December 31, 2018 (2017 – unrealized losses of $7 million).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2018.

CHANGES IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2018

CHANGES IN OPERATING WORKING CAPITAL

CHANGES IN OPERATING WORKING CAPITAL



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Increase in Accounts receivable	(69	)	(576	)	(482	)
Increase in Inventories	(49	)	(38	)	(87	)
Decrease/(increase) in Assets held for sale	—		14		(13	)
Decrease in Other current assets	45		189		328
(Decrease)/increase in Accounts payable and other	(70	)	151		424
Increase in Accrued interest	41		12		62
(Decrease)/increase in Liabilities related to assets held for sale	—		(25	)	16
(Increase)/decrease in Operating Working Capital	(102	)	(273	)	248

ACQUISITIONS AND DISPOSITIONS

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

ACQUISITIONS AND DISPOSITIONS

U.S. Natural Gas Pipelines

Iroquois Gas Transmission System and Portland Natural Gas Transmission System

On June 1, 2017, TransCanada closed the sale of 49.34 per cent of its 50 per cent interest in Iroquois, along with an option to sell the remaining 0.66 per cent at a later date, to TC PipeLines, LP. At the same time, TransCanada closed the sale of its remaining 11.81 per cent interest in Portland to TC PipeLines, LP. Proceeds from these transactions were US$765 million, before post-closing adjustments, and were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and Portland debt.

In January 2016, TransCanada closed the sale of a 49.9 per cent interest in Portland to TC PipeLines, LP for an aggregate purchase price of US$223 million. Proceeds were comprised of US$188 million in cash and the assumption of US$35 million of a proportional share of Portland debt.

In March 2016, TransCanada acquired a 4.87 per cent interest in Iroquois for an aggregate purchase price of US$54 million, increasing TransCanada’s interest in Iroquois to 49.35 per cent. On May 1, 2016, the Company acquired an additional

0.65 per cent interest for an aggregate purchase price of US$7 million, further increasing TransCanada’s interest in Iroquois to

50 per cent.

Acquisition of Columbia

On July 1, 2016, TransCanada acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash, based on US$25.50 per share for all of Columbia's outstanding common shares as well as all outstanding restricted and performance stock units. The acquisition was financed through proceeds of approximately $4.4 billion from the sale of subscription receipts, draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and, upon closing of the acquisition, were exchanged into approximately 96.6 million common shares of TransCanada. Refer to Note 20, Common shares for further information on the subscription receipts.

At the date of acquisition, Columbia operated a portfolio of approximately 24,500 km (15,200 miles) of regulated natural gas pipelines, 285 Bcf of natural gas storage facilities and midstream and other assets in various regions in the U.S. TransCanada acquired Columbia to expand the Company’s natural gas business in the U.S. market, positioning the Company for additional long-term growth opportunities.

The goodwill arising from the acquisition principally reflects the opportunities to expand the Company’s U.S. Natural Gas Pipelines segment and to gain a stronger competitive position in the North American natural gas business. The goodwill resulting from the acquisition is not deductible for income tax purposes. The acquisition was accounted for as a business combination using the acquisition method where the acquired tangible and intangible assets and assumed liabilities were recorded at their estimated fair values at the date of acquisition. The purchase price equation reflects management’s estimate of the fair value of Columbia’s assets and liabilities as at July 1, 2016.



	July 1, 2016
(millions of $)	U.S.		Canadian¹

Purchase Price Consideration	10,294		13,392
Fair Value
Current assets	658		856
Plant, property and equipment	7,560		9,835
Equity investments	441		574
Regulatory assets	190		248
Intangible and other assets	135		175
Current liabilities	(597	)	(777	)
Regulatory liabilities	(294	)	(383	)
Other long-term liabilities	(144	)	(187	)
Deferred income tax liabilities	(1,613	)	(2,098	)
Long-term debt	(2,981	)	(3,878	)
Non-controlling interests	(808	)	(1,051	)
Fair Value of Net Assets Acquired	2,547		3,314
Goodwill	7,747		10,078


1	At July 1, 2016 exchange rate of $1.30.

The fair values of current assets including cash and cash equivalents, accounts receivable, and inventories and the fair values of current liabilities including notes payable and accrued interest approximated their carrying values due to the short-term nature of these items. Certain acquisition-related working capital items resulted in an adjustment to accounts payable.

Columbia’s natural gas pipelines are subject to FERC regulations and, as a result, their rate bases are expected to be recovered with a reasonable rate of return over the life of the assets. These assets, as well as related regulatory assets and liabilities, had fair values equal to their carrying values on acquisition. The fair value of mineral rights included in Columbia's plant, property and equipment was determined using a discounted cash flow approach which resulted in a fair value increase of $241 million (US$185 million). On acquisition date, the fair value of base gas included in Columbia’s plant, property and equipment was determined by using a quoted market price multiplied by the estimated volume of base gas in place which resulted in a fair value increase of $840 million (US$646 million).

In second quarter 2017, the Company completed its procedures over measuring the volume of base gas acquired and, as a result, decreased its fair value 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 income tax liabilities by $45 million (US$35 million) and increasing goodwill by $71 million (US$55 million) to a total of US$7,802 million (2016 – US$7,747 million) at December 31, 2017. This adjustment did not impact the Company's net income.

The fair value of Columbia’s long-term debt was estimated using an income approach based on observable market rates for similar debt instruments from external data service providers. This resulted in a fair value increase of $300 million (US$231 million).

The following table summarizes the acquisition date fair value of Columbia's debt acquired by TransCanada.



(millions of $)	Maturity Date	Type	Fair Value	Interest Rate

COLUMBIA PIPELINE GROUP, INC.
	June 2018	Senior Unsecured Notes (US$500)	US$506	2.45	%
	June 2020	Senior Unsecured Notes (US$750)	US$779	3.30	%
	June 2025	Senior Unsecured Notes (US$1,000)	US$1,092	4.50	%
	June 2045	Senior Unsecured Notes (US$500)	US$604	5.80	%
			US$2,981

The fair values of Columbia's DB plan and other post-retirement benefit plans were based on an actuarial valuation of the funded status of the plans as of the acquisition date which resulted in an increase of $15 million (US$12 million) and $5 million (US$4 million) to Regulatory assets and Other long-term liabilities, respectively, and a decrease of $14 million (US$11 million) and $2 million (US$2 million) to Intangible and other assets and Regulatory liabilities, respectively.

Temporary differences created as a result of the fair value changes described above resulted in deferred income tax assets and liabilities that were recorded at the Company's then U.S. effective tax rate of 39 per cent.

The fair value of Columbia’s non-controlling interests was based on the approximately 53.8 million CPPL common units outstanding to the public as of June 30, 2016, and valued at the June 30, 2016 closing price of US$15.00 per common unit. On February 17, 2017, TransCanada acquired all outstanding publicly held common units of CPPL. Refer to Note 19, Non-controlling interests, for further information.

In 2016, acquisition expenses of approximately $36 million were included in Plant operating costs and other in the Consolidated statement of income.

Upon completion of the acquisition, the Company began consolidating Columbia. Columbia’s significant accounting policies were consistent with TransCanada’s and continued to be applied. Columbia contributed $929 million to the Company's Revenues and $132 million to the Company's net income from July 1, 2016 to December 31, 2016.

The following supplemental pro forma consolidated financial information of the Company for the years ended December 31, 2016 and 2015 includes the results of operations for Columbia as if the acquisition had been completed on January 1, 2015.



year ended December 31
(millions of Canadian $)	2016	2015

Revenues	13,404	13,007
Net Income/(Loss)	627	(820	)
Net Income/(Loss) Attributable to Common Shares	234	(971	)

Energy

Cartier Wind

On October 24, 2018, the Company completed the sale of its 62 per cent interest in the Cartier Wind power facilities to Innergex Renewable Energy Inc for proceeds of $630 million, before post-closing adjustments. As a result, the Company recorded a gain on sale of $170 million ($143 million after tax) which is included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income.

Ontario Solar Assets

On December 19, 2017, the Company completed the sale of its Ontario solar assets to a third party for proceeds of $541 million, before post-closing adjustments. As a result, the Company recorded a gain on sale of $127 million ($136 million after tax) which is included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income.

U.S. Northeast Power Assets

In 2018, upon finalizing its 2017 annual tax return for its U.S. operations, the Company recorded a $27 million income tax recovery related to the sale of its U.S. Northeast power generation assets.

On April 19, 2017, the Company completed the sale of TC Hydro for proceeds of approximately US$1.07 billion, before post-closing adjustments. As a result, in 2017 the Company recorded a gain on sale of $715 million ($440 million after tax) including the impact of $5 million of foreign currency translation gains which were reclassified from AOCI to net income.

On June 2, 2017, TransCanada completed the sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power for proceeds of approximately US$2.029 billion, before post-closing adjustments. In 2016, the Company recorded a loss of $829 million ($863 million after tax) which included the impact of $70 million of foreign currency translation gains that were reclassified from AOCI to net income on close. The Company recorded an additional loss on sale of $211 million ($167 million after tax) in 2017 which included $2 million in foreign currency translation gains. This additional loss primarily related to adjustments to the purchase price and repair costs for an unplanned outage at Ravenswood prior to close of the sale.

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

Ironwood

In February 2016, TransCanada acquired the Ironwood natural gas fired, combined cycle power plant for US$653 million in cash after post-closing adjustments. The evaluation of assigned fair value of acquired assets and liabilities did not result in the recognition of goodwill. The Company began consolidating Ironwood as of the date of acquisition which did not have a material impact on the Revenues and Net income of the Company. In addition, the pro forma incremental impact of Ironwood on the Company’s Revenues and Net income from the date of acquisition to the date of sale was not material.

COMMITMENTS, CONTINGENCIES AND GUARANTEES

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

Operating leases

Future annual payments under the Company's operating leases for various premises, services and equipment, net of sublease receipts, are approximately as follows:



year ended December 31	Minimum Lease Payments	Amounts Recoverable under Subleases	Net Payments
(millions of Canadian $)	Minimum Lease Payments	Amounts Recoverable under Subleases	Net Payments

2019	81	7	74
2020	78	7	71
2021	76	4	72
2022	69	3	66
2023	67	3	64
2024 and thereafter	390	8	382
	761	32	729

The operating lease agreements for premises, services and equipment expire at various dates through 2052, with an option to renew certain lease agreements for periods of one year to 25 years. Net rental expense on operating leases in 2018 was $84 million (2017 – $93 million; 2016 – $145 million).

Other commitments

TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business.

Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts. At December 31, 2018, TransCanada had the following capital expenditure commitments:


•	approximately $4.6 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with the construction of the Coastal GasLink and NGTL System pipeline projects


•	approximately $0.1 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with Columbia Gas and Columbia Gulf growth projects


•	approximately $0.3 billion for its Mexico natural gas pipelines, primarily related to construction of the Sur de Texas, Villa de Reyes and Tula pipeline projects


•	approximately $0.4 billion for its Liquids pipelines, primarily related to the development of Keystone XL and construction of White Spruce


•	approximately $0.7 billion for its Energy business, primarily related to its proportionate share of commitments for Bruce Power's life extension program


•	approximately $0.1 billion for its Corporate segment related to various information technology services agreements.

Contingencies

TransCanada is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2018, the Company had accrued approximately $40 million (2017 – $34 million) related to operating facilities, which represents the present value of the estimated future amount it expects to spend to remediate the sites. However, additional liabilities may be incurred as assessments take place and remediation efforts continue.

TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. The amounts involved in such proceedings are not reasonably estimable as the final outcome of such legal proceedings cannot be predicted with certainty. It is the opinion of management that the ultimate 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 financial performance of this entity. Such agreements include a guarantee and a letter of credit which are primarily related to construction services and the delivery of natural gas.

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 recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees is as follows:



		2018		2017
at December 31	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value
(millions of Canadian $)	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value

Sur de Texas	ranging to 2020	183	1	315	2
Bruce Power	ranging to 2021	88	—	88	1
Other jointly owned entities	ranging to 2059	104	11	104	13
		375	12	507	16


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

CORPORATE RESTRUCTURING COSTS

12 Months Ended

Dec. 31, 2018

Restructuring and Related Activities [Abstract]

CORPORATE RESTRUCTURING COSTS

In mid-2015, the Company commenced a business restructuring and transformation initiative to reduce overall costs and maximize the effectiveness and efficiency of its existing operations. The Company incurred corporate restructuring costs and recorded a provision to allow for planned severance costs in future years, as well as expected future losses under lease commitments.

Cumulatively to December 31, 2018, the Company has incurred costs of $86 million for employee severance and $60 million for lease commitments, net of $157 million related to costs that were recoverable through regulatory and tolling structures. The Company recorded additional provisions in 2018 to reflect the changes in expected future losses under lease commitments. The remaining lease commitments provision at December 31, 2018 is expected to be fully realized by 2027.

Changes in the restructuring liability were as follows:



(millions of Canadian $)	Employee Severance		Lease Commitments		Total

Restructuring liability as at December 31, 2016	36		63		99
Restructuring charges¹	—		6		6
Accretion expense	—		1		1
Cash payments	(27	)	(17	)	(44	)
Restructuring liability as at December 31, 2017	9		53		62
Restructuring charges¹	—		42		42
Accretion expense	—		1		1
Cash payments	(9	)	(15	)	(24	)
Restructuring Liability as at December 31, 2018	—		81		81


1	At December 31, 2018, the Company recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million as a regulatory asset on the Consolidated balance sheet related to costs that are recoverable through regulatory and tolling structures in future periods (2017 – $3 million and $3 million, respectively).

VARIABLE INTEREST ENTITIES

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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 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 for the settlement of the VIE’s obligations are as follows:



at December 31
(millions of Canadian $)	2018	2017

ASSETS
Current Assets
Cash and cash equivalents	45	41
Accounts receivable	79	63
Inventories	24	23
Other	13	11
	161	138
Plant, Property and Equipment	3,026	3,535
Equity Investments	965	917
Goodwill	453	490
Intangible and Other Assets	8	3
	4,613	5,083
LIABILITIES
Current Liabilities
Accounts payable and other	88	137
Dividends payable	—	1
Accrued interest	24	23
Current portion of long-term debt	79	88
	191	249
Regulatory Liabilities	43	34
Other Long-Term Liabilities	3	3
Deferred Income Tax Liabilities	13	13
Long-Term Debt	3,125	3,244
	3,375	3,543

Non-Consolidated VIEs

The Company’s non-consolidated VIEs consist of legal entities where the Company is not the primary beneficiary as it 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:



at December 31
(millions of Canadian $)	2018	2017

Balance sheet
Equity investments	4,575	4,372
Off-balance sheet
Potential exposure to guarantees	170	171
Maximum exposure to loss	4,745	4,543

ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Basis of Presentation

Use of Estimates and Judgments

Significant estimates and judgments used in the preparation of the consolidated financial statements that involve assumptions that are highly uncertain or subjective include, but are not limited to:


•	fair value of plant, property and equipment and equity investments (Notes 8 and 9)


•	fair value of goodwill (Note 11)


•	fair value of intangible assets (Note 12) and


•	fair value of assets and liabilities acquired in a business combination (Note 26).


•	depreciation rates of plant, property and equipment (Note 8)


•	carrying value of regulatory assets and liabilities (Note 10)


•	carrying value of asset retirement obligations (Note 15)


•	provisions for income taxes, including U.S. Tax Reform (Note 16)


•	assumptions used to measure retirement and other post-retirement obligations (Note 23)


•	fair value of financial instruments (Note 24) and


•	provisions for commitments, contingencies, guarantees (Note 27) and restructuring costs (Note 28).

Actual results could differ from these estimates.

Regulation


•	a regulator must establish or approve the rates for the regulated services or activities


•	the regulated rates must be designed to recover the cost of providing the services or products and


•	it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers because of the demand for services or products and the level of direct or indirect competition.

Revenue Recognition

Canadian Natural Gas Pipelines

Capacity Arrangements and Transportation

U.S. Natural Gas Pipelines

Capacity Arrangements and Transportation

Natural Gas Storage and Other

Mexico Natural Gas Pipelines

Capacity Arrangements and Transportation

Liquids Pipelines

Capacity Arrangements and Transportation

Energy

Power Generation

Natural Gas Storage and Other

Cash and Cash Equivalents

Inventories

Assets Held for Sale

Plant, Property and Equipment

Natural Gas Pipelines

Midstream and Other

Liquids Pipelines

Energy

Corporate

Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful life at average annual rates ranging from three per cent to 20 per cent.

Capitalized Project Costs

Impairment of Long-Lived Assets

Acquisitions and Goodwill

Loans and Receivables

Loans receivable from affiliates and accounts receivable are measured at cost.

Power Purchase Arrangements

Restricted Investments

Income Taxes

Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.

Asset Retirement Obligations

For those AROs that the Company records, the following assumptions are used:


•	when the asset is expected to be retired


•	the scope and cost of abandonment and reclamation activities that are required and


•	appropriate inflation and discount rates.

Environmental Liabilities

Stock Options and Other Compensation Programs

Employee Post-Retirement Benefits

Foreign Currency Transactions and Translation

Derivative Instruments and Hedging Activities

In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change.

Long-Term Debt Transaction Costs and Issuance Costs

Guarantees

Accounting Changes

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.

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

The Company’s accounting policies related to revenue recognition have not substantially changed as a result of adopting the new guidance on revenue from contracts with customers. Results reported for 2018 reflect the application of the new guidance, while the 2017 and 2016 comparative results were prepared and reported under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP." Under legacy U.S. GAAP, revenues were recognized when the risk, rewards, and benefits were transferred to the customer by the Company providing the goods or services under the contract, in an amount the Company expected to collect from the customer.

Under the new guidance applied in 2018, revenues are recognized when the Company satisfies its performance obligations by transferring control of the promised goods or services to its customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company has elected to utilize a practical expedient to recognize revenues from its U.S. and certain Mexico natural gas pipelines contracts as customers are invoiced. 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 5, Revenues, for further information related to the impact of adopting 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 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 intra-entity asset transfers when the transfer occurs. The new guidance was effective January 1, 2018, was applied using a modified retrospective approach, and resulted in an adjustment to retained earnings of $95 million.

In February 2018, the FASB issued new guidance that allows a reclassification from AOCI to retained earnings for stranded tax effects resulting from U.S. Tax Reform. 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. This new guidance is effective January 1, 2019, however, early adoption is permitted. The Company elected to early adopt this guidance effective fourth quarter 2018 and used a portfolio approach for releasing the income tax effects from AOCI to retained earnings. The Company applied this guidance retrospectively, at the beginning of the period of adoption, resulting in an adjustment to retained earnings of $17 million.

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 period and end of period 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.

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 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.

Derecognition of Nonfinancial Assets

In February 2017, the FASB issued new guidance that clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset. The FASB also amended the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. This new guidance was effective January 1, 2018, was applied using the modified retrospective transition method and did not have a material impact on the Company's 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 with early adoption permitted. The Company elected to adopt this guidance effective fourth quarter 2018 as it simplified goodwill impairment testing. The guidance was applied prospectively and used in the 2018 annual goodwill impairment test.

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 lessee 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. Lessees will classify leases as finance or operating, with classification affecting the pattern of expense recognition in the statement of income. The new guidance does not make extensive changes to lessor accounting. The Company currently expects that substantially all of its leases where the Company is the lessor will continue to be classified as operating leases under the new standard.

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 it consistently to all of its existing or expired land easements not previously accounted for as leases. The Company will apply this practical expedient upon transition to the new standard.

The new guidance is effective January 1, 2019, with early adoption permitted. The Company will adopt the new standard on its effective date. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application being January 1, 2019. In July 2018, the FASB issued a transition option allowing entities to not apply the new guidance, including disclosure requirements, to the comparative periods they present in their financial statements in the year of adoption. The Company will apply this transition option and use the effective date as the date of initial application. Consequently, financial information will not be updated and disclosures required under the new standard will not be provided for dates and periods before January 1, 2019.

The Company will elect the package of practical expedients which permits entities not to reassess prior conclusions about lease identification, lease classification and initial direct costs under the rules of the new standard.

The Company believes that the most significant effects of adoption will relate to the recognition of new ROU assets and lease liabilities on the Company's balance sheet for its operating leases and providing significant new disclosures about the Company's leasing activities. The guidance will not impact the Company's income statement. On adoption, the Company will recognize ROU assets of approximately $606 million and additional operating lease liabilities of approximately $600 million based on the present value of the remaining minimum lease payments for existing operating leases. The new standard also provides practical expedients for a Company’s ongoing accounting. The Company will elect the short-term lease recognition exemption for all eligible leases. This means, for those leases that qualify, the Company will not recognize ROU assets or lease liabilities. The Company will also elect the practical expedient to not separate lease and non-lease components for all leases for which the Company is the lessee and for facility and liquids tank terminals for which the Company is the lessor.

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.

Fair value measurement

In August 2018, the FASB issued new guidance that amends certain disclosure requirements for fair value measurements. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Defined benefit plans

In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to DB pension and other post retirement benefit plans. This new guidance is effective January 1, 2021, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Implementation costs of cloud computing arrangements

In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting arrangement over the term of the arrangement. This guidance is effective January 1, 2020, however, early adoption is permitted. This guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Consolidation

In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

SEGMENTED INFORMATION (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment



year ended December 31, 2018	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total
(millions of Canadian $)	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total

Revenues	4,038		4,314		619		2,584		2,124		—			13,679
Intersegment revenues	—		162		—		—		56		(218	)	²	—
	4,038		4,476		619		2,584		2,180		(218	)		13,679
Income from equity investments	12		256		22		64		355		5		³	714
Plant operating costs and other	(1,405	)	(1,368	)	(34	)	(630	)	(313	)	159		²	(3,591	)
Commodity purchases resold	—		—		—		—		(1,488	)	—			(1,488	)
Property taxes	(266	)	(199	)	—		(98	)	(6	)	—			(569	)
Depreciation and amortization	(1,129	)	(664	)	(97	)	(341	)	(119	)	—			(2,350	)
Goodwill and other asset impairment charges	—		(801	)	—		—		—		—			(801	)
Gain on sale of assets	—		—		—		—		170		—			170
Segmented earnings/(losses)	1,250		1,700		510		1,579		779		(54	)		5,764
Interest expense														(2,265	)
Allowance for funds used during construction														526
Interest income and other³														(76	)
Income before income taxes														3,949
Income tax expense														(432	)
Net income														3,517
Net loss attributable to non-controlling interests														185
Net income attributable to controlling interests														3,702
Preferred share dividends														(163	)
Net income attributable to common shares														3,539

Capital spending
Capital expenditures	2,442		5,591		463		110		767		45			9,418
Capital projects in development	36		1		—		459		—		—			496
Contributions to equity investments	—		179		334		12		490		—			1,015
	2,478		5,771		797		581		1,257		45			10,929


1	Includes intersegment eliminations.



year ended December 31, 2017	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total
(millions of Canadian $)	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total

Revenues	3,693		3,584		570		2,009		3,593		—			13,449
Intersegment revenues	—		51		—		—		—		(51	)	²	—
	3,693		3,635		570		2,009		3,593		(51	)		13,449
Income/(loss) from equity investments	11		240		(9	)	(3	)	471		63		³	773
Plant operating costs and other	(1,300	)	(1,340	)	(42	)	(623	)	(550	)	(51	)	²	(3,906	)
Commodity purchases resold	—		—		—		—		(2,382	)	—			(2,382	)
Property taxes	(260	)	(181	)	—		(89	)	(39	)	—			(569	)
Depreciation and amortization	(908	)	(594	)	(93	)	(309	)	(151	)	—			(2,055	)
Goodwill and other asset impairment charges	—		—		—		(1,236	)	(21	)	—			(1,257	)
Gain on sale of assets	—		—		—		—		631		—			631
Segmented earnings/(losses)	1,236		1,760		426		(251	)	1,552		(39	)		4,684
Interest expense														(2,069	)
Allowance for funds used during construction														507
Interest income and other³														184
Income before income taxes														3,306
Income tax recovery														89
Net income														3,395
Net income attributable to non-controlling interests														(238	)
Net income attributable to controlling interests														3,157
Preferred share dividends														(160	)
Net income attributable to common shares														2,997

Capital spending
Capital expenditures	2,106		3,712		833		341		350		41			7,383
Capital projects in development	75		—		—		71		—		—			146
Contributions to equity investments	—		118		1,121		117		325		—			1,681
	2,181		3,830		1,954		529		675		41			9,210


1	Includes intersegment eliminations.



year ended December 31, 2016	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total
(millions of Canadian $)	Canadian Natural Gas Pipelines		U.S. Natural Gas Pipelines		Mexico Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate¹			Total

Revenues	3,682		2,526		378		1,755		4,206		—			12,547
Intersegment revenues	—		56		—		—		—		(56	)	²	—
	3,682		2,582		378		1,755		4,206		(56	)		12,547
Income/(loss) from equity investments	12		214		(3	)	(1	)	292		—			514
Plant operating costs and other	(1,245	)	(1,057	)	(43	)	(568	)	(884	)	(64	)	²	(3,861	)
Commodity purchases resold	—		—		—		—		(2,172	)	—			(2,172	)
Property taxes	(267	)	(120	)	—		(88	)	(80	)	—			(555	)
Depreciation and amortization	(875	)	(425	)	(45	)	(292	)	(302	)	—			(1,939	)
Goodwill and other asset impairment charges	—		—		—		—		(1,388	)	—			(1,388	)
Loss on assets held for sale/sold	—		(4	)	—		—		(829	)	—			(833	)
Segmented earnings/(losses)	1,307		1,190		287		806		(1,157	)	(120	)		2,313
Interest expense														(1,998	)
Allowance for funds used during construction														419
Interest income and other														103
Income before income taxes														837
Income tax expense														(352	)
Net income														485
Net income attributable to non-controlling interests														(252	)
Net income attributable to controlling interests														233
Preferred share dividends														(109	)
Net income attributable to common shares														124

Capital spending
Capital expenditures	1,372		1,517		944		668		473		33			5,007
Capital projects in development	153		—		—		142		—		—			295
Contributions to equity investments	—		5		198		327		235		—			765
	1,525		1,522		1,142		1,137		708		33			6,067


1	Includes intersegment eliminations.



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Total Assets by segment
Canadian Natural Gas Pipelines	18,407	16,904
U.S. Natural Gas Pipelines	44,115	35,898
Mexico Natural Gas Pipelines	7,058	5,716
Liquids Pipelines	17,352	15,438
Energy	8,475	8,503
Corporate	3,513	3,642
	98,920	86,101

Revenue from External Customers by Geographic Areas



year ended December 31	2018	2017	2016
(millions of Canadian $)	2018	2017	2016

Revenues
Canada – domestic	4,187	3,618	3,697
Canada – export	1,075	1,255	1,177
United States	7,798	8,006	7,295
Mexico	619	570	378
	13,679	13,449	12,547

Schedule of Long-Lived Assets by Country



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Plant, Property and Equipment
Canada	23,226	21,632
United States	37,385	30,693
Mexico	5,892	4,952
	66,503	57,277

REVENUES (Tables)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenues

The following tables summarizes total Revenues for the year ended December 31, 2018.



(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	4,038	3,549	614	2,079	—	10,280
Power generation	—	—	—	—	1,771	1,771
Natural gas storage and other	—	654	5	3	81	743
	4,038	4,203	619	2,082	1,852	12,794
Other revenues^1,2	—	111	—	502	272	885
	4,038	4,314	619	2,584	2,124	13,679


2	Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 16, Income taxes, for further information.

Impact of New Revenue Recognition Guidance

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
(millions of Canadian $)	December 31, 2017	Adjustment		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.

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



	December 31, 2018
	As reported	Pro-forma using legacy U.S. GAAP
(millions of Canadian $)

Current Assets
Accounts receivable	2,535	2,694
Other	1,180	1,021

Contract Balances



(millions of Canadian $)	December 31, 2018	January 1, 2018
(millions of Canadian $)	December 31, 2018	January 1, 2018

Receivables from contracts with customers	1,684	1,736
Contract assets¹	159	79
Long-term contract assets²	21	—
Contract liabilities³	11	17
Long-term contract liabilities⁴	121	—


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


2	Recorded as part of Intangibles and other assets on the Consolidated balance sheet.


3	Comprised of deferred revenue recorded in Accounts payable and other on the Consolidated balance sheet. During the year ended December 31, 2018,

$17 million of revenue was recognized that was included in the contract liability at the beginning of the year.


4	Comprised of deferred revenue recorded in Other long-term liabilities on the Consolidated balance sheet.

ASSETS HELD FOR SALE (Tables)

12 Months Ended

Dec. 31, 2018

Discontinued Operations and Disposal Groups [Abstract]

Assets and Liabilities Classified as Held for Sale

At December 31, 2018, the related assets and liabilities were classified as held for sale in the Energy segment as follows:



(millions of Canadian $)

Assets held for sale
Accounts receivable	6
Plant, property and equipment	537
Total assets held for sale	543
Liabilities related to assets held for sale
Other long-term liabilities	(3	)
Total liabilities related to assets held for sale¹	(3	)


1	Included in Accounts payable and other on the Consolidated balance sheet.

- Definition

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Section 45
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721677-107760

+ Details

OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2018

Other Assets [Abstract]

Schedule of Other Current Assets



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Fair value of derivative contracts (Note 24)	737	332
Contract assets (Note 5)	159	—
Regulatory assets (Note 10)	83	23
Cash provided as collateral	55	99
Prepaid expenses	41	109
Other	105	128
	1,180	691

PLANT, PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Schedule of Plant, Property and Equipment



	2018			2017
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Canadian Natural Gas Pipelines
NGTL System
Pipeline	10,764	4,500	6,264	10,153	4,190	5,963
Compression	3,289	1,677	1,612	3,021	1,593	1,428
Metering and other	1,247	613	634	1,188	569	619
	15,300	6,790	8,510	14,362	6,352	8,010
Under construction	2,111	—	2,111	940	—	940
	17,411	6,790	10,621	15,302	6,352	8,950
Canadian Mainline
Pipeline	10,077	6,777	3,300	9,763	6,455	3,308
Compression	3,642	2,656	986	3,605	2,499	1,106
Metering and other	652	241	411	655	207	448
	14,371	9,674	4,697	14,023	9,161	4,862
Under construction	149	—	149	156	—	156
	14,520	9,674	4,846	14,179	9,161	5,018
Other Canadian Natural Gas Pipelines¹
Other	1,842	1,420	422	1,815	1,363	452
Under construction	124	—	124	4	—	4
	1,966	1,420	546	1,819	1,363	456
	33,897	17,884	16,013	31,300	16,876	14,424
U.S. Natural Gas Pipelines
Columbia Gas
Pipeline	6,711	251	6,460	3,550	125	3,425
Compression	2,932	132	2,800	1,547	64	1,483
Metering and other	2,884	75	2,809	2,306	37	2,269
	12,527	458	12,069	7,403	226	7,177
Under construction	4,347	—	4,347	3,332	—	3,332
	16,874	458	16,416	10,735	226	10,509
ANR
Pipeline	1,600	443	1,157	1,427	365	1,062
Compression	1,978	388	1,590	1,582	286	1,296
Metering and other	1,217	324	893	961	268	693
	4,795	1,155	3,640	3,970	919	3,051
Under construction	272	—	272	358	—	358
	5,067	1,155	3,912	4,328	919	3,409



	2018			2017
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Other U.S. Natural Gas Pipelines
GTN	2,322	951	1,371	2,107	822	1,285
Great Lakes	2,180	1,251	929	1,988	1,113	875
Columbia Gulf	1,753	74	1,679	1,115	37	1,078
Midstream	1,212	91	1,121	1,085	54	1,031
Other²	1,190	474	716	1,950	574	1,376
	8,657	2,841	5,816	8,245	2,600	5,645
Under construction	846	—	846	699	—	699
	9,503	2,841	6,662	8,944	2,600	6,344
	31,444	4,454	26,990	24,007	3,745	20,262
Mexico Natural Gas Pipelines
Pipeline	3,172	301	2,871	2,872	214	2,658
Compression	506	41	465	448	30	418
Metering and other	640	91	549	573	65	508
	4,318	433	3,885	3,893	309	3,584
Under construction	1,990	—	1,990	1,368	—	1,368
	6,308	433	5,875	5,261	309	4,952
Liquids Pipelines
Keystone Pipeline System
Pipeline	9,780	1,271	8,509	9,002	992	8,010
Pumping equipment	1,065	184	881	1,022	152	870
Tanks and other³	3,598	488	3,110	3,314	385	2,929
	14,443	1,943	12,500	13,338	1,529	11,809
Under construction⁴	18	—	18	456	—	456
	14,461	1,943	12,518	13,794	1,529	12,265
Intra-Alberta Pipelines⁵
Pipeline	762	22	740	748	3	745
Pumping equipment	104	3	101	104	—	104
Tanks and other	291	8	283	259	1	258
	1,157	33	1,124	1,111	4	1,107
Under construction	84	—	84	47	—	47
	1,241	33	1,208	1,158	4	1,154
	15,702	1,976	13,726	14,952	1,533	13,419
Energy
Natural Gas⁶	2,062	708	1,354	2,645	743	1,902
Wind⁷	—	—	—	673	204	469
Natural Gas Storage and Other	741	169	572	734	156	578
	2,803	877	1,926	4,052	1,103	2,949
Under construction	1,735	—	1,735	1,028	—	1,028
	4,538	877	3,661	5,080	1,103	3,977
Corporate	448	210	238	411	168	243
	92,337	25,834	66,503	81,011	23,734	57,277


1	Includes Foothills, Ventures LP, Great Lakes Canada and Coastal GasLink.


2	Includes Portland, North Baja, Tuscarora and Crossroads as well as Bison for 2017. Bison's remaining carrying value was fully impaired at December 31, 2018.


3	Includes tanks that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $194 million and $23 million, respectively, at December 31, 2018 (2017 – $184 million and $19 million, respectively), while revenues of $15 million were recognized in 2018 (2017 – $16 million; 2016 – $16 million).


4	Certain costs related to the Keystone XL project were recorded in Plant, property and equipment at December 31, 2017. In 2018, these costs were reclassified to Capital projects in development as the Company recommenced capitalizing Keystone XL development costs.


7	The Company closed the sale of its Cartier Wind power assets on October 24, 2018. Refer to Note 26, Acquisitions and dispositions, for further information.

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2018

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Investments



(millions of Canadian $)	Ownership Interest at December 31, 2018		Income/(Loss) from Equity Investments						Equity Investments
			year ended December 31						at December 31
			2018		2017		2016		2018	2017

Canadian Natural Gas Pipelines
TQM	50.0	%	12		11		12		71	68
U.S. Natural Gas Pipelines
Northern Border¹	50.0	%	87		87		92		677	641
Iroquois²	50.0	%	60		59		54		291	280
Millennium³	47.5	%	75		66		33		511	291
Pennant Midstream³	47.0	%	17		11		6		256	228
Other	Various		17		17		29		113	92
Mexico Natural Gas Pipelines
Sur de Texas⁴	60.0	%	27		66		(3	)	627	399
TransGas	nil		—		(12	)	—		—	—
Liquids Pipelines
Grand Rapids⁵	50.0	%	65		17		(1	)	1,028	996
Other⁶	Various		(1	)	(20	)	—		21	20
Energy
Bruce Power⁷	48.3	%	311		434		293		3,166	2,987
Portlands Energy⁸	50.0	%	36		31		33		289	301
ASTC Power Partnership	50.0	%	—		—		(37	)	—	—
Other	Various		8		6		3		63	63
			714		773		514		7,113	6,366


1	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company was US$115 million (2017 – US$115 million) due to the fair value assessment of assets at the time of acquisition.


2	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million (2017 – US$41 million) due mainly to the fair value assessment of the assets at the time of acquisition.


3	Acquired as part of Columbia Pipeline Group, Inc. (Columbia) on July 1, 2016. Income from Equity investments reflects equity earnings from the date of acquisition.


4	TransCanada has an ownership interest of 60.0 per cent in Sur de Texas which, as a jointly controlled entity, applies the equity method of accounting. Income from equity investments includes foreign exchange gains and losses recorded in the Corporate segment which are fully offset in Interest income and other in the Consolidated statement of income.


5	Grand Rapids was placed in service in August 2017. At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $102 million (2017 – $105 million) due mainly to interest capitalized during construction and the fair value of guarantees.


6	Includes investments in Canaport Energy East Marine Terminal Limited Partnership and HoustonLink Pipeline Company LLC. At December 31, 2018 and 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil.


7	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $870 million (2017 – $902 million) due to the fair value assessment of assets at the time of acquisitions.


8	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million (2017 – $73 million) due mainly to interest capitalized during construction.

Summarized Financial Information of Equity Investments



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Income
Revenues	4,836		4,913		4,336
Operating and other expenses	(3,545	)	(2,993	)	(3,068	)
Net income	1,515		1,636		1,080
Net income attributable to TransCanada	714		773		514



at December 31	2018		2017
(millions of Canadian $)	2018		2017

Balance Sheet
Current assets	2,209		2,176
Non-current assets	20,647		17,869
Current liabilities	(2,049	)	(1,577	)
Non-current liabilities	(9,042	)	(8,217	)

RATE-REGULATED BUSINESSES (Tables)

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities



at December 31	2018	2017	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)	2018	2017	Remaining Recovery/ Settlement Period (years)

Regulatory Assets
Deferred income taxes¹	1,051	940	n/a
Operating and debt-service regulatory assets²	12	—	1
Pensions and other post-retirement benefits^1,3	379	388	n/a
Foreign exchange on long-term debt^1,4	46	—	1-11
Other	143	71	n/a
	1,631	1,399
Less: Current portion included in Other current assets (Note 7)	83	23
	1,548	1,376

Regulatory Liabilities
Operating and debt-service regulatory liabilities²	96	188	1
Pensions and other post-retirement benefits³	53	164	n/a
ANR related post-employment and retirement benefits other than pension⁵	54	66	n/a
Long term adjustment account⁶	1,015	1,142	2-45
Bridging amortization account⁶	305	202	12
Pipeline abandonment trust balance	1,113	825	n/a
Cost of removal⁷	261	216	n/a
Deferred income taxes	165	75	n/a
Deferred income taxes – U.S. Tax Reform⁸	1,394	1,659	n/a
Other	65	47	n/a
	4,521	4,584
Less: Current portion included in Accounts payable and other (Note 14)	591	263
	3,930	4,321


1	These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.


2	Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulator for inclusion in determining tolls for the following calendar year.


3	These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates.


6	These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. The 2018 LTAA balance of $1,015 million consists of $932 million to be amortized over two years with the remaining balance to be amortized over 45 years.


7	This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated operations for future costs to be incurred.


8	These balances represent the impact of U.S. Tax Reform. The regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax liabilities that gave rise to the regulatory liabilities. See Note 16, Income taxes, for further information on U.S. Tax Reform.

GOODWILL (Tables)

12 Months Ended

Dec. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The Company has recorded the following Goodwill on its acquisitions:



(millions of Canadian $)	U.S. Natural Gas Pipelines

Balance at January 1, 2017	13,958
Columbia adjustment (Note 26)	71
Foreign exchange rate changes	(945	)
Balance at December 31, 2017	13,084
Tuscarora impairment charge	(79	)
Foreign exchange rate changes	1,173
Balance at December 31, 2018	14,178

INTANGIBLE AND OTHER ASSETS (Tables)

12 Months Ended

Dec. 31, 2018

Intangible Assets, Net (Excluding Goodwill) [Abstract]

Schedule of Other Assets



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Capital projects in development	1,051	596
Deferred income tax assets (Note 16)	322	316
Employee post-retirement benefits (Note 23)	192	193
Fair value of derivative contracts (Note 24)	61	73
Other	295	306
	1,921	1,484

NOTES PAYABLE (Tables)

12 Months Ended

Dec. 31, 2018

Short-term Debt [Abstract]

Schedule of Notes Payable



	2018			2017
(millions of Canadian $, unless otherwise noted)	Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31		Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31

Canada	2,117	2.5	%	884	1.6	%
U.S. (2018 – US$448; 2017 – US$688)	611	3.1	%	862	2.2	%
Mexico (2018 – US$25; 2017 – MXN$275)	34	3.3	%	17	8.0	%
	2,762			1,763

Schedule of Credit Facilities

These unsecured credit facilities included the following:

at December 31

(billions of Canadian $, unless otherwise noted)

2018

2017

Borrower

Description

Matures

Total Facilities

Unused Capacity

Total Facilities

Committed, syndicated, revolving, extendible, senior unsecured credit facilities¹:

TCPL

Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes

December 2023

3.0

TCPL/TCPL USA/Columbia/TAIL

Supports TCPL, TCPL USA and TAIL's U.S. dollar commercial paper programs and is used for general corporate purposes of the borrowers, guaranteed by TCPL

December 2019

US 4.5

—

TCPL/TCPL USA/Columbia/TAIL

Used for general corporate purposes of the borrowers, guaranteed by TCPL

December 2021

US 1.0

—

TCPL

Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes

—

US 2.0

TCPL USA

Used for TCPL USA general corporate purposes, guaranteed by TCPL

—

US 1.0

Columbia

Used for Columbia general corporate purposes, guaranteed by TCPL

—

US 1.0

TAIL

Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL

—

US 0.5

Demand senior unsecured revolving credit facilities¹:

TCPL/TCPL USA

Supports the issuance of letters of credit and provides additional liquidity, TCPL USA facility guaranteed by TCPL

Demand

2.1

1.0

1.9

Mexico subsidiary

Used for Mexico general corporate purposes, guaranteed by TCPL

Demand

MXN 5.0

MXN 4.5

MXN 5.0

ACCOUNTS PAYABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2018

Payables and Accruals [Abstract]

Schedule of Accounts Payable and Other



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Trade payables	3,224	2,847
Fair value of derivative contracts (Note 24)	922	387
Unredeemed shares of Columbia	357	312
Regulatory liabilities (Note 10)	591	263
Other	314	248
	5,408	4,057

OTHER LONG-TERM LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2018

Deferred Costs, Noncurrent [Abstract]

Schedule of Other Long-Term Liabilities



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Employee post-retirement benefits (Note 23)	569	389
Asset retirement obligations	90	98
Fair value of derivative contracts (Note 24)	42	72
Guarantees (Note 27)	12	16
Other	295	152
	1,008	727

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of Provision for Income Taxes



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Current
Canada	65		113		116
Foreign	250		36		40
	315		149		156
Deferred
Canada	49		(185	)	101
Foreign	235		751		95
Foreign – U.S. Tax Reform and 2018 FERC Actions	(167	)	(804	)	—
	117		(238	)	196
Income Tax Expense/(Recovery)	432		(89	)	352

Schedule of Geographic Components of Income



year ended December 31	2018	2017		2016
(millions of Canadian $)	2018	2017		2016

Canada	433	(339	)	219
Foreign	3,516	3,645		618
Income before Income Taxes	3,949	3,306		837

Reconciliation of Income Tax Expense



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Income before income taxes	3,949		3,306		837
Federal and provincial statutory tax rate	27	%	27	%	27	%
Expected income tax expense	1,066		893		226
U.S. Tax Reform and 2018 FERC Actions	(167	)	(804	)	—
Foreign income tax rate differentials	(432	)	(81	)	(196	)
Loss/(income) from equity investments and non-controlling interests	50		(64	)	(68	)
Income tax differential related to regulated operations	(54	)	(42	)	81
Non-taxable portion of capital gains	(11	)	(42	)	—
Asset impairment charges¹	—		34		242
Non-deductible amounts	—		4		46
Other	(20	)	13		21
Income Tax Expense/(Recovery)	432		(89	)	352


1	Net of nil (2017 – nil, 2016 – $112 million) attributed to higher foreign tax rates.

Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Deferred Income Tax Assets
Tax loss and credit carryforwards	1,238	1,379
Difference in accounting and tax bases of impaired assets and assets held for sale	574	651
Regulatory and other deferred amounts	858	512
Unrealized foreign exchange losses on long-term debt	491	216
Financial instruments	—	10
Other	292	227
	3,453	2,995
Less: valuation allowance	1,159	832
	2,294	2,163
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,449	6,240
Equity investments	1,069	632
Taxes on future revenue requirement	300	238
Other	180	140
	7,998	7,250
Net Deferred Income Tax Liabilities	5,704	5,087

The above deferred tax amounts have been classified in the Consolidated balance sheet as follows:



at December 31	2018	2017
(millions of Canadian $)	2018	2017

Deferred Income Tax Assets
Intangible and other assets (Note 12)	322	316
Deferred Income Tax Liabilities
Deferred income tax liabilities	6,026	5,403
Net Deferred Income Tax Liabilities	5,704	5,087

Reconciliation of the Annual Changes in the Total Unrecognized Tax Benefit

Below is the reconciliation of the annual changes in the total unrecognized tax benefit:



at December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Unrecognized tax benefit at beginning of year	15		18		17
Gross increases – tax positions in prior years	13		—		3
Gross decreases – tax positions in prior years	(5	)	(1	)	—
Gross increases – tax positions in current year	—		2		2
Settlement	—		—		(1	)
Lapse of statutes of limitations	(4	)	(4	)	(3	)
Unrecognized Tax Benefit at End of Year	19		15		18

LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

The Company issued long-term debt over the three years ended December 31, 2018 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Issue Date

Type

Maturity Date

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

October 2018

Senior Unsecured Notes

March 2049

US 1,000

5.10

October 2018

Senior Unsecured Notes

May 2028

US 400

4.25

July 2018

Medium Term Notes

July 2048

800

4.18

July 2018

Medium Term Notes

March 2028

200

3.39

May 2018

Senior Unsecured Notes

May 2028

US 1,000

4.25

May 2018

Senior Unsecured Notes

May 2048

US 1,000

4.875

May 2018

Senior Unsecured Notes

May 2038

US 500

4.75

November 2017

Senior Unsecured Notes

November 2019

US 550

Floating

November 2017

Senior Unsecured Notes

November 2019

US 700

2.125

September 2017

Medium Term Notes

March 2028

300

3.39

September 2017

Medium Term Notes

September 2047

700

4.33

June 2016

Acquisition Bridge Facility³

June 2018

US 5,213

Floating

June 2016

Medium Term Notes

July 2023

300

3.69

⁴

June 2016

Medium Term Notes

June 2046

700

4.35

January 2016

Senior Unsecured Notes

January 2026

US 850

4.875

January 2016

Senior Unsecured Notes

January 2019

US 400

3.125

NORTH BAJA PIPELINE, LLC

December 2018

Unsecured Term Loan

December 2021

US 50

Floating

PORTLAND NATURAL GAS TRANSMISSION SYSTEM

April 2018

Unsecured Loan Facility

April 2023

US 19

Floating

TUSCARORA GAS TRANSMISSION COMPANY

August 2017

Unsecured Term Loan

August 2020

US 25

Floating

April 2016

Unsecured Term Loan

April 2019

US 10

Floating

TC PIPELINES, LP

May 2017

Senior Unsecured Notes

May 2027

US 500

3.90

TRANSCANADA PIPELINE USA LTD.

June 2016

Acquisition Bridge Facility³

June 2018

US 1,700

Floating

ANR PIPELINE COMPANY

June 2016

Senior Unsecured Notes

June 2026

US 240

4.14


1	Reflects coupon rate on re-opening of a pre-existing senior unsecured notes issue. The notes were issued at a discount to par, resulting in a re-issuance yield of 4.439 per cent.


2	Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at a discount to par, resulting in a re-issuance yield of 3.41 per cent.


3	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the issuance of common shares in fourth quarter 2016 and 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.


4	Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent.



		2018			2017
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate¹		Outstanding at December 31	Interest Rate¹
(millions of Canadian $, unless otherwise noted)	Maturity Dates	Outstanding at December 31	Interest Rate¹		Outstanding at December 31	Interest Rate¹

TRANSCANADA PIPELINES LIMITED
Debentures
Canadian	2019 to 2020	350	11.4	%	500	10.8	%
U.S. (2018 and 2017 – US$400)	2021	546	9.9	%	501	9.9	%
Medium Term Notes
Canadian	2019 to 2048	7,504	4.8	%	6,504	4.9	%
Senior Unsecured Notes
U.S. (2018 – US$17,192; 2017 – US$14,892)	2019 to 2049	23,456	5.1	%	18,644	5.1	%
		31,856			26,149
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian	2024	100	9.9	%	100	9.9	%
U.S. (2018 and 2017 – US$200)	2023	273	7.9	%	250	7.9	%
Medium Term Notes
Canadian	2025 to 2030	504	7.4	%	504	7.4	%
U.S. (2018 and 2017 – US$33)	2026	44	7.5	%	41	7.5	%
		921			895
COLUMBIA PIPELINE GROUP, INC.
Senior Unsecured Notes
U.S. (2018 – US$2,250; 2017 – US$2,750)²	2020 to 2045	3,070	4.4	%	3,443	4.0	%
TC PIPELINES, LP
Unsecured Loan Facility
U.S. (2018 – US$40; 2017 – US$185)	2021	55	3.8	%	232	2.7	%
Unsecured Term Loan
U.S. (2018 – US$500; 2017 – US$670)³	2022	682	3.6	%	839	2.7	%
Senior Unsecured Notes
U.S. (2018 and 2017 – US$1,200)	2021 to 2027	1,637	4.4	%	1,502	4.4	%
		2,374			2,573
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2018 and 2017 – US$672)	2021 to 2026	918	7.2	%	842	7.2	%
GAS TRANSMISSION NORTHWEST LLC
Unsecured Term Loan
U.S. (2018 – US$35; 2017 – US$55)	2019	48	3.3	%	69	1.1	%
Senior Unsecured Notes
U.S. (2018 and 2017 – US$250)	2020 to 2035	341	5.6	%	313	5.6	%
		389			382
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2018 – US$240; 2017 – US$259)	2021 to 2030	327	7.7	%	324	7.7	%



		2018				2017
Outstanding amounts	Maturity Dates	Outstanding at December 31		Interest Rate¹		Outstanding at December 31		Interest Rate¹
(millions of Canadian $, unless otherwise noted)	Maturity Dates	Outstanding at December 31		Interest Rate¹		Outstanding at December 31		Interest Rate¹

PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Unsecured Loan Facility
U.S. (2018 – US$19; 2017 – nil)	2023	26		3.6	%	—		—
Senior Secured Notes⁴
U.S. (2018 – nil; 2017 – US$30)		—		—		38		6.0	%
		26				38
TUSCARORA GAS TRANSMISSION COMPANY
Unsecured Term Loan
U.S. (2018 – US$24; 2017 – US$25)	2020	33		3.5	%	31		1.1	%
NORTH BAJA PIPELINE, LLC
Unsecured Term Loan
U.S. (2018 – US$50; 2017 – nil)	2021	68		3.5	%	—		—
		39,982				34,677
Current portion of long-term debt		(3,462	)			(2,866	)
Unamortized debt discount and issue costs		(241	)			(174	)
Fair value adjustments⁵		230				238
		36,509				31,875


2	Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia’s obligations is required to comply with covenants under the debt indenture and in the event of default, the guarantors would be obligated to pay the principal and related interest.


3	The US$500 million term loan facility was amended in September 2017 to extend the maturity dates from 2018 to 2022.


4	These notes were secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.


5	The fair value adjustments include $232 million (2017 – $242 million) related to the acquisition of Columbia. The fair value adjustments also include a decrease of $2 million (2017 – $4 million) related to hedged interest rate risk. Refer to Note 24, Risk management and financial instruments, for further information.

Schedule of Repayments of Long-Term Debt

At December 31, 2018, principal repayments for the next five years on the Company's long-term debt are approximately as follows:



(millions of Canadian $)	2019	2020	2021	2022	2023

Principal repayments on long-term debt	3,465	2,834	2,098	2,100	1,930

Schedule of Retired Long-Term Debt

The Company retired/repaid long-term debt over the three years ended December 31, 2018 as follows:



(millions of Canadian $, unless otherwise noted)
Company	Retirement/Repayment Date	Type	Amount	Interest Rate

TRANSCANADA PIPELINES LIMITED
	August 2018	Senior Unsecured Notes	US 850	6.50	%
	March 2018	Debentures	150	9.45	%
	January 2018	Senior Unsecured Notes	US 500	1.875	%
	January 2018	Senior Unsecured Notes	US 250	Floating
	December 2017	Debentures	100	9.80	%
	November 2017	Senior Unsecured Notes	US 1,000	1.625	%
	June 2017	Acquisition Bridge Facility¹	US 1,513	Floating
	February 2017	Acquisition Bridge Facility¹	US 500	Floating
	January 2017	Medium Term Notes	300	5.10	%
	November 2016	Acquisition Bridge Facility¹	US 3,200	Floating
	October 2016	Medium Term Notes	400	4.65	%
	June 2016	Senior Unsecured Notes	US 84	7.69	%
	June 2016	Senior Unsecured Notes	US 500	Floating
	January 2016	Senior Unsecured Notes	US 750	0.75	%
TC PIPELINES, LP
	December 2018	Unsecured Term Loan	US 170	Floating
COLUMBIA PIPELINE GROUP, INC.
	June 2018	Senior Unsecured Notes	US 500	2.45	%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
	May 2018	Senior Secured Notes	US 18	5.90	%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
	March 2018	Senior Unsecured Notes	US 9	6.73	%
TUSCARORA GAS TRANSMISSION COMPANY
	August 2017	Senior Secured Notes	US 12	3.82	%
TRANSCANADA PIPELINE USA LTD.
	June 2017	Acquisition Bridge Facility¹	US 630	Floating
	April 2017	Acquisition Bridge Facility¹	US 1,070	Floating
NOVA GAS TRANSMISSION LTD.
	February 2016	Debentures	225	12.20	%


1	These facilities were put in place to finance a portion of the Columbia acquisition and were fully retired in second quarter 2017.

Schedule of Interest Expense

Interest expense in the three years ended December 31 was as follows:



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Interest on long-term debt	1,877		1,794		1,765
Interest on junior subordinated notes	391		348		180
Interest on short-term debt	73		33		18
Capitalized interest	(124	)	(173	)	(176	)
Amortization and other financial charges¹	48		67		211
	2,265		2,069		1,998

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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+ Details

JUNIOR SUBORDINATED NOTES (Tables)

12 Months Ended

Dec. 31, 2018

Junior Subordinated Notes [Abstract]

Schedule of Junior Subordinated Notes



		2018				2017
Outstanding loan amount	Maturity Date	Outstanding at December 31		Effective Interest Rate¹		Outstanding at December 31		Effective Interest Rate¹
(millions of Canadian $, unless otherwise noted)	Maturity Date	Outstanding at December 31		Effective Interest Rate¹		Outstanding at December 31		Effective Interest Rate¹

TRANSCANADA PIPELINES LIMITED²
US$1,000 notes issued 2007at 6.35%³	2067	1,364		5.6	%	1,252		5.0	%
US$750 notes issued 2015 at 5.875%^4,5	2075	1,024		6.5	%	939		5.9	%
US$1,200 notes issued 2016 at 6.125%^4,5	2076	1,637		7.2	%	1,502		6.6	%
US$1,500 notes issued 2017 at 5.55%^4,5	2077	2,047		6.2	%	1,878		5.6	%
$1,500 notes issued 2017 at 4.90%^4,5	2077	1,500		5.5	%	1,500		5.1	%
		7,572				7,071
Unamortized debt discount and issue costs		(64	)			(64	)
		7,508				7,007


1	The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for loan fees and discounts.


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


3	In May 2017, Junior subordinated notes of US$1 billion converted from a fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three month LIBOR plus 2.21 per cent.


5	The coupon rate is initially a fixed interest rate for the first ten years and converts to a floating rate thereafter.

NON-CONTROLLING INTERESTS (Tables)

12 Months Ended

Dec. 31, 2018

Noncontrolling Interest [Abstract]

Schedule of Non-Controlling Interests

The Company's Non-controlling interests included in the Consolidated balance sheet are as follows:



at December 31	2018	2017
(millions of Canadian $)

Non-controlling interest in TC PipeLines, LP	1,655	1,852

The Company's Net (loss)/income attributable to non-controlling interests included in the Consolidated statement of income are as follows:



year ended December 31	2018		2017	2016
(millions of Canadian $)	2018		2017	2016

Non-controlling interest in TC PipeLines, LP	(185	)	220	215
Non-controlling interest in Portland Natural Gas Transmission System¹	—		9	20
Non-controlling interest in Columbia Pipeline Partners LP²	—		9	17
	(185	)	238	252


1	Non-controlling interest in 2017 for the period January 1 to May 31 when TransCanada sold its remaining interest in Portland to TC PipeLines, LP. Refer to Note 26, Acquisitions and dispositions for further information.


2	Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of Columbia Pipeline Partners LP.

COMMON SHARES (Tables)

12 Months Ended

Dec. 31, 2018

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Schedule of Common Shares



	Number of Shares		Amount
	(thousands)		(millions of Canadian $)

Outstanding at January 1, 2016	702,614		12,102
Issued under public offerings¹	156,825		7,752
Dividend reinvestment and share purchase plan	2,942		177
Exercise of options	1,683		74
Repurchase of shares	(305	)	(6	)
Outstanding at December 31, 2016	863,759		20,099
Dividend reinvestment and share purchase plan	12,824		790
At-the-market equity issuance program¹	3,462		216
Exercise of options	1,331		62
Outstanding at December 31, 2017	881,376		21,167
At-the-market equity issuance program¹	20,050		1,118
Dividend reinvestment and share purchase plan	15,937		855
Exercise of options	734		34
Outstanding at December 31, 2018	918,097		23,174


1	Net of issue costs and deferred income taxes.

Schedule of Weighted Average Shares



Weighted Average Common Shares Outstanding
(millions)	2018	2017	2016

Basic	902	872	759
Diluted	903	874	760

Schedule of Stock Options Activity



	Number of Options (thousands)		Weighted Average Exercise Prices	Weighted Average Remaining Contractual Life (years)
Options outstanding at January 1, 2018	11,026		$51.38
Options granted	2,250		$56.89
Options exercised	(734	)	$42.65
Options forfeited/expired	(138	)	$57.23
Options Outstanding at December 31, 2018	12,404		$52.83	3.6
Options Exercisable at December 31, 2018	8,189		$50.72	2.6

Schedule of Options Valuation Assumptions

The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions:



year ended December 31	2018		2017		2016

Weighted average fair value	$5.80		$7.22		$5.67
Expected life (years)¹	5.7		5.7		5.8
Interest rate	2.1	%	1.2	%	0.7	%
Volatility²	16	%	18	%	21	%
Dividend yield	4.2	%	3.6	%	4.9	%
Forfeiture rate³	—		—		5	%


1	Expected life is based on historical exercise activity.


2	Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.


3	On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance.

Schedule of Additional Option Information

The following table summarizes additional stock option information:



year ended December 31	2018	2017	2016
(millions of Canadian $, unless otherwise noted)	2018	2017	2016

Total intrinsic value of options exercised	10	28	31
Fair value of options that have vested	101	140	126
Total options vested	2.1 million	2.3 million	2.1 million

PREFERRED SHARES (Tables)

12 Months Ended

Dec. 31, 2018

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Schedule of Preferred Shares



at December 31	Number of Shares Outstanding	Current Yield		Annual Dividend Per Share		Redemption Price Per Share		Redemption and Conversion Option Date	Right to Convert Into^1,2	2018	2017	2016
	(thousands)									(millions of Canadian $)³

Cumulative First Preferred Shares
Series 1	9,498	3.266	%		$0.8165		$25.00	December 31, 2019	Series 2	233	233	233
Series 2	12,502	Floating⁴		Floating			$25.00	December 31, 2019	Series 1	306	306	306
Series 3	8,533	2.152	%		$0.538		$25.00	June 30, 2020	Series 4	209	209	209
Series 4	5,467	Floating⁴		Floating			$25.00	June 30, 2020	Series 3	134	134	134
Series 5	12,714	2.263	%		$0.56575		$25.00	January 30, 2021	Series 6	310	310	310
Series 6	1,286	Floating⁴		Floating			$25.00	January 30, 2021	Series 5	32	32	32
Series 7	24,000	4.00	%		$1.00		$25.00	April 30, 2019	Series 8	589	589	589
Series 9	18,000	4.25	%		$1.0625		$25.00	October 30, 2019	Series 10	442	442	442
Series 11	10,000	3.80	%		$0.95		$25.00	November 30, 2020	Series 12	244	244	244
Series 13	20,000	5.50	%		$1.375		$25.00	May 31, 2021	Series 14	493	493	493
Series 15	40,000	4.90	%		$1.225		$25.00	May 31, 2022	Series 16	988	988	988
Carrying value										3,980	3,980	3,980


3	Net of underwriting commissions and deferred income taxes.

- Definition

Tabular disclosure of an entity's stock, including par or stated value per share, number and dollar amount of share subscriptions, shares authorized, shares issued, shares outstanding, number and dollar amount of shares held in an employee trust, dividend per share, total dividends, share conversion features, par value plus additional paid in capital, the value of treasury stock and other information necessary to a fair presentation, and EPS information. Stock by class includes common, convertible, and preferred stocks which are not redeemable or redeemable solely at the option of the issuer. Includes preferred stock with redemption features that are solely within the control of the issuer and mandatorily redeemable stock if redemption is required to occur only upon liquidation or termination of the reporting entity. If more than one issue is outstanding, state the title of each issue and the corresponding dollar amount; dollar amount of any shares subscribed but unissued and the deduction of subscriptions receivable there from; number of shares authorized, issued, and outstanding.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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+ Details

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Components of Other Comprehensive Income/(Loss)

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



year ended December 31, 2018	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount

Foreign currency translation gains on net investment in foreign operations	1,323		35		1,358
Change in fair value of net investment hedges	(57	)	15		(42	)
Change in fair value of cash flow hedges	(14	)	4		(10	)
Reclassification to net income of gains and losses on cash flow hedges	27		(6	)	21
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(153	)	39		(114	)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	20		(5	)	15
Other comprehensive income on equity investments	113		(27	)	86
Other Comprehensive Income	1,259		55		1,314



year ended December 31, 2017	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount

Foreign currency translation losses on net investment in foreign operations	(746	)	(3	)	(749	)
Reclassification of foreign currency translation gains on disposal of foreign operations	(77	)	—		(77	)
Change in fair value of cash flow hedges	3		—		3
Reclassification to net income of gains and losses on cash flow hedges	(3	)	1		(2	)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(14	)	3		(11	)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	21		(5	)	16
Other comprehensive loss on equity investments	(141	)	35		(106	)
Other Comprehensive Loss	(957	)	31		(926	)



year ended December 31, 2016	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
Foreign currency translation gains on net investment in foreign operations	3		—		3
Change in fair value of net investment hedges	(14	)	4		(10	)
Change in fair value of cash flow hedges	44		(14	)	30
Reclassification to net income of gains and losses on cash flow hedges	71		(29	)	42
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(38	)	12		(26	)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	22		(6	)	16
Other comprehensive loss on equity investments	(117	)	30		(87	)
Other Comprehensive Loss	(29	)	(3	)	(32	)

Schedule of Changes in Accumulated Other Comprehensive Income

The changes in AOCI by component are as follows:



	Currency Translation Adjustments		Cash Flow Hedges		Pension and Other Post-Retirement Benefit Plan Adjustments		Equity Investments		Total¹

AOCI balance at January 1, 2016	(383	)	(97	)	(198	)	(261	)	(939	)
Other comprehensive income/(loss) before reclassifications²	7		27		(26	)	(101	)	(93	)
Amounts reclassified from AOCI	—		42		16		14		72
Net current period other comprehensive income/(loss)	7		69		(10	)	(87	)	(21	)
AOCI balance at December 31, 2016	(376	)	(28	)	(208	)	(348	)	(960	)
Other comprehensive (loss)/income before reclassifications^2,3	(590	)	(1	)	(11	)	(117	)	(719	)
Amounts reclassified from AOCI	(77	)	(2	)	16		11		(52	)
Net current period other comprehensive (loss)/income	(667	)	(3	)	5		(106	)	(771	)
AOCI balance at December 31, 2017	(1,043	)	(31	)	(203	)	(454	)	(1,731	)
Other comprehensive income/(loss) before reclassifications²	1,150		(9	)	(114	)	72		1,099
Amounts reclassified from AOCI^4,5	—		16		15		12		43
Net current period other comprehensive income/(loss)	1,150		7		(99	)	84		1,142
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	—		1		(12	)	(6	)	(17	)
AOCI balance at December 31, 2018	107		(23	)	(314	)	(376	)	(606	)


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


2	In 2018, other comprehensive income before reclassifications on currency translation adjustments and cash flow hedges are net of non-controlling interest gains of $166 million (2017 – $159 million losses; 2016 – $14 million losses) and losses of $1 million (2017 – $4 million gains and 2016 – $3 million gains), respectively.


3	Other comprehensive (loss)/income before reclassification on pension and other post-retirement benefit plan adjustments includes a $27 million reduction on settlements and curtailments.


5	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million and $2 million, respectively.

Schedule of Reclassifications out of Accumulated Other Comprehensive Income

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



	Amounts Reclassified From AOCI¹						Affected Line Item in the Consolidated Statement of Income
year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Cash flow hedges
Commodities	(4	)	20		(57	)	Revenues (Energy)
Interest	(18	)	(17	)	(14	)	Interest expense
	(22	)	3		(71	)	Total before tax
	6		(1	)	29		Income tax expense
	(16	)	2		(42	)	Net of tax^1,3
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial gains and losses	(16	)	(15	)	(22	)	Plant operating costs and other²
Settlement charge	(4	)	(2	)	—		Plant operating costs and other²
	(20	)	(17	)	(22	)	Total before tax
	5		5		6		Income tax expense
	(15	)	(12	)	(16	)	Net of tax¹
Equity investments
Equity income	(16	)	(15	)	(19	)	Income from equity investments
	4		4		5		Income tax expense
	(12	)	(11	)	(14	)	Net of tax^1,3
Currency translation adjustments
Realization of foreign currency translation gains on disposal of foreign operations	—		77		—		Gain/(loss) on assets held for sale/sold
	—		—		—		Income tax expense
	—		77		—		Net of tax¹


1	Amounts in parentheses indicate expenses to the Consolidated statement of income.


2	These AOCI components are included in the computation of net benefit cost. Refer to Note 23, Employee post-retirement benefits for further information.


3	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million (2017 – nil , 2016 – nil) and $2 million (2017 – nil, 2016 – nil), respectively.

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Schedule of Contributions for Defined Benefit Plans

Total cash contributions by the Company for employee post-retirement benefits were as follows:



year ended December 31	2018	2017	2016
(millions of Canadian $)	2018	2017	2016

DB Plans	103	163	111
Other post-retirement benefit plans	23	7	8
Savings and DC Plans	59	42	52
	185	212	171

Schedule of Change in Benefit Obligations, Change in Plan Assets, and Funded Status

The Company's funded status at December 31 is comprised of the following:



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2018		2017		2018		2017

Change in Benefit Obligation¹
Benefit obligation – beginning of year	3,646		3,456		375		372
Service cost	121		113		4		4
Interest cost	134		135		14		14
Employee contributions	5		5		—		3
Benefits paid	(177	)	(166	)	(23	)	(19	)
Actuarial (gain)/loss	(92	)	253		43		19
Curtailment	—		(14	)	—		(2	)
Settlement	(71	)	(66	)	—		—
Foreign exchange rate changes	87		(70	)	17		(16	)
Benefit obligation – end of year	3,653		3,646		430		375
Change in Plan Assets
Plan assets at fair value – beginning of year	3,451		3,208		365		354
Actual return on plan assets	(73	)	358		(15	)	45
Employer contributions²	103		163		23		7
Employee contributions	5		5		—		3
Benefits paid	(176	)	(166	)	(27	)	(19	)
Settlement	(71	)	(57	)	—		—
Foreign exchange rate changes	82		(60	)	30		(25	)
Plan assets at fair value – end of year	3,321		3,451		376		365
Funded Status – Plan Deficit	(332	)	(195	)	(54	)	(10	)


1	The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation.


2	Excludes a $17 million letter of credit provided to the Canadian DB Plan for funding purposes (2017 – $27 million).

Schedule of Amounts Recognized in the Balance Sheet for its DB Plans and Other Post-Retirement Benefits Plans

The amounts recognized in the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans are as follows:



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2018		2017		2018		2017

Intangible and other assets (Note 12)	—		—		192		193
Accounts payable and other	(1	)	(1	)	(8	)	(8	)
Other long-term liabilities (Note 15)	(331	)	(194	)	(238	)	(195	)
	(332	)	(195	)	(54	)	(10	)

Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets

Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded:



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2018		2017		2018		2017

Projected benefit obligation¹	(3,653	)	(3,646	)	(246	)	(203	)
Plan assets at fair value	3,321		3,451		—		—
Funded Status – Plan Deficit	(332	)	(195	)	(246	)	(203	)


1	The projected benefit obligation for the pension benefit plans differ from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels.

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for All DB Plans

The funded status based on the accumulated benefit obligation for all DB Plans is as follows:



at December 31	2018		2017
(millions of Canadian $)	2018		2017

Accumulated benefit obligation	(3,347	)	(3,372	)
Plan assets at fair value	3,321		3,451
Funded Status	(26	)	79

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for Plans Not Fully Funded

Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded.



at December 31	2018		2017
(millions of Canadian $)	2018		2017

Accumulated benefit obligation	(3,347	)	(944	)
Plan assets at fair value	3,321		925
Funded Status – Plan Deficit	(26	)	(19	)

Schedule of Weighted Average Asset Allocations and Target Allocations by Asset Category

The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:



	Percentage of Plan Assets				Target Allocations
at December 31	2018		2017		2018

Debt securities	33	%	30	%	25% to 45%
Equity securities	56	%	64	%	40% to 70%
Alternatives	11	%	6	%	5% to 15%
	100	%	100	%

Schedule of Allocation of Plan Assets, Employer and Related Party Securities

Debt and equity securities include the Company's debt and common shares as follows:



at December 31			Percentage of Plan Assets
(millions of Canadian $)	2018	2017	2018		2017

Debt securities	8	7	0.3	%	0.2	%
Equity securities	7	3	0.2	%	0.1	%

Schedule of Plan Assets for DB Plans and Other Post-Retirement Benefits Measured at Fair Value



at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $)	2018	2017	2018	2017	2018	2017	2018	2017	2018	2017

Asset Category
Cash and Cash Equivalents	48	44	—	17	—	—	48	61	1	2
Equity Securities:
Canadian	355	410	138	151	—	—	493	561	13	15
U.S.	460	543	116	354	—	—	576	897	16	24
International	40	45	281	322	—	—	321	367	9	10
Global	116	—	268	301	—	—	384	301	10	8
Emerging	8	8	138	147	—	—	146	155	4	4
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	186	193	—	—	186	193	5	5
Provincial	—	—	198	194	—	—	198	194	5	5
Municipal	—	—	8	8	—	—	8	8	1	—
Corporate	—	—	112	122	—	—	112	122	3	3
U.S. Bonds:
Federal	350	—	—	244	—	—	350	244	9	6
State	—	—	—	41	—	—	—	41	—	1
Municipal	—	—	—	4	—	—	—	4	—	—
Corporate	145	—	51	234	—	—	196	234	5	6
International:
Government	6	—	4	4	—	—	10	4	1	—
Corporate	19	—	18	5	—	—	37	5	1	—
Mortgage backed	128	—	—	73	—	—	128	73	3	2
Other Investments:
Real estate	—	—	—	—	196	140	196	140	5	4
Infrastructure	—	—	—	—	163	70	163	70	4	2
Private equity funds	—	—	—	—	3	6	3	6	1	—
Funds held on deposit	142	136	—	—	—	—	142	136	4	3
	1,817	1,186	1,518	2,414	362	216	3,697	3,816	100	100

Schedule of the Net Change in the Level III Fair Value Category

The following table presents the net change in the Level III fair value category:



(millions of Canadian $, pre-tax)

Balance at December 31, 2016	199
Purchases and sales	11
Realized and unrealized gains	6
Balance at December 31, 2017	216
Purchases and sales	127
Realized and unrealized gains	19
Balance at December 31, 2018	362

Schedule of Estimated Future Benefit Payments

The following are estimated future benefit payments, which reflect expected future service:



(millions of Canadian $)	Pension Benefits	Other Post- Retirement Benefits

2019	190	24
2020	193	23
2021	198	23
2022	203	23
2023	207	23
2024 to 2028	1,081	114

Schedule of Weighted Average Assumptions Used in Calculating Benefit Obligation

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:



	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31	2018		2017		2018		2017

Discount rate	3.90	%	3.60	%	4.10	%	3.70	%
Rate of compensation increase	3.00	%	3.00	%	—		—

Schedule of Significant Weighted Average Actuarial Assumptions Adopted in Measuring Net Benefit Plan Costs

The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:



	Pension Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2018		2017		2016		2018		2017		2016

Discount rate	3.60	%	3.95	%	4.20	%	3.70	%	4.15	%	4.30	%
Expected long-term rate of return on plan assets	6.70	%	6.50	%	6.70	%	4.00	%	6.05	%	5.95	%
Rate of compensation increase	3.00	%	1.20	%	0.80	%	—		—		—

Schedule of Effects of a 1% Change in Assumed Health Care Cost Trend Rates

A one per cent change in assumed health care cost trend rates would have the following effects:



(millions of Canadian $)	Increase	Decrease

Effect on total of service and interest cost components	1	(1	)
Effect on post-retirement benefit obligation	25	(21	)

Schedule of Net Benefit Costs

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



at December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
(millions of Canadian $)	2018		2017		2016		2018		2017		2016

Service cost¹	121		108		107		4		4		3
Other components of net benefit cost¹
Interest cost	134		122		127		14		14		13
Expected return on plan assets	(221	)	(178	)	(175	)	(16	)	(21	)	(11	)
Amortization of actuarial loss	15		14		20		1		1		2
Amortization of regulatory asset	18		37		27		—		1		1
Amortization of transitional obligation related to regulated business	—		—		—		—		—		2
Settlement charge – regulatory asset	—		2		—		—		—		—
Settlement charge – AOCI	4		2		—		—		—		—
	(50	)	(1	)	(1	)	(1	)	(5	)	7
Net Benefit Cost Recognized	71		107		106		3		(1	)	10


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

Schedule of the Pre-Tax Amounts Recognized in AOCI

Pre-tax amounts recognized in AOCI were as follows:



	2018		2017		2016
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)
Net loss	364	53	273	11	270	21

Schedule of the Pre-Tax Amounts Recognized in OCI

Pre-tax amounts recognized in OCI were as follows:



	2018				2017				2016
at December 31	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits
(millions of Canadian $)	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits

Amortization of net loss from AOCI to net income	(15	)	(1	)	(18	)	(1	)	(20	)	(2	)
Curtailment	—		—		(14	)	(2	)	—		—
Settlement	(4	)	—		(11	)	—		—		—
Funded status adjustment	110		43		46		(7	)	43		(5	)
	91		42		3		(10	)	23		(7	)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2018

Risk Management and Financial Instruments [Abstract]

Summary of Derivative Instruments

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



	2018			2017
at December 31	Fair Value^1,2		Notional Amount	Fair Value^1,2		Notional Amount
(millions of Canadian $, unless otherwise noted)	Fair Value^1,2		Notional Amount	Fair Value^1,2		Notional Amount

U.S. dollar cross-currency interest rate swaps (maturing 2019)³	(43	)	US 300	(199	)	US 1,200
U.S. dollar foreign exchange options (maturing 2019 to 2020)	(47	)	US 2,500	5		US 500
	(90	)	US 2,800	(194	)	US 1,700


1	Fair value equals carrying value.


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


3	In 2018, Net income includes net realized gains of $2 million (2017 – gains of $4 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense.

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



at December 31, 2018	Power	Natural Gas	Liquids	Foreign Exchange	Interest Rate

Purchases¹	23,865	44	59	—	—
Sales¹	17,689	56	79	—	—
Millions of U.S. dollars	—	—	—	3,862	1,650
Maturity dates	2019-2023	2019-2027	2019	2019	2019-2030


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 Rate

Purchases¹	66,132	133	6	—	—
Sales¹	42,836	135	7	—	—
Millions of U.S. dollars	—	—	—	2,931	2,300
Millions of Mexican pesos	—	—	—	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.

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



at December 31	2018	2017
(millions of Canadian $, unless otherwise noted)	2018	2017

Notional amount	31,000 (US 22,700)	25,400 (US 20,200)
Fair value	31,700 (US 23,200)	28,900 (US 23,100)

Schedule of Financial Instruments



	2018				2017
at December 31	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions of Canadian $)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term debt, including current portion^1,2 (Note 17)	(39,971	)	(42,284	)	(34,741	)	(40,180	)
Junior subordinated notes (Note 18)	(7,508	)	(6,665	)	(7,007	)	(7,233	)
	(47,479	)	(48,949	)	(41,748	)	(47,413	)


1	Long-term debt is recorded at amortized cost, except for US$750 million (2017 – US$1.1 billion) that is attributed to hedged risk and recorded at fair value.

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:



	2018		2017
at December 31	LMCI Restricted Investments	Other Restricted Investments¹	LMCI Restricted Investments	Other Restricted Investments¹
(millions of Canadian $)	LMCI Restricted Investments	Other Restricted Investments¹	LMCI Restricted Investments	Other Restricted Investments¹

Fair value of fixed income securities²
Fixed income securities (maturing within 1 year)	—	22	—	23
Fixed income securities (maturing within 1-5 years)	—	110	—	107
Fixed income securities (maturing within 5-10 years)	140	—	14	—
Fixed income securities (maturing after 10 years)	952	—	790	—
	1,092	132	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 Company's Consolidated balance sheet.

The balance sheet classification of the fair value of derivative instruments as at December 31, 2018 is as follows:



at December 31, 2018	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments¹
(millions of Canadian $)	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments¹

Other current assets (Note 7)
Commodities²	1		—		—		716		717
Foreign exchange	—		—		16		1		17
Interest rate	3		—		—		—		3
	4		—		16		717		737
Intangible and other assets (Note 12)
Commodities²	1		—		—		50		51
Foreign exchange	—		—		1		—		1
Interest rate	8		1		—		—		9
	9		1		1		50		61
Total Derivative Assets	13		1		17		767		798

Accounts payable and other (Note 14)
Commodities²	(4	)	—		—		(622	)	(626	)
Foreign exchange	—		—		(105	)	(188	)	(293	)
Interest rate	—		(3	)	—		—		(3	)
	(4	)	(3	)	(105	)	(810	)	(922	)
Other long-term liabilities (Note 15)
Commodities²	—		—		—		(28	)	(28	)
Foreign exchange	—		—		(2	)	—		(2	)
Interest rate	(11	)	(1	)	—		—		(12	)
	(11	)	(1	)	(2	)	(28	)	(42	)
Total Derivative Liabilities	(15	)	(4	)	(107	)	(838	)	(964	)
Total Derivatives	(2	)	(3	)	(90	)	(71	)	(166	)


1	Fair value equals carrying value.


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

The balance sheet classification of the fair value of derivative instruments as at December 31, 2017 is as follows:



at December 31, 2017	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments¹
(millions of Canadian $)	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments¹

Other current assets (Note 7)
Commodities²	1		—		—		249		250
Foreign exchange	—		—		8		70		78
Interest rate	3		—		—		1		4
	4		—		8		320		332
Intangible and other assets (Note 12)
Commodities²	—		—		—		69		69
Interest rate	4		—		—		—		4
	4		—		—		69		73
Total Derivative Assets	8		—		8		389		405

Accounts payable and other (Note 14)
Commodities²	(6	)	—		—		(208	)	(214	)
Foreign exchange	—		—		(159	)	(10	)	(169	)
Interest rate	—		(4	)	—		—		(4	)
	(6	)	(4	)	(159	)	(218	)	(387	)
Other long-term liabilities (Note 15)
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.

Unrealized Gain (Loss) on Investments



	2018			2017			2016
year ended December 31 (millions of Canadian $)	LMCI restricted investments¹		Other restricted investments	LMCI restricted investments¹		Other restricted investments	LMCI restricted investments¹		Other restricted investments

Net unrealized gains/(losses)	11		—	(3	)	1	(28	)	(1	)
Net realized losses²	(4	)	—	(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	The realized gains and losses on the sale of LMCI restricted investment securities are determined using the average cost basis.

Realized Gain (Loss) on Investments



	2018			2017			2016
year ended December 31 (millions of Canadian $)	LMCI restricted investments¹		Other restricted investments	LMCI restricted investments¹		Other restricted investments	LMCI restricted investments¹		Other restricted investments

Net unrealized gains/(losses)	11		—	(3	)	1	(28	)	(1	)
Net realized losses²	(4	)	—	(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	The realized gains and losses on the sale of LMCI restricted investment securities are determined using the average cost basis.

Derivative Instruments - Balance Sheet and Income Statement Information

Derivatives in fair value hedging relationships

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



at December 31	Carrying amount				Fair value hedging adjustments¹
(millions of Canadian $)	2018		2017		2018	2017

Current portion of long-term debt	(748	)	(688	)	3	1
Long-term debt	(273	)	(685	)	—	4
	(1,021	)	(1,373	)	3	5


1	At December 31, 2018 and 2017, adjustments for discontinued hedging relationships included in these balances were nil.

Effect of fair value and cash flow hedging relationships

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



year ended December 31	Revenues (Energy)				Interest Expense
(millions of Canadian $)	2018	2017		2016	2018		2017		2016

Total Amount Presented in the Consolidated Statement of Income	2,124	3,593		4,206	(2,265	)	(2,069	)	(1,998	)
Fair Value Hedges
Interest rate contracts
Hedged items	—	—		—	(71	)	(74	)	(74	)
Derivatives designated as hedging instruments	—	—		—	(4	)	1		8
Cash Flow Hedges
Reclassification of gains/(losses) on derivative instruments from AOCI to net income^1,2
Interest rate contracts	—	—		—	22		17		14
Commodity contracts	5	(20	)	57	—		—		—


1	Refer to Note 22, 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.

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



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Derivative instruments held for trading¹
Amount of unrealized gains/(losses) in the year
Commodities²	28		62		123
Foreign exchange	(248	)	88		25
Interest rate	—		(1	)	—
Amount of realized gains/(losses) in the year
Commodities	351		(107	)	(204	)
Foreign exchange	(24	)	18		62
Interest rate	—		1		—
Derivative instruments in hedging relationships
Amount of realized (losses)/gains in the year
Commodities	(1	)	23		(167	)
Foreign exchange	—		5		(101	)
Interest rate	(1	)	1		4


1	Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively.


2	In 2018 and 2017, 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 (2016 – net loss of $42 million).

Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships

The components of OCI (Note 22) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows:



year ended December 31	2018		2017		2016
(millions of Canadian $, pre-tax)	2018		2017		2016

Change in fair value of derivative instruments recognized in OCI¹
Commodities	(1	)	(1	)	39
Interest rate	(13	)	4		5
	(14	)	3		44


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

Schedule of Offsetting Assets



at December 31, 2018	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts

Derivative – Asset
Commodities	768		(626	)	142
Foreign exchange	18		(18	)	—
Interest rate	12		(4	)	8
	798		(648	)	150
Derivative – Liability
Commodities	(654	)	626		(28	)
Foreign exchange	(295	)	18		(277	)
Interest rate	(15	)	4		(11	)
	(964	)	648		(316	)


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



at December 31, 2017	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts

Derivative – Asset
Commodities	319		(198	)	121
Foreign exchange	78		(56	)	22
Interest rate	8		(1	)	7
	405		(255	)	150
Derivative – Liability
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.

Schedule of Offsetting Liabilities



at December 31, 2018	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts

Derivative – Asset
Commodities	768		(626	)	142
Foreign exchange	18		(18	)	—
Interest rate	12		(4	)	8
	798		(648	)	150
Derivative – Liability
Commodities	(654	)	626		(28	)
Foreign exchange	(295	)	18		(277	)
Interest rate	(15	)	4		(11	)
	(964	)	648		(316	)


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



at December 31, 2017	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments		Amounts Available for Offset¹		Net Amounts

Derivative – Asset
Commodities	319		(198	)	121
Foreign exchange	78		(56	)	22
Interest rate	8		(1	)	7
	405		(255	)	150
Derivative – Liability
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.

Schedule of Fair Value of Assets and Liabilities Measured on a Recurring Basis

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 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 becomes 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 2018, are categorized as follows:



at December 31, 2018	Quoted Prices in Active Markets (Level I)¹		Significant Other Observable Inputs (Level II)¹		Significant Unobservable Inputs (Level III)¹		Total
(millions of Canadian $)	Quoted Prices in Active Markets (Level I)¹		Significant Other Observable Inputs (Level II)¹		Significant Unobservable Inputs (Level III)¹		Total

Derivative Instrument Assets:
Commodities	581		187		—		768
Foreign exchange	—		18		—		18
Interest rate	—		12		—		12
Derivative Instrument Liabilities:
Commodities	(555	)	(95	)	(4	)	(654	)
Foreign exchange	—		(295	)	—		(295	)
Interest rate	—		(15	)	—		(15	)
	26		(188	)	(4	)	(166	)


1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2018.

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 December 31, 2017	Quoted Prices in Active Markets (Level I)¹		Significant Other Observable Inputs (Level II)¹		Significant Unobservable Inputs (Level III)¹		Total
(millions of Canadian $)	Quoted Prices in Active Markets (Level I)¹		Significant Other Observable Inputs (Level II)¹		Significant Unobservable Inputs (Level III)¹		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.

Schedule of Net Change in the Level III Fair Value Category

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



(millions of Canadian $, pre-tax)	2018		2017

Balance at beginning of year	(7	)	16
Transfers out of Level III	5		(19	)
Total gains/(losses) included in Net income	8		(17	)
Settlements	(9	)	18
Sales	—		(5	)
Foreign exchange	(1	)	—
Balance at end of year¹	(4	)	(7	)


1	Revenues include unrealized losses of $5 million attributed to derivatives in the Level III category that were still held at December 31, 2018 (2017 – unrealized losses of $7 million).

CHANGES IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2018

CHANGES IN OPERATING WORKING CAPITAL

Schedule of changes in operating working capital



year ended December 31	2018		2017		2016
(millions of Canadian $)	2018		2017		2016

Increase in Accounts receivable	(69	)	(576	)	(482	)
Increase in Inventories	(49	)	(38	)	(87	)
Decrease/(increase) in Assets held for sale	—		14		(13	)
Decrease in Other current assets	45		189		328
(Decrease)/increase in Accounts payable and other	(70	)	151		424
Increase in Accrued interest	41		12		62
(Decrease)/increase in Liabilities related to assets held for sale	—		(25	)	16
(Increase)/decrease in Operating Working Capital	(102	)	(273	)	248

ACQUISITIONS AND DISPOSITIONS (Tables)

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed



	July 1, 2016
(millions of $)	U.S.		Canadian¹

Purchase Price Consideration	10,294		13,392
Fair Value
Current assets	658		856
Plant, property and equipment	7,560		9,835
Equity investments	441		574
Regulatory assets	190		248
Intangible and other assets	135		175
Current liabilities	(597	)	(777	)
Regulatory liabilities	(294	)	(383	)
Other long-term liabilities	(144	)	(187	)
Deferred income tax liabilities	(1,613	)	(2,098	)
Long-term debt	(2,981	)	(3,878	)
Non-controlling interests	(808	)	(1,051	)
Fair Value of Net Assets Acquired	2,547		3,314
Goodwill	7,747		10,078


1	At July 1, 2016 exchange rate of $1.30.

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

The following table summarizes the acquisition date fair value of Columbia's debt acquired by TransCanada.



(millions of $)	Maturity Date	Type	Fair Value	Interest Rate

COLUMBIA PIPELINE GROUP, INC.
	June 2018	Senior Unsecured Notes (US$500)	US$506	2.45	%
	June 2020	Senior Unsecured Notes (US$750)	US$779	3.30	%
	June 2025	Senior Unsecured Notes (US$1,000)	US$1,092	4.50	%
	June 2045	Senior Unsecured Notes (US$500)	US$604	5.80	%
			US$2,981

Business Acquisition, Pro Forma Information



year ended December 31
(millions of Canadian $)	2016	2015

Revenues	13,404	13,007
Net Income/(Loss)	627	(820	)
Net Income/(Loss) Attributable to Common Shares	234	(971	)

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Annual Payments

Future annual payments under the Company's operating leases for various premises, services and equipment, net of sublease receipts, are approximately as follows:



year ended December 31	Minimum Lease Payments	Amounts Recoverable under Subleases	Net Payments
(millions of Canadian $)	Minimum Lease Payments	Amounts Recoverable under Subleases	Net Payments

2019	81	7	74
2020	78	7	71
2021	76	4	72
2022	69	3	66
2023	67	3	64
2024 and thereafter	390	8	382
	761	32	729

Schedule of Guarantees

The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees is as follows:



		2018		2017
at December 31	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value
(millions of Canadian $)	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value

Sur de Texas	ranging to 2020	183	1	315	2
Bruce Power	ranging to 2021	88	—	88	1
Other jointly owned entities	ranging to 2059	104	11	104	13
		375	12	507	16


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

CORPORATE RESTRUCTURING COSTS (Tables)

12 Months Ended

Dec. 31, 2018

Restructuring and Related Activities [Abstract]

Restructuring and Related Costs

Changes in the restructuring liability were as follows:



(millions of Canadian $)	Employee Severance		Lease Commitments		Total

Restructuring liability as at December 31, 2016	36		63		99
Restructuring charges¹	—		6		6
Accretion expense	—		1		1
Cash payments	(27	)	(17	)	(44	)
Restructuring liability as at December 31, 2017	9		53		62
Restructuring charges¹	—		42		42
Accretion expense	—		1		1
Cash payments	(9	)	(15	)	(24	)
Restructuring Liability as at December 31, 2018	—		81		81


1	At December 31, 2018, the Company recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million as a regulatory asset on the Consolidated balance sheet related to costs that are recoverable through regulatory and tolling structures in future periods (2017 – $3 million and $3 million, respectively).

VARIABLE INTEREST ENTITIES (Tables)

12 Months Ended

Dec. 31, 2018

Variable Interest Entity, Primary Beneficiary

Variable Interest Entity [Line Items]

Schedule of Variable Interest Entities

The Consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations are as follows:



at December 31
(millions of Canadian $)	2018	2017

ASSETS
Current Assets
Cash and cash equivalents	45	41
Accounts receivable	79	63
Inventories	24	23
Other	13	11
	161	138
Plant, Property and Equipment	3,026	3,535
Equity Investments	965	917
Goodwill	453	490
Intangible and Other Assets	8	3
	4,613	5,083
LIABILITIES
Current Liabilities
Accounts payable and other	88	137
Dividends payable	—	1
Accrued interest	24	23
Current portion of long-term debt	79	88
	191	249
Regulatory Liabilities	43	34
Other Long-Term Liabilities	3	3
Deferred Income Tax Liabilities	13	13
Long-Term Debt	3,125	3,244
	3,375	3,543

Variable Interest Entity, Not Primary Beneficiary

Variable Interest Entity [Line Items]

Schedule of Variable Interest Entities

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:



at December 31
(millions of Canadian $)	2018	2017

Balance sheet
Equity investments	4,575	4,372
Off-balance sheet
Potential exposure to guarantees	170	171
Maximum exposure to loss	4,745	4,543

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

DESCRIPTION OF TRANSCANADA'S BUSINESS (Details)	12 Months Ended
DESCRIPTION OF TRANSCANADA'S BUSINESS (Details)	Dec. 31, 2018 plant segment mi km Bcf
Segment Reporting Information [Line Items]
Number of business segments in which the entity operates \| segment	5
Canadian Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) \| km	40,686
Investments of regulated natural gas pipelines (in miles) \| mi	25,281
U.S. Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) \| km	50,199
Investments of regulated natural gas pipelines (in miles) \| mi	31,192
Investments of regulated natural gas storage facilities (in billion cubic feet) \| Bcf	535
Mexico Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) \| km	1,670
Investments of regulated natural gas pipelines (in miles) \| mi	1,038
Liquids Pipelines
Segment Reporting Information [Line Items]
Wholly owned and operated crude oil pipeline systems (in kilometers) \| km	4,874
Wholly owned and operated crude oil pipeline systems (in miles) \| mi	3,030
Energy
Segment Reporting Information [Line Items]
Number of electrical power generation plants \| plant	10
Non-regulated natural gas storage facilities (in billion cubic feet) \| Bcf	118

ACCOUNTING POLICIES (Details)	12 Months Ended
ACCOUNTING POLICIES (Details)	Dec. 31, 2018
Employee Post-Retirement Benefits
Moving average period of basis used to determine expected return on plan assets (in years)	5 years
Corporate \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	3.00%
Corporate \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	20.00%
Natural Gas Pipelines \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	1.00%
Natural Gas Pipelines \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	7.00%
Midstream \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	1.70%
Midstream \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	2.50%
Liquids Pipelines \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	2.00%
Liquids Pipelines \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	2.50%
Energy \| Power generation and natural gas storage plant, equipment and structures \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	2.00%
Energy \| Power generation and natural gas storage plant, equipment and structures \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (in percent)	20.00%

ACCOUNTING CHANGES (Details) - CAD ($) $ in Millions	12 Months Ended
ACCOUNTING CHANGES (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2019	Jan. 01, 2018
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	$ 17
Accounting Standards Update 2016-02 \| Scenario, Forecast
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use asset		$ 606
Operating lease liabilities		$ 600
Accounting Standards Update 2016-16 \| Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative-effect adjustment for adoption of new accounting pronouncement			$ 95

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	12 Months Ended
SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segmented information
Revenues	$ 13,679	$ 13,449	$ 12,547
Income from equity investments	714	773	514
Plant operating costs and other	(3,591)	(3,906)	(3,861)
Commodity purchases resold	(1,488)	(2,382)	(2,172)
Property taxes	(569)	(569)	(555)
Depreciation and amortization	(2,350)	(2,055)	(1,939)
Goodwill and other asset impairment charges	(801)	(1,257)	(1,388)
Gain/(loss) on assets held for sale/sold	170	631	(833)
Segmented earnings/(losses)	5,764	4,684	2,313
Interest expense	(2,265)	(2,069)	(1,998)
Allowance for funds used during construction	526	507	419
Interest income and other	(76)	184	103
Income before Income Taxes	3,949	3,306	837
Income tax recovery/(expense)	(432)	89	(352)
Net Income	3,517	3,395	485
Net income attributable to non-controlling interests	185	(238)	(252)
Net Income Attributable to Controlling Interests	3,702	3,157	233
Preferred share dividends	(163)	(160)	(109)
Net Income Attributable to Common Shares	3,539	2,997	124
Capital spending
Capital expenditures	9,418	7,383	5,007
Capital projects in development	496	146	295
Contributions to equity investments	1,015	1,681	765
Capital spending	10,929	9,210	6,067
Assets	98,920	86,101
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	66,503	57,277
Canada
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	23,226	21,632
Canada – domestic
Segmented information
Revenues	4,187	3,618	3,697
Canada – export
Segmented information
Revenues	1,075	1,255	1,177
United States
Segmented information
Revenues	7,798	8,006	7,295
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	37,385	30,693
Mexico
Segmented information
Revenues	619	570	378
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	5,892	4,952
Corporate
Segmented information
Revenues	(218)	(51)	(56)
Income from equity investments	5	63	0
Plant operating costs and other	159	(51)	(64)
Commodity purchases resold	0	0	0
Property taxes	0	0	0
Depreciation and amortization	0	0	0
Goodwill and other asset impairment charges	0	0	0
Gain/(loss) on assets held for sale/sold	0	0	0
Segmented earnings/(losses)	(54)	(39)	(120)
Capital spending
Capital expenditures	45	41	33
Capital projects in development	0	0	0
Contributions to equity investments	0	0	0
Capital spending	45	41	33
Assets	3,513	3,642
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	238	243
Canadian Natural Gas Pipelines
Segmented information
Revenues	4,038	3,693	3,682
Canadian Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	4,038	3,693	3,682
Income from equity investments	12	11	12
Plant operating costs and other	(1,405)	(1,300)	(1,245)
Commodity purchases resold	0	0	0
Property taxes	(266)	(260)	(267)
Depreciation and amortization	(1,129)	(908)	(875)
Goodwill and other asset impairment charges	0	0	0
Gain/(loss) on assets held for sale/sold	0	0	0
Segmented earnings/(losses)	1,250	1,236	1,307
Capital spending
Capital expenditures	2,442	2,106	1,372
Capital projects in development	36	75	153
Contributions to equity investments	0	0	0
Capital spending	2,478	2,181	1,525
Assets	18,407	16,904
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	16,013	14,424
Canadian Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues	0	0	0
U.S. Natural Gas Pipelines
Segmented information
Revenues	4,314	3,584	2,526
U.S. Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	4,476	3,635	2,582
Income from equity investments	256	240	214
Plant operating costs and other	(1,368)	(1,340)	(1,057)
Commodity purchases resold	0	0	0
Property taxes	(199)	(181)	(120)
Depreciation and amortization	(664)	(594)	(425)
Goodwill and other asset impairment charges	(801)	0	0
Gain/(loss) on assets held for sale/sold	0	0	(4)
Segmented earnings/(losses)	1,700	1,760	1,190
Capital spending
Capital expenditures	5,591	3,712	1,517
Capital projects in development	1	0	0
Contributions to equity investments	179	118	5
Capital spending	5,771	3,830	1,522
Assets	44,115	35,898
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	26,990	20,262
U.S. Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues	162	51	56
Mexico Natural Gas Pipelines
Segmented information
Revenues	619	570	378
Mexico Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	619	570	378
Income from equity investments	22	(9)	(3)
Plant operating costs and other	(34)	(42)	(43)
Commodity purchases resold	0	0	0
Property taxes	0	0	0
Depreciation and amortization	(97)	(93)	(45)
Goodwill and other asset impairment charges	0	0	0
Gain/(loss) on assets held for sale/sold	0	0	0
Segmented earnings/(losses)	510	426	287
Capital spending
Capital expenditures	463	833	944
Capital projects in development	0	0	0
Contributions to equity investments	334	1,121	198
Capital spending	797	1,954	1,142
Assets	7,058	5,716
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	5,875	4,952
Mexico Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues	0	0	0
Liquids Pipelines
Segmented information
Revenues	2,584	2,009	1,755
Liquids Pipelines \| Operating segments
Segmented information
Revenues	2,584	2,009	1,755
Income from equity investments	64	(3)	(1)
Plant operating costs and other	(630)	(623)	(568)
Commodity purchases resold	0	0	0
Property taxes	(98)	(89)	(88)
Depreciation and amortization	(341)	(309)	(292)
Goodwill and other asset impairment charges	0	(1,236)	0
Gain/(loss) on assets held for sale/sold	0	0	0
Segmented earnings/(losses)	1,579	(251)	806
Capital spending
Capital expenditures	110	341	668
Capital projects in development	459	71	142
Contributions to equity investments	12	117	327
Capital spending	581	529	1,137
Assets	17,352	15,438
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	13,726	13,419
Liquids Pipelines \| Intersegment eliminations
Segmented information
Revenues	0	0	0
Energy
Segmented information
Revenues	2,124	3,593	4,206
Energy \| Operating segments
Segmented information
Revenues	2,180	3,593	4,206
Income from equity investments	355	471	292
Plant operating costs and other	(313)	(550)	(884)
Commodity purchases resold	(1,488)	(2,382)	(2,172)
Property taxes	(6)	(39)	(80)
Depreciation and amortization	(119)	(151)	(302)
Goodwill and other asset impairment charges	0	(21)	(1,388)
Gain/(loss) on assets held for sale/sold	170	631	(829)
Segmented earnings/(losses)	779	1,552	(1,157)
Capital spending
Capital expenditures	767	350	473
Capital projects in development	0	0	0
Contributions to equity investments	490	325	235
Capital spending	1,257	675	708
Assets	8,475	8,503
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	3,661	3,977
Energy \| Intersegment eliminations
Segmented information
Revenues	$ 56	$ 0	$ 0

REVENUES - Disaggregation of Revenues (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 12,794
Other revenues	885
Revenues	13,679	$ 13,449	$ 12,547
Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	10,280
Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,771
Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	743
Canadian Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,038
Other revenues	0
Revenues	4,038	3,693	3,682
Canadian Natural Gas Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,038
Canadian Natural Gas Pipelines \| Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Canadian Natural Gas Pipelines \| Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
U.S. Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,203
Other revenues	111
Revenues	4,314	3,584	2,526
U.S. Natural Gas Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,549
U.S. Natural Gas Pipelines \| Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
U.S. Natural Gas Pipelines \| Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	654
Mexico Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	619
Other revenues	0
Revenues	619	570	378
Mexico Natural Gas Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	614
Mexico Natural Gas Pipelines \| Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Mexico Natural Gas Pipelines \| Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,082
Other revenues	502
Revenues	2,584	2,009	1,755
Liquids Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,079
Liquids Pipelines \| Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Liquids Pipelines \| Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3
Energy
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,852
Other revenues	272
Revenues	2,124	$ 3,593	$ 4,206
Energy \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Energy \| Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,771
Energy \| Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 81

REVENUES - Impact of New Revenue Guidance (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Current Assets
Accounts receivable	$ 2,535	$ 2,460	$ 2,522
Other	1,180	770	691
Current Liabilities
Accounts payable and other	5,408	4,074	4,057
Calculated under Revenue Guidance in Effect before Topic 606
Current Assets
Accounts receivable	2,694
Other	$ 1,021
Calculated under Revenue Guidance in Effect before Topic 606 \| Accounting Standards Update 2014-09
Current Assets
Accounts receivable			2,522
Other			691
Current Liabilities
Accounts payable and other			$ 4,057
Difference between Revenue Guidance in Effect before and after Topic 606 \| Accounting Standards Update 2014-09
Current Assets
Accounts receivable		(62)
Other		79
Current Liabilities
Accounts payable and other		$ 17

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Jan. 01, 2018
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 1,684	$ 1,736
Contract assets	159	79
Long-term contract assets	21	0
Contract liabilities	11	17
Long-term contract liabilities	121	$ 0
Revenue recognized	$ 17

REVENUES - Remaining Performance Obligations - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($)
Long-term pipeline capacity arrangements and transportation contracts \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 6,000
Future revenues, expected timing of satisfaction, period	1 year
Long-term pipeline capacity arrangements and transportation contracts \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 30,100
Natural gas storage and other \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 283
Future revenues, expected timing of satisfaction, period	1 year
Natural gas storage and other \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 1,200

REVENUES - Additional Information - Narrative (Details)	12 Months Ended
REVENUES - Additional Information - Narrative (Details)	Dec. 31, 2018
Rate-regulated firm capacity contracts
Disaggregation of Revenue [Line Items]
Future revenues, expected timing of satisfaction, explanation	one to three years

ASSETS HELD FOR SALE - Narrative (Details) $ in Millions, $ in Millions		12 Months Ended
	Jun. 30, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)	Dec. 14, 2018 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale		$ 170	$ 631	$ (833)
Coolidge generating station \| Disposal group, not discontinued operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale consideration					$ 465
Coolidge generating station \| Disposal group, not discontinued operations \| Scenario, Forecast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale	$ 65
Gain on sale, net of tax	50
Foreign currency translation gains	$ 10

ASSETS HELD FOR SALE - Assets and Liabilities Classified as Held for Sale (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Assets held for sale
Total assets held for sale	$ 543	$ 0
Coolidge generating station \| Disposal group, not discontinued operations
Assets held for sale
Accounts receivable	6
Plant, property and equipment	537
Total assets held for sale	543
Liabilities related to assets held for sale
Other long-term liabilities	(3)
Total liabilities related to assets held for sale	$ (3)

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Other Assets [Abstract]
Fair value of derivative contracts (Note 24)	$ 737		$ 332
Contract assets (Note 5)	159	$ 79
Regulatory assets (Note 10)	83		23
Cash provided as collateral	55		99
Prepaid expenses	41		109
Other	105		128
Other current assets, total	$ 1,180	$ 770	$ 691

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions				12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Oct. 05, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Plant, property and equipment
Cost	$ 92,337	$ 81,011		$ 92,337	$ 81,011
Accumulated Depreciation	25,834	23,734		25,834	23,734
Net Book Value	66,503	57,277		66,503	57,277
Revenues				12,794
Energy East, Eastern Mainline and Upland projects
Plant, property and equipment
Impairment charge			$ 83
Impairment charge, net of tax			$ 64
Power development project
Plant, property and equipment
Impairment charge		21
Impairment charge, net of tax		16
Bison
Plant, property and equipment
Impairment charge	722
Impairment charge, net of tax and noncontrolling interest	140
Gain on contract termination	130
Gain on contract termination, net of tax and noncontrolling interest	25
Canadian Natural Gas Pipelines
Plant, property and equipment
Revenues				4,038
Canadian Natural Gas Pipelines \| Under construction \| NGTL System
Plant, property and equipment
Accumulated Depreciation	0	0		0	0
U.S. Natural Gas Pipelines
Plant, property and equipment
Revenues				4,203
Mexico Natural Gas Pipelines
Plant, property and equipment
Revenues				619
Liquids Pipelines
Plant, property and equipment
Revenues				2,082
Liquids Pipelines \| Tanks and other, operating leases \| Keystone Pipeline System
Plant, property and equipment
Cost	194	184		194	184
Accumulated Depreciation	23	19		23	19
Operating lease income				15	16	$ 16
Liquids Pipelines \| Pipelines, operating leases \| Northern Courier
Plant, property and equipment
Cost	1,130	1,111		1,130	1,111
Accumulated Depreciation	32	4		32	4
Operating lease income				142	20
Energy
Plant, property and equipment
Revenues				1,852
Energy \| Facilities under PPAs
Plant, property and equipment
Cost	655	1,264		655	1,264
Accumulated Depreciation	268	354		268	354
Revenues				216	215	$ 212
Operating segments \| Canadian Natural Gas Pipelines
Plant, property and equipment
Cost	33,897	31,300		33,897	31,300
Accumulated Depreciation	17,884	16,876		17,884	16,876
Net Book Value	16,013	14,424		16,013	14,424
Operating segments \| Canadian Natural Gas Pipelines \| NGTL System
Plant, property and equipment
Cost	17,411	15,302		17,411	15,302
Accumulated Depreciation	6,790	6,352		6,790	6,352
Net Book Value	10,621	8,950		10,621	8,950
Operating segments \| Canadian Natural Gas Pipelines \| Canadian Mainline
Plant, property and equipment
Cost	14,520	14,179		14,520	14,179
Accumulated Depreciation	9,674	9,161		9,674	9,161
Net Book Value	4,846	5,018		4,846	5,018
Operating segments \| Canadian Natural Gas Pipelines \| Other
Plant, property and equipment
Cost	1,842	1,815		1,842	1,815
Accumulated Depreciation	1,420	1,363		1,420	1,363
Net Book Value	422	452		422	452
Operating segments \| Canadian Natural Gas Pipelines \| Other Natural Gas Pipelines
Plant, property and equipment
Cost	1,966	1,819		1,966	1,819
Accumulated Depreciation	1,420	1,363		1,420	1,363
Net Book Value	546	456		546	456
Operating segments \| Canadian Natural Gas Pipelines \| Pipeline \| NGTL System
Plant, property and equipment
Cost	10,764	10,153		10,764	10,153
Accumulated Depreciation	4,500	4,190		4,500	4,190
Net Book Value	6,264	5,963		6,264	5,963
Operating segments \| Canadian Natural Gas Pipelines \| Pipeline \| Canadian Mainline
Plant, property and equipment
Cost	10,077	9,763		10,077	9,763
Accumulated Depreciation	6,777	6,455		6,777	6,455
Net Book Value	3,300	3,308		3,300	3,308
Operating segments \| Canadian Natural Gas Pipelines \| Compression \| NGTL System
Plant, property and equipment
Cost	3,289	3,021		3,289	3,021
Accumulated Depreciation	1,677	1,593		1,677	1,593
Net Book Value	1,612	1,428		1,612	1,428
Operating segments \| Canadian Natural Gas Pipelines \| Compression \| Canadian Mainline
Plant, property and equipment
Cost	3,642	3,605		3,642	3,605
Accumulated Depreciation	2,656	2,499		2,656	2,499
Net Book Value	986	1,106		986	1,106
Operating segments \| Canadian Natural Gas Pipelines \| Metering and other \| NGTL System
Plant, property and equipment
Cost	1,247	1,188		1,247	1,188
Accumulated Depreciation	613	569		613	569
Net Book Value	634	619		634	619
Operating segments \| Canadian Natural Gas Pipelines \| Metering and other \| Canadian Mainline
Plant, property and equipment
Cost	652	655		652	655
Accumulated Depreciation	241	207		241	207
Net Book Value	411	448		411	448
Operating segments \| Canadian Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| NGTL System
Plant, property and equipment
Cost	15,300	14,362		15,300	14,362
Accumulated Depreciation	6,790	6,352		6,790	6,352
Net Book Value	8,510	8,010		8,510	8,010
Operating segments \| Canadian Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Canadian Mainline
Plant, property and equipment
Cost	14,371	14,023		14,371	14,023
Accumulated Depreciation	9,674	9,161		9,674	9,161
Net Book Value	4,697	4,862		4,697	4,862
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| NGTL System
Plant, property and equipment
Cost	2,111	940		2,111	940
Net Book Value	2,111	940		2,111	940
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| Canadian Mainline
Plant, property and equipment
Cost	149	156		149	156
Accumulated Depreciation	0	0		0	0
Net Book Value	149	156		149	156
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| Other Natural Gas Pipelines
Plant, property and equipment
Cost	124	4		124	4
Accumulated Depreciation	0	0		0	0
Net Book Value	124	4		124	4
Operating segments \| U.S. Natural Gas Pipelines
Plant, property and equipment
Cost	31,444	24,007		31,444	24,007
Accumulated Depreciation	4,454	3,745		4,454	3,745
Net Book Value	26,990	20,262		26,990	20,262
Operating segments \| U.S. Natural Gas Pipelines \| Other Natural Gas Pipelines
Plant, property and equipment
Cost	9,503	8,944		9,503	8,944
Accumulated Depreciation	2,841	2,600		2,841	2,600
Net Book Value	6,662	6,344		6,662	6,344
Operating segments \| U.S. Natural Gas Pipelines \| Columbia Gas
Plant, property and equipment
Cost	16,874	10,735		16,874	10,735
Accumulated Depreciation	458	226		458	226
Net Book Value	16,416	10,509		16,416	10,509
Operating segments \| U.S. Natural Gas Pipelines \| ANR
Plant, property and equipment
Cost	5,067	4,328		5,067	4,328
Accumulated Depreciation	1,155	919		1,155	919
Net Book Value	3,912	3,409		3,912	3,409
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Other
Plant, property and equipment
Cost	1,190	1,950		1,190	1,950
Accumulated Depreciation	474	574		474	574
Net Book Value	716	1,376		716	1,376
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Columbia Gas
Plant, property and equipment
Cost	6,711	3,550		6,711	3,550
Accumulated Depreciation	251	125		251	125
Net Book Value	6,460	3,425		6,460	3,425
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| ANR
Plant, property and equipment
Cost	1,600	1,427		1,600	1,427
Accumulated Depreciation	443	365		443	365
Net Book Value	1,157	1,062		1,157	1,062
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| GTN
Plant, property and equipment
Cost	2,322	2,107		2,322	2,107
Accumulated Depreciation	951	822		951	822
Net Book Value	1,371	1,285		1,371	1,285
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Great Lakes
Plant, property and equipment
Cost	2,180	1,988		2,180	1,988
Accumulated Depreciation	1,251	1,113		1,251	1,113
Net Book Value	929	875		929	875
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Columbia Gulf
Plant, property and equipment
Cost	1,753	1,115		1,753	1,115
Accumulated Depreciation	74	37		74	37
Net Book Value	1,679	1,078		1,679	1,078
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Midstream
Plant, property and equipment
Cost	1,212	1,085		1,212	1,085
Accumulated Depreciation	91	54		91	54
Net Book Value	1,121	1,031		1,121	1,031
Operating segments \| U.S. Natural Gas Pipelines \| Compression \| Columbia Gas
Plant, property and equipment
Cost	2,932	1,547		2,932	1,547
Accumulated Depreciation	132	64		132	64
Net Book Value	2,800	1,483		2,800	1,483
Operating segments \| U.S. Natural Gas Pipelines \| Compression \| ANR
Plant, property and equipment
Cost	1,978	1,582		1,978	1,582
Accumulated Depreciation	388	286		388	286
Net Book Value	1,590	1,296		1,590	1,296
Operating segments \| U.S. Natural Gas Pipelines \| Metering and other \| Columbia Gas
Plant, property and equipment
Cost	2,884	2,306		2,884	2,306
Accumulated Depreciation	75	37		75	37
Net Book Value	2,809	2,269		2,809	2,269
Operating segments \| U.S. Natural Gas Pipelines \| Metering and other \| ANR
Plant, property and equipment
Cost	1,217	961		1,217	961
Accumulated Depreciation	324	268		324	268
Net Book Value	893	693		893	693
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Other Natural Gas Pipelines
Plant, property and equipment
Cost	8,657	8,245		8,657	8,245
Accumulated Depreciation	2,841	2,600		2,841	2,600
Net Book Value	5,816	5,645		5,816	5,645
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Columbia Gas
Plant, property and equipment
Cost	12,527	7,403		12,527	7,403
Accumulated Depreciation	458	226		458	226
Net Book Value	12,069	7,177		12,069	7,177
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| ANR
Plant, property and equipment
Cost	4,795	3,970		4,795	3,970
Accumulated Depreciation	1,155	919		1,155	919
Net Book Value	3,640	3,051		3,640	3,051
Operating segments \| U.S. Natural Gas Pipelines \| Under construction
Plant, property and equipment
Accumulated Depreciation	0	0		0	0
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| Other Natural Gas Pipelines
Plant, property and equipment
Cost	846	699		846	699
Accumulated Depreciation	0	0		0	0
Net Book Value	846	699		846	699
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| Columbia Gas
Plant, property and equipment
Cost	4,347	3,332		4,347	3,332
Accumulated Depreciation	0	0		0	0
Net Book Value	4,347	3,332		4,347	3,332
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| ANR
Plant, property and equipment
Cost	272	358		272	358
Net Book Value	272	358		272	358
Operating segments \| Mexico Natural Gas Pipelines
Plant, property and equipment
Cost	6,308	5,261		6,308	5,261
Accumulated Depreciation	433	309		433	309
Net Book Value	5,875	4,952		5,875	4,952
Operating segments \| Mexico Natural Gas Pipelines \| Pipeline
Plant, property and equipment
Cost	3,172	2,872		3,172	2,872
Accumulated Depreciation	301	214		301	214
Net Book Value	2,871	2,658		2,871	2,658
Operating segments \| Mexico Natural Gas Pipelines \| Compression
Plant, property and equipment
Cost	506	448		506	448
Accumulated Depreciation	41	30		41	30
Net Book Value	465	418		465	418
Operating segments \| Mexico Natural Gas Pipelines \| Metering and other
Plant, property and equipment
Cost	640	573		640	573
Accumulated Depreciation	91	65		91	65
Net Book Value	549	508		549	508
Operating segments \| Mexico Natural Gas Pipelines \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	4,318	3,893		4,318	3,893
Accumulated Depreciation	433	309		433	309
Net Book Value	3,885	3,584		3,885	3,584
Operating segments \| Mexico Natural Gas Pipelines \| Under construction
Plant, property and equipment
Cost	1,990	1,368		1,990	1,368
Accumulated Depreciation	0	0		0	0
Net Book Value	1,990	1,368		1,990	1,368
Operating segments \| Liquids Pipelines
Plant, property and equipment
Cost	15,702	14,952		15,702	14,952
Accumulated Depreciation	1,976	1,533		1,976	1,533
Net Book Value	13,726	13,419		13,726	13,419
Operating segments \| Liquids Pipelines \| Keystone Pipeline System
Plant, property and equipment
Cost	14,461	13,794		14,461	13,794
Accumulated Depreciation	1,943	1,529		1,943	1,529
Net Book Value	12,518	12,265		12,518	12,265
Operating segments \| Liquids Pipelines \| Intra-Alberta Pipelines
Plant, property and equipment
Cost	1,241	1,158		1,241	1,158
Accumulated Depreciation	33	4		33	4
Net Book Value	1,208	1,154		1,208	1,154
Operating segments \| Liquids Pipelines \| Pipeline \| Keystone Pipeline System
Plant, property and equipment
Cost	9,780	9,002		9,780	9,002
Accumulated Depreciation	1,271	992		1,271	992
Net Book Value	8,509	8,010		8,509	8,010
Operating segments \| Liquids Pipelines \| Pipeline \| Intra-Alberta Pipelines
Plant, property and equipment
Cost	762	748		762	748
Accumulated Depreciation	22	3		22	3
Net Book Value	740	745		740	745
Operating segments \| Liquids Pipelines \| Pumping equipment \| Keystone Pipeline System
Plant, property and equipment
Cost	1,065	1,022		1,065	1,022
Accumulated Depreciation	184	152		184	152
Net Book Value	881	870		881	870
Operating segments \| Liquids Pipelines \| Pumping equipment \| Intra-Alberta Pipelines
Plant, property and equipment
Cost	104	104		104	104
Accumulated Depreciation	3	0		3	0
Net Book Value	101	104		101	104
Operating segments \| Liquids Pipelines \| Tanks and other \| Keystone Pipeline System
Plant, property and equipment
Cost	3,598	3,314		3,598	3,314
Accumulated Depreciation	488	385		488	385
Net Book Value	3,110	2,929		3,110	2,929
Operating segments \| Liquids Pipelines \| Tanks and other \| Intra-Alberta Pipelines
Plant, property and equipment
Cost	291	259		291	259
Accumulated Depreciation	8	1		8	1
Net Book Value	283	258		283	258
Operating segments \| Liquids Pipelines \| Property, plant and equipment excluding under construction \| Keystone Pipeline System
Plant, property and equipment
Cost	14,443	13,338		14,443	13,338
Accumulated Depreciation	1,943	1,529		1,943	1,529
Net Book Value	12,500	11,809		12,500	11,809
Operating segments \| Liquids Pipelines \| Property, plant and equipment excluding under construction \| Intra-Alberta Pipelines
Plant, property and equipment
Cost	1,157	1,111		1,157	1,111
Accumulated Depreciation	33	4		33	4
Net Book Value	1,124	1,107		1,124	1,107
Operating segments \| Liquids Pipelines \| Under construction \| Keystone Pipeline System
Plant, property and equipment
Cost	18	456		18	456
Accumulated Depreciation	0	0		0	0
Net Book Value	18	456		18	456
Operating segments \| Liquids Pipelines \| Under construction \| Intra-Alberta Pipelines
Plant, property and equipment
Cost	84	47		84	47
Accumulated Depreciation	0	0		0	0
Net Book Value	84	47		84	47
Operating segments \| Energy
Plant, property and equipment
Cost	4,538	5,080		4,538	5,080
Accumulated Depreciation	877	1,103		877	1,103
Net Book Value	3,661	3,977		3,661	3,977
Operating segments \| Energy \| Natural Gas
Plant, property and equipment
Cost	2,062	2,645		2,062	2,645
Accumulated Depreciation	708	743		708	743
Net Book Value	1,354	1,902		1,354	1,902
Operating segments \| Energy \| Wind
Plant, property and equipment
Cost	0	673		0	673
Accumulated Depreciation	0	204		0	204
Net Book Value	0	469		0	469
Operating segments \| Energy \| Natural Gas Storage and Other
Plant, property and equipment
Cost	741	734		741	734
Accumulated Depreciation	169	156		169	156
Net Book Value	572	578		572	578
Operating segments \| Energy \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	2,803	4,052		2,803	4,052
Accumulated Depreciation	877	1,103		877	1,103
Net Book Value	1,926	2,949		1,926	2,949
Operating segments \| Energy \| Under construction
Plant, property and equipment
Cost	1,735	1,028		1,735	1,028
Accumulated Depreciation	0	0		0	0
Net Book Value	1,735	1,028		1,735	1,028
Corporate
Plant, property and equipment
Cost	448	411		448	411
Accumulated Depreciation	210	168		210	168
Net Book Value	$ 238	$ 243		$ 238	$ 243
TC PipeLines, LP
Plant, property and equipment
Noncontrolling interest, ownership interest by parent	25.50%			25.50%

EQUITY INVESTMENTS - Ownership Information of Equity Investments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Aug. 31, 2017	Jun. 02, 2017	Jun. 01, 2017	May 01, 2016	Mar. 31, 2016
Equity Investments
Income/(Loss) from Equity Investments	$ 714	$ 773	$ 514
Equity Investments	7,113	6,366
Iroquois
Equity Investments
Ownership interest percentage									50.00%	49.35%
TransGas
Equity Investments
Ownership interest percentage						46.50%
Grand Rapids
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets	$ 102	105
Canadian Natural Gas Pipelines \| TQM
Equity Investments
Ownership interest percentage	50.00%			50.00%
Income/(Loss) from Equity Investments	$ 12	11	12
Equity Investments	$ 71	68
U.S. Natural Gas Pipelines \| Northern Border
Equity Investments
Ownership interest percentage	50.00%			50.00%
Income/(Loss) from Equity Investments	$ 87	87	92
Equity Investments	$ 677	641
Difference between the carrying value of the investment and the underlying equity in the net assets				$ 115	$ 115
U.S. Natural Gas Pipelines \| Iroquois
Equity Investments
Ownership interest percentage	50.00%			50.00%			0.66%	50.00%
Income/(Loss) from Equity Investments	$ 60	59	54
Equity Investments	$ 291	280
Difference between the carrying value of the investment and the underlying equity in the net assets				$ 41	$ 41
U.S. Natural Gas Pipelines \| Millennium
Equity Investments
Ownership interest percentage	47.50%			47.50%
Income/(Loss) from Equity Investments	$ 75	66	33
Equity Investments	$ 511	291
U.S. Natural Gas Pipelines \| Pennant Midstream
Equity Investments
Ownership interest percentage	47.00%			47.00%
Income/(Loss) from Equity Investments	$ 17	11	6
Equity Investments	256	228
U.S. Natural Gas Pipelines \| Other
Equity Investments
Income/(Loss) from Equity Investments	17	17	29
Equity Investments	$ 113	92
Mexico Natural Gas Pipelines \| Sur de Texas
Equity Investments
Ownership interest percentage	60.00%			60.00%
Income/(Loss) from Equity Investments	$ 27	66	(3)
Equity Investments	627	399
Mexico Natural Gas Pipelines \| TransGas
Equity Investments
Income/(Loss) from Equity Investments	0	(12)	0
Equity Investments	$ 0	0
Liquids Pipelines \| Grand Rapids
Equity Investments
Ownership interest percentage	50.00%			50.00%
Income/(Loss) from Equity Investments	$ 65	17	(1)
Equity Investments	1,028	996
Liquids Pipelines \| Other
Equity Investments
Income/(Loss) from Equity Investments	(1)	(20)	0
Equity Investments	21	20
Liquids Pipelines \| Canaport Energy East Marine Terminal Limited Partnership
Equity Investments
Equity Investments	$ 0	0
Energy \| Bruce Power
Equity Investments
Ownership interest percentage	48.30%			48.30%
Income/(Loss) from Equity Investments	$ 311	434	293
Equity Investments	3,166	2,987
Difference between the carrying value of the investment and the underlying equity in the net assets	$ 870	902
Energy \| Portlands Energy
Equity Investments
Ownership interest percentage	50.00%			50.00%
Income/(Loss) from Equity Investments	$ 36	31	33
Equity Investments	289	301
Difference between the carrying value of the investment and the underlying equity in the net assets	$ 73	73
Energy \| ASTC Power Partnership
Equity Investments
Ownership interest percentage	50.00%			50.00%
Income/(Loss) from Equity Investments	$ 0	0	(37)
Equity Investments	0	0
Energy \| Other
Equity Investments
Income/(Loss) from Equity Investments	8	6	$ 3
Equity Investments	$ 63	$ 63

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income
Revenues	$ 4,836	$ 4,913	$ 4,336
Operating and other expenses	(3,545)	(2,993)	(3,068)
Net income	1,515	1,636	1,080
Income from equity investments	714	773	$ 514
Balance Sheet
Current assets	2,209	2,176
Non-current assets	20,647	17,869
Current liabilities	(2,049)	(1,577)
Non-current liabilities	$ (9,042)	$ (8,217)

EQUITY INVESTMENTS - Narrative (Details) $ in Millions	1 Months Ended		3 Months Ended	12 Months Ended
EQUITY INVESTMENTS - Narrative (Details) $ in Millions	Oct. 31, 2017 CAD ($)	Aug. 31, 2017 CAD ($)	Mar. 31, 2016 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)	Dec. 31, 2018 MXN ($)	Dec. 31, 2017 MXN ($)
Equity Investments
Distributions received from equity investments				$ 1,106	$ 1,332	$ 1,571
Returns of capital				121	362	727
Contributions to equity investments				1,015	1,681	$ 765
Joint Venture \| Revolving credit facility \| Unsecured Loan Facility
Equity Investments
Credit facility, amount								$ 21,300,000,000.0
TransGas
Equity Investments
Asset impairment charges		$ 12
Ownership interest percentage		46.50%
Contract term		20 years
Canaport Energy East Marine Terminal Limited Partnership \| Liquids Pipelines \| Energy East, Eastern Mainline and Upland projects
Equity Investments
Asset impairment charges	$ 20
Sundance B PPA \| Energy
Equity Investments
Asset impairment charges			$ 29
Asset impairment charge, after tax			$ 21
Sur de Texas
Equity Investments
Contributions to equity investments				179	977
Sur de Texas \| Joint Venture
Equity Investments
Loans receivable from affiliates				1,300	900		$ 18,900,000,000	$ 14,400,000,000
Interest income, related party				$ 120	$ 34
Sur de Texas \| Mexico Natural Gas Pipelines
Equity Investments
Ownership interest percentage				60.00%			60.00%

RATE-REGULATED BUSINESSES - Narrative (Details) $ in Millions					1 Months Ended		12 Months Ended
	Dec. 31, 2018 pipeline	Feb. 22, 2018	Feb. 21, 2018	Dec. 31, 2017	Jun. 30, 2018	Mar. 31, 2016 USD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2013 USD ($)
Columbia Gas Transmission
Public Utilities, General Disclosures [Line Items]
Maximum cost recovery and return on investment						$ 1,100,000,000.0		$ 1,500,000,000.0
Cost recovery and return on investment, recognition period								5 years
Cost recovery and return on investment, additional period						3 years
NGTL System
Public Utilities, General Disclosures [Line Items]
Period of settlement					2 years
Approved ROE on deemed common equity, percent					10.10%
Deemed common equity, percent					40.00%
Approved composite depreciation rate					3.50%
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity, percent							10.10%
Deemed common equity, percent							40.00%
Approved composite depreciation rate	3.20%			3.90%
After-tax annual contribution to reduce revenue requirement							$ 20
Fixed toll term							6 years
Great Lakes
Public Utilities, General Disclosures [Line Items]
Maximum transportation rate decrease		27.00%	2.00%
TC Pipe Lines LP
Public Utilities, General Disclosures [Line Items]
Noncontrolling interest, ownership interest by parent	25.50%
TC Pipe Lines LP
Public Utilities, General Disclosures [Line Items]
Number of wholly-owned or partially owned pipelines \| pipeline	8

RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) $ in Millions, $ in Millions				12 Months Ended			115 Months Ended
	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2006 CAD ($)	Dec. 31, 2006 USD ($)	Jul. 31, 2016 USD ($)
Regulatory Assets
Regulatory Assets	$ 1,631		$ 1,399	$ 1,631
Less: Current portion included in Other current assets (Note 7)	83		23	83
Regulatory Assets, noncurrent	1,548		1,376	1,548
Regulatory Liabilities
Regulatory Liabilities	4,521		4,584	4,521
Less: Current portion included in Accounts payable and other (Note 14)	591		263	591
Regulatory Liabilities, noncurrent	3,930		4,321	3,930
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Regulatory Liabilities	96		188	$ 96
Remaining Recovery/ Settlement Period (years)				1 year
Pensions and other post retirement benefits \| ANR PIPELINE COMPANY
Regulatory Liabilities
Regulatory Liabilities	54		66	$ 54
Long term adjustment account
Regulatory Liabilities
Regulatory Liabilities	1,015		1,142	$ 1,015
Long term adjustment account \| Minimum
Regulatory Liabilities
Remaining Recovery/ Settlement Period (years)				2 years
Long term adjustment account \| Maximum
Regulatory Liabilities
Remaining Recovery/ Settlement Period (years)				45 years
Bridging amortization account
Regulatory Liabilities
Regulatory Liabilities	305		202	$ 305
Remaining Recovery/ Settlement Period (years)				12 years
Pipeline abandonment trust balance
Regulatory Liabilities
Regulatory Liabilities	1,113		825	$ 1,113
Cost of removal
Regulatory Liabilities
Regulatory Liabilities	261		216	261
Deferred income taxes
Regulatory Liabilities
Regulatory Liabilities	165		75	165
U.S. Tax Reform
Regulatory Liabilities
Regulatory Liabilities	1,394		1,659	1,394
Other
Regulatory Liabilities
Regulatory Liabilities	65		47	65
Postretirement benefit costs \| ANR PIPELINE COMPANY
Other disclosures pertaining to regulated assets and liabilities
Regulatory liability settlement	11	$ 8	26				$ 21
Amount to be addressed In next settlement					$ 43	$ 32
Long term adjustment account, amount to be amortized over two years
Regulatory Liabilities
Regulatory Liabilities	932			932
Deferred income taxes
Regulatory Assets
Regulatory Assets	1,051		940	1,051
Operating and debt-service regulatory assets
Regulatory Assets
Regulatory Assets	12			$ 12
Remaining Recovery/ Settlement Period (years)				1 year
Pensions and other post retirement benefits
Regulatory Assets
Regulatory Assets	379		388	$ 379
Regulatory Liabilities
Regulatory Liabilities	53		164	53
Foreign exchange on long-term debt
Regulatory Assets
Regulatory Assets	46			$ 46
Foreign exchange on long-term debt \| Minimum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)				1 year
Foreign exchange on long-term debt \| Maximum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)				11 years
Other
Regulatory Assets
Regulatory Assets	$ 143		$ 71	$ 143

GOODWILL (Details) $ in Millions, $ in Millions	3 Months Ended		12 Months Ended
GOODWILL (Details) $ in Millions, $ in Millions	Jun. 30, 2017 CAD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2017 USD ($)
Goodwill
Balance at the beginning of the period			$ 13,084
Balance at the end of the period			14,178	$ 13,084
U.S. Natural Gas Pipelines
Goodwill
Balance at the beginning of the period			13,084	13,958
Tuscarora impairment charge			(79)
Foreign exchange rate changes			1,173	(945)
Balance at the end of the period			$ 14,178	13,084
Columbian Pipeline
Goodwill
Balance at the beginning of the period					$ 7,747
Columbia adjustment (Note 26)	$ 71	$ 55
Balance at the end of the period					$ 7,802
Columbian Pipeline \| U.S. Natural Gas Pipelines
Goodwill
Columbia adjustment (Note 26)				$ 71

GOODWILL - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
GOODWILL - Narrative (Details) $ in Millions, $ in Millions	Dec. 31, 2018 CAD ($)	Dec. 31, 2016 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2017 USD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 14,178			$ 13,084
Tuscarora
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill impairment charge	79
Goodwill impairment charge, net of tax and noncontrolling interest	$ 15
Goodwill			$ 23		$ 82
Great Lakes
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill			$ 573		$ 573
Percentage of fair value in excess of carrying amount (less than)	10.00%		10.00%
Ravenswood
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill impairment charge		$ 1,085
Goodwill impairment charge, net of tax		$ 656

INTANGIBLE AND OTHER ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Capital projects in development	$ 1,051	$ 596
Deferred income tax assets (Note 16)	322	316
Employee post-retirement benefits (Note 23)	192	193
Fair value of derivative contracts (Note 24)	61	73
Other	295	306
Intangible and other assets	$ 1,921	$ 1,484

INTANGIBLE AND OTHER ASSETS - Narrative (Details) - CAD ($) $ in Millions		1 Months Ended			12 Months Ended
	Oct. 05, 2017	Nov. 30, 2018	Oct. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
Capital projects in development					$ 1,051	$ 596
Reimbursement of costs related to capital projects in development					470	634	$ 0
Asset impairment charges					801	1,257	$ 1,388
Sundance A (expires 2017) \| Energy
Finite-Lived Intangible Assets [Line Items]
Asset impairment charges				$ 92		211
Asset impairment charge, after tax				$ 68		155
Keystone XL
Finite-Lived Intangible Assets [Line Items]
Capital projects in development					$ 800	$ 0
Coastal GasLink pipeline project
Finite-Lived Intangible Assets [Line Items]
Reimbursement of costs related to capital projects in development		$ 470
Pacific Northwest LNG project
Finite-Lived Intangible Assets [Line Items]
Reimbursement of costs related to capital projects in development			$ 634
Energy East, Eastern Mainline and Upland projects
Finite-Lived Intangible Assets [Line Items]
Asset impairment charges	$ 1,153
Asset impairment charge, after tax	$ 870

NOTES PAYABLE (Details)	12 Months Ended
NOTES PAYABLE (Details)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)	Dec. 31, 2018 MXN ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 MXN ($)	Dec. 31, 2017 USD ($)
Notes payable
Outstanding	$ 2,762,000,000	$ 1,763,000,000
Operated affiliates
Notes payable
Unused Capacity	800,000,000	400,000,000
Revolving credit facility
Notes payable
Cost to maintain	12,000,000	7,000,000	$ 10,000,000
Revolving and demand credit facilities
Notes payable
Total Facilities	12,900,000,000.0	11,000,000,000.0
TCPL \| Revolving credit facility
Notes payable
Total Facilities							$ 2,000,000,000
TCPL \| Revolving credit facility \| Maturing December 2023
Notes payable
Total Facilities	3,000,000,000	3,000,000,000
Unused Capacity	3,000,000,000
TCPL \| Notes payable
Notes payable
Outstanding	$ 2,117,000,000	$ 884,000,000
Weighted average interest rate per annum	2.50%	1.60%		2.50%	2.50%	1.60%	1.60%
TCPL USA and TAIL \| Notes payable
Notes payable
Outstanding	$ 611,000,000	$ 862,000,000			$ 448,000,000		$ 688,000,000
Weighted average interest rate per annum	3.10%	2.20%		3.10%	3.10%	2.20%	2.20%
Mexico subsidiary \| Revolving credit facility
Notes payable
Total Facilities				$ 5,000,000,000.0		$ 5,000,000,000.0
Unused Capacity				$ 4,500,000,000
Mexico subsidiary \| Notes payable
Notes payable
Outstanding	$ 34,000,000	$ 17,000,000			$ 25,000,000	$ 275,000,000
Weighted average interest rate per annum	3.30%	8.00%		3.30%	3.30%	8.00%	8.00%
TCPL/TCPL USA/Columbia/TAIL \| Revolving credit facility \| Maturing December 2019
Notes payable
Total Facilities					$ 4,500,000,000.0		$ 0
Unused Capacity					4,500,000,000
TCPL/TCPL USA/Columbia/TAIL \| Revolving credit facility \| Maturing December 2021
Notes payable
Total Facilities					1,000,000,000		0
Unused Capacity					$ 1,000,000,000
TCPL USA \| Revolving credit facility
Notes payable
Total Facilities							1,000,000,000
Columbia \| Revolving credit facility
Notes payable
Total Facilities							1,000,000,000
TAIL \| Revolving credit facility
Notes payable
Total Facilities							$ 500,000,000.0
TCPL/TCPL USA \| Revolving credit facility
Notes payable
Total Facilities	$ 2,100,000,000.0	$ 1,900,000,000.0
Unused Capacity	$ 1,000,000,000

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Payables and Accruals [Abstract]
Trade payables	$ 3,224		$ 2,847
Fair value of derivative contracts (Note 24)	922		387
Unredeemed shares of Columbia	357		312
Regulatory liabilities (Note 10)	591		263
Other	314		248
Accounts payable and other	$ 5,408	$ 4,074	$ 4,057

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred Costs, Noncurrent [Abstract]
Employee post-retirement benefits (Note 23)	$ 569	$ 389
Asset retirement obligations	90	98
Fair value of derivative contracts (Note 24)	42	72
Guarantees (Note 27)	12	16
Other	295	152
Other long-term liabilities	$ 1,008	$ 727

INCOME TAXES - U.S. Tax Reform (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Income Tax Contingency [Line Items]
Provisional deferred income tax recovery			$ 816
Increase in regulatory liabilities for businesses subject to RRA			1,686
Additional deferred income tax recovery	$ 52
Additional deferred income tax recovery for businesses subject to RRA	115
U.S. Tax Reform
Income Tax Contingency [Line Items]
Amortization of regulatory liability		$ 58
Net regulatory liability	$ 1,394	$ 1,394	1,686
Other Post-Retirement Benefit Plans
Income Tax Contingency [Line Items]
Provisional deferred income tax recovery			$ 12

INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	12 Months Ended
INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current
Canada	$ 65	$ 113	$ 116
Foreign	250	36	40
Total	315	149	156
Deferred
Canada	49	(185)	101
Foreign	235	751	95
Deferred – U.S. Tax Reform and 2018 FERC Actions	(167)	(804)	0
Total	117	(238)	196
Income Tax (Recovery)/Expense	$ 432	$ (89)	$ 352

INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Canada	$ 433	$ (339)	$ 219
Foreign	3,516	3,645	618
Income before Income Taxes	$ 3,949	$ 3,306	$ 837

INCOME TAXES - Reconciliation of Income Tax (Recovery)/Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income before income taxes	$ 3,949	$ 3,306	$ 837
Federal and provincial statutory tax rate	27.00%	27.00%	27.00%
Expected income tax expense	$ 1,066	$ 893	$ 226
U.S. Tax Reform and 2018 FERC Actions	(167)	(804)	0
Foreign income tax rate differentials	(432)	(81)	(196)
Loss/(income) from equity investments and non-controlling interests	50	(64)	(68)
Income tax differential related to regulated operations	(54)	(42)	81
Non-taxable portion of capital gains	(11)	(42)	0
Asset impairment charges	0	34	242
Non-deductible amounts	0	4	46
Other	(20)	13	21
Income Tax (Recovery)/Expense	432	(89)	352
Foreign tax rate differential related to asset impairments, amount	$ 0	$ 0	$ 112

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred Income Tax Assets
Tax loss and credit carryforwards	$ 1,238	$ 1,379
Difference in accounting and tax bases of impaired assets and assets held for sale	574	651
Regulatory and other deferred amounts	858	512
Unrealized foreign exchange losses on long-term debt	491	216
Financial instruments		10
Other	292	227
Deferred tax assets, gross	3,453	2,995
Less: Valuation allowance	1,159	832
Deferred tax assets, net of Valuation allowance	2,294	2,163
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,449	6,240
Equity investments	1,069	632
Taxes on future revenue requirement	300	238
Other	180	140
Deferred tax liabilities, gross	7,998	7,250
Net Deferred Income Tax Liabilities	5,704	5,087
Deferred Income Tax Assets
Intangible and other assets (Note 12)	322	316
Deferred Income Tax Liabilities
Deferred income tax liabilities	6,026	5,403
Net Deferred Income Tax Liabilities	$ 5,704	$ 5,087

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefit at beginning of year	$ 15	$ 18	$ 17
Gross increases – tax positions in prior years	13	0	3
Gross decreases – tax positions in prior years	(5)	(1)	0
Gross increases – tax positions in current year	0	2	2
Settlement	0	0	(1)
Lapse of statutes of limitations	(4)	(4)	(3)
Unrecognized Tax Benefit at End of Year	$ 19	$ 15	$ 18

INCOME TAXES - Additional Narrative (Details) $ in Millions	12 Months Ended
INCOME TAXES - Additional Narrative (Details) $ in Millions	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Net operating loss carryforwards
Tax loss and credit carryforwards	$ 1,238,000,000	$ 1,379,000,000
Deferred income tax liabilities on the unremitted earnings of foreign investments	619,000,000	569,000,000
Income tax payments, net of refunds	338,000,000	247,000,000	$ 105,000,000
Interest expense (recovery) reflected within net tax expense	(1,000,000)	0	0
Income tax penalties expense	0	0	$ 0
Accrued interest expense	3,000,000	4,000,000
Income tax penalties accrued	0	0
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards	1,867,000,000	1,280,000,000
Capital loss carryforwards	0
Capital loss carryforwards unrecognized	821,000,000	668,000,000
Canada federal and provincial \| Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits	91,000,000	82,000,000
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards				$ 889	$ 1,800
Tax loss and credit carryforwards	$ 0	$ 0
Operating loss carryforward unrecognized				706	710
U.S. federal \| Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits				1	56
Mexican Tax Authority
Net operating loss carryforwards
Tax loss and credit carryforwards				$ 3	$ 7

LONG-TERM DEBT - Amounts Outstanding and Principal Repayments (Details) $ in Millions, $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2017 CAD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)
Debt Instrument [Line Items]
Outstanding			$ 39,982	$ 34,677
Current portion of long-term debt			(3,462)	(2,866)
Unamortized debt discount and issue costs			(241)	(174)
Fair value adjustments			230	238
Long-term debt, excluding current maturities			36,509	31,875
Decrease in fair value of interest rate hedge			2	4
Repayments of Long-term Debt [Abstract]
2019			3,465
2020			2,834
2021			2,098
2022			2,100
2023			1,930
Columbian Pipeline
Debt Instrument [Line Items]
Increase (decrease) in fair value of acquired liabilities, long-term debt	$ 300	$ 231	232	242
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding			31,856	26,149
TRANSCANADA PIPELINES LIMITED \| Debentures, Maturity Dates Between 2019 and 2020
Debt Instrument [Line Items]
Outstanding			$ 350	$ 500
Interest Rate			11.40%	10.80%	11.40%	10.80%
TRANSCANADA PIPELINES LIMITED \| Debentures, Maturity Date of 2021
Debt Instrument [Line Items]
Outstanding			$ 546	$ 501	$ 400	$ 400
Interest Rate			9.90%	9.90%	9.90%	9.90%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes
Debt Instrument [Line Items]
Outstanding			$ 7,504	$ 6,504
Interest Rate			4.80%	4.90%	4.80%	4.90%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding			$ 23,456	$ 18,644	$ 17,192	$ 14,892
Interest Rate			5.10%	5.10%	5.10%	5.10%
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding			$ 921	$ 895
NOVA GAS TRANSMISSION LTD. \| Debentures and Notes, Maturity Date of 2024
Debt Instrument [Line Items]
Outstanding			$ 100	$ 100
Interest Rate			9.90%	9.90%	9.90%	9.90%
NOVA GAS TRANSMISSION LTD. \| Debentures and Notes, Maturity Date of 2023
Debt Instrument [Line Items]
Outstanding			$ 273	$ 250	$ 200	$ 200
Interest Rate			7.90%	7.90%	7.90%	7.90%
NOVA GAS TRANSMISSION LTD. \| Medium-Term Notes, Maturity between 2025 and 2030
Debt Instrument [Line Items]
Outstanding			$ 504	$ 504
Interest Rate			7.40%	7.40%	7.40%	7.40%
NOVA GAS TRANSMISSION LTD. \| Medium-Term Notes, Maturity Date of 2026
Debt Instrument [Line Items]
Outstanding			$ 44	$ 41	$ 33	$ 33
Interest Rate			7.50%	7.50%	7.50%	7.50%
Columbian Pipeline \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding			$ 3,070	$ 3,443	$ 2,250	$ 2,750
Interest Rate			4.40%	4.00%	4.40%	4.00%
TC PIPELINES, LP
Debt Instrument [Line Items]
Outstanding			$ 2,374	$ 2,573
TC PIPELINES, LP \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding			$ 1,637	$ 1,502	$ 1,200	$ 1,200
Interest Rate			4.40%	4.40%	4.40%	4.40%
TC PIPELINES, LP \| Unsecured Loan Facility
Debt Instrument [Line Items]
Outstanding			$ 55	$ 232	$ 40	$ 185
Interest Rate			3.80%	2.70%	3.80%	2.70%
TC PIPELINES, LP \| Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding			$ 682	$ 839	$ 500	$ 670
Interest Rate			3.60%	2.70%	3.60%	2.70%
TC PIPELINES, LP \| Unsecured Term Loan Maturing October 2022
Debt Instrument [Line Items]
Outstanding							$ 500
ANR PIPELINE COMPANY \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding			$ 918	$ 842	$ 672	$ 672
Interest Rate			7.20%	7.20%	7.20%	7.20%
GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Outstanding			$ 389	$ 382
GAS TRANSMISSION NORTHWEST LLC \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding			$ 341	$ 313	$ 250	$ 250
Interest Rate			5.60%	5.60%	5.60%	5.60%
GAS TRANSMISSION NORTHWEST LLC \| Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding			$ 48	$ 69	$ 35	$ 55
Interest Rate			3.30%	1.10%	3.30%	1.10%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding			$ 327	$ 324	$ 240	$ 259
Interest Rate			7.70%	7.70%	7.70%	7.70%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Debt Instrument [Line Items]
Outstanding			$ 26	$ 38
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Unsecured Loan Facility
Debt Instrument [Line Items]
Outstanding			$ 26		$ 19	$ 0
Interest Rate			3.60%	0.00%	3.60%	0.00%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Senior Secured Notes
Debt Instrument [Line Items]
Outstanding			$ 0	$ 38	$ 0	$ 30
Interest Rate			0.00%	6.00%	0.00%	6.00%
TUSCARORA GAS TRANSMISSION COMPANY \| Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding			$ 33	$ 31	$ 24	$ 25
Interest Rate			3.50%	1.10%	3.50%	1.10%
NORTH BAJA PIPELINE, LLC \| Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding			$ 68		$ 50	$ 0
Interest Rate			3.50%	0.00%	3.50%	0.00%

LONG-TERM DEBT - Issued (Details) $ in Millions, $ in Millions	1 Months Ended
	Dec. 31, 2018 USD ($)	Oct. 31, 2018 USD ($)	Jul. 31, 2018 CAD ($)	May 31, 2018 USD ($)	Apr. 30, 2018 USD ($)	Nov. 30, 2017 USD ($)	Sep. 30, 2017 CAD ($)	Aug. 31, 2017 USD ($)	May 31, 2017 USD ($)	Nov. 30, 2016 USD ($)	Jun. 30, 2016 CAD ($)	Jun. 30, 2016 USD ($)	Apr. 30, 2016 USD ($)	Jan. 31, 2016 USD ($)
Acquisition Bridge Facility
Debt Instrument [Line Items]
Amount										$ 6,900
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due March 2049
Debt Instrument [Line Items]
Amount		$ 1,000
Interest Rate		5.10%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due May 2028
Debt Instrument [Line Items]
Amount		$ 400		$ 1,000
Interest Rate		4.25%		4.25%
Long-term debt, re-issuance yield, percent		4.439%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due July 2048
Debt Instrument [Line Items]
Amount			$ 800
Interest Rate			4.18%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due March 2028
Debt Instrument [Line Items]
Amount			$ 200
Interest Rate			3.39%
Long-term debt, re-issuance yield, percent			3.41%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due May 2048
Debt Instrument [Line Items]
Amount				$ 1,000
Interest Rate				4.875%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due May 2038
Debt Instrument [Line Items]
Amount				$ 500
Interest Rate				4.75%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due November 2019, floating interest rate
Debt Instrument [Line Items]
Amount						$ 550
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due November 2019, fixed interest rate
Debt Instrument [Line Items]
Amount						$ 700
Interest Rate						2.125%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due March 2028
Debt Instrument [Line Items]
Amount							$ 300
Interest Rate							3.39%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due September 2047
Debt Instrument [Line Items]
Amount							$ 700
Interest Rate							4.33%
TRANSCANADA PIPELINES LIMITED \| Acquisition Bridge Facility
Debt Instrument [Line Items]
Amount												$ 5,213
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due July 2023
Debt Instrument [Line Items]
Amount											$ 300
Interest Rate											3.69%	3.69%
Long-term debt, re-issuance yield, percent											2.69%	2.69%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due June 2046
Debt Instrument [Line Items]
Amount											$ 700
Interest Rate											4.35%	4.35%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due January 2026
Debt Instrument [Line Items]
Amount														$ 850
Interest Rate														4.875%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due January 2019
Debt Instrument [Line Items]
Amount														$ 400
Interest Rate														3.125%
NORTH BAJA PIPELINE, LLC \| Unsecured Term Loan due December 2021
Debt Instrument [Line Items]
Amount	$ 50
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Unsecured Loan Facility due April 2023
Debt Instrument [Line Items]
Amount					$ 19
TUSCARORA GAS TRANSMISSION COMPANY \| Unsecured Term Loan due August 2020
Debt Instrument [Line Items]
Amount								$ 25
TUSCARORA GAS TRANSMISSION COMPANY \| Unsecured Term Loan due April 2019
Debt Instrument [Line Items]
Amount													$ 10
TC PIPELINES, LP \| Senior Unsecured Notes due May 2027
Debt Instrument [Line Items]
Amount									$ 500
Interest Rate									3.90%
TRANSCANADA PIPELINE USA LTD. \| Acquisition Bridge Facility
Debt Instrument [Line Items]
Amount												$ 1,700
ANR PIPELINE COMPANY \| Senior Unsecured Notes Due June 2026
Debt Instrument [Line Items]
Amount												$ 240
Interest Rate											4.14%	4.14%

LONG-TERM DEBT - Retired (Details) $ in Millions, $ in Millions	1 Months Ended
	Dec. 31, 2018 USD ($)	Aug. 31, 2018 USD ($)	Jun. 30, 2018 USD ($)	May 31, 2018 USD ($)	Mar. 31, 2018 CAD ($)	Mar. 31, 2018 USD ($)	Jan. 31, 2018 USD ($)	Dec. 31, 2017 CAD ($)	Nov. 30, 2017 USD ($)	Aug. 31, 2017 USD ($)	Jun. 30, 2017 USD ($)	Apr. 30, 2017 USD ($)	Feb. 28, 2017 USD ($)	Jan. 31, 2017 CAD ($)	Nov. 30, 2016 USD ($)	Oct. 31, 2016 CAD ($)	Jun. 30, 2016 USD ($)	Feb. 29, 2016 CAD ($)	Jan. 31, 2016 USD ($)
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due August 2018
Debt Instrument [Line Items]
Amount		$ 850
Interest Rate		6.50%
TRANSCANADA PIPELINES LIMITED \| Debentures due March 2018
Debt Instrument [Line Items]
Amount					$ 150
Interest Rate					9.45%	9.45%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due January 2018, fixed interest rate
Debt Instrument [Line Items]
Amount							$ 500
Interest Rate							1.875%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due January 2018, floating interest rate
Debt Instrument [Line Items]
Amount							$ 250
TRANSCANADA PIPELINES LIMITED \| Debentures due December 2017
Debt Instrument [Line Items]
Amount								$ 100
Interest Rate								9.80%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due November 2017
Debt Instrument [Line Items]
Amount									$ 1,000
Interest Rate									1.625%
TRANSCANADA PIPELINES LIMITED \| Acquisition Bridge Facility
Debt Instrument [Line Items]
Amount											$ 1,513		$ 500		$ 3,200
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due January 2017
Debt Instrument [Line Items]
Amount														$ 300
Interest Rate														5.10%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due October 2016
Debt Instrument [Line Items]
Amount																$ 400
Interest Rate																4.65%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due June 2016, fixed interest rate
Debt Instrument [Line Items]
Amount																	$ 84
Interest Rate																	7.69%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due June 2016, floating interest rate
Debt Instrument [Line Items]
Amount																	$ 500
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due January 2016
Debt Instrument [Line Items]
Amount																			$ 750
Interest Rate																			0.75%
TC PIPELINES, LP \| Unsecured Term Loan due December 2018
Debt Instrument [Line Items]
Amount	$ 170
COLUMBIA PIPELINE GROUP, INC. \| Senior Unsecured Notes due June 2018
Debt Instrument [Line Items]
Amount			$ 500
Interest Rate			2.45%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Senior Secured Notes due May 2018
Debt Instrument [Line Items]
Amount				$ 18
Interest Rate				5.90%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP \| Senior Unsecured Notes due March 2018
Debt Instrument [Line Items]
Amount						$ 9
Interest Rate					6.73%	6.73%
TUSCARORA GAS TRANSMISSION COMPANY \| Senior Secured Notes due August 2017
Debt Instrument [Line Items]
Amount										$ 12
Interest Rate										3.82%
TRANSCANADA PIPELINE USA LTD. \| Acquisition Bridge Facility
Debt Instrument [Line Items]
Amount											$ 630	$ 1,070
NOVA GAS TRANSMISSION LTD. \| Debentures due February 2016
Debt Instrument [Line Items]
Amount																		$ 225
Interest Rate																		12.20%

LONG-TERM DEBT - Interest Expense and Payments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Interest Expense [Abstract]
Capitalized interest	$ (124)	$ (173)	$ (176)
Amortization and other financial charges	48	67	211
Interest expense	2,265	2,069	1,998
Interest payments, net of interest capitalized	2,156	1,987	1,721
Interest Expense
Interest Expense [Abstract]
Dividend equivalent payments recorded as interest expense		109	109
Short-term debt
Interest Expense [Abstract]
Interest on debt	73	33	18
Long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest on debt	1,877	1,794	1,765
Junior subordinated notes
Interest Expense [Abstract]
Interest on debt	$ 391	$ 348	$ 180

JUNIOR SUBORDINATED NOTES (Details)	1 Months Ended			3 Months Ended	12 Months Ended
JUNIOR SUBORDINATED NOTES (Details)	May 31, 2017 USD ($)	Mar. 31, 2017 USD ($)	Aug. 31, 2016 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2017 USD ($)	May 31, 2017 CAD ($)
Debt Instrument [Line Items]
Outstanding					$ 39,982,000,000		$ 34,677,000,000
Unamortized debt discount and issue costs					(241,000,000)		(174,000,000)
Long-term Debt						$ 750,000,000		$ 1,100,000,000
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding					31,856,000,000		26,149,000,000
TRANSCANADA PIPELINES LIMITED \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					7,572,000,000		7,071,000,000
Unamortized debt discount and issue costs					(64,000,000)		(64,000,000)
Long-term Debt					7,508,000,000		7,007,000,000
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2067 \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 1,364,000,000		$ 1,252,000,000
Effective Interest Rate					5.60%	5.60%	5.00%	5.00%
Debt instrument, face amount						$ 1,000,000,000
Stated interest rate					6.35%	6.35%			6.35%
Stated interest rate, period of time					10 years
Debt converted	$ 1,000,000,000
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2067 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Basis points (percent)	2.21%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2075 \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 1,024,000,000		$ 939,000,000
Effective Interest Rate					6.50%	6.50%	5.90%	5.90%
Debt instrument, face amount						$ 750,000,000
Stated interest rate					5.875%	5.875%
Stated interest rate, period of time					10 years
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2076 \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 1,637,000,000		$ 1,502,000,000
Effective Interest Rate					7.20%	7.20%	6.60%	6.60%
Debt instrument, face amount						$ 1,200,000,000
Stated interest rate					6.125%	6.125%
Stated interest rate, period of time					10 years
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2077 \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 2,047,000,000		$ 1,878,000,000
Effective Interest Rate					6.20%	6.20%	5.60%	5.60%
Debt instrument, face amount						$ 1,500,000,000
Stated interest rate					5.55%	5.55%
Stated interest rate, period of time					10 years
TRANSCANADA PIPELINES LIMITED \| Canadian junior subordinated debt, due 2077 \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 1,500,000,000		$ 1,500,000,000
Effective Interest Rate					5.50%	5.50%	5.10%	5.10%
Debt instrument, face amount					$ 1,500,000,000
Stated interest rate					4.90%	4.90%
Stated interest rate, period of time					10 years
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2017-A \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,500,000,000.0		$ 1,500,000,000.0
Stated interest rate		5.55%		5.55%
Administrative charge percentage		0.25%		0.25%
Redemption price as a percentage of principal amount plus accrued and unpaid interest		100.00%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2017-A \| March 2027 until March 2047 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Basis points (percent)		3.458%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2017-A \| March 2047 until March 2077 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Basis points (percent)		4.208%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2017-B \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount									$ 1,500,000,000.0
Stated interest rate									4.90%
Administrative charge percentage									0.25%
Redemption price as a percentage of principal amount plus accrued and unpaid interest	100.00%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2017-B \| May 2027 until May 2047 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Basis points (percent)	3.33%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2017-B \| May 2047 to May 2077 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Basis points (percent)	4.08%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2016-A \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount			$ 1,200,000,000.0
Stated interest rate			6.125%
Administrative charge percentage			0.25%
Redemption price as a percentage of principal amount plus accrued and unpaid interest			100.00%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2016-A \| August 2026 until August 2046 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Basis points (percent)			4.89%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2016-A \| August 2046 to August 2076 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Basis points (percent)			5.64%
TransCanada Trust \| Trust Notes - Series 2017-A \| Notes payable
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,500,000,000.0		$ 1,500,000,000.0
Stated interest rate, period of time				10 years
TransCanada Trust \| Trust Notes - Series 2017-A \| First Ten Years \| Notes payable
Debt Instrument [Line Items]
Stated interest rate		5.30%		5.30%
TransCanada Trust \| Trust Notes - Series 2017-B \| Notes payable
Debt Instrument [Line Items]
Debt instrument, face amount									$ 1,500,000,000.0
Stated interest rate, period of time	10 years
TransCanada Trust \| Trust Notes - Series 2017-B \| First Ten Years \| Notes payable
Debt Instrument [Line Items]
Stated interest rate									4.65%
TransCanada Trust \| Trust Notes - Series 2016-A \| Notes payable
Debt Instrument [Line Items]
Debt instrument, face amount			$ 1,200,000,000.0
Stated interest rate, period of time			10 years
TransCanada Trust \| Trust Notes - Series 2016-A \| First Ten Years \| Notes payable
Debt Instrument [Line Items]
Stated interest rate			5.875%

NON-CONTROLLING INTERESTS (Details) - CAD ($) $ in Millions	12 Months Ended
NON-CONTROLLING INTERESTS (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest in TC PipeLines, LP	$ 1,655	$ 1,852
Non-controlling interests included in the Consolidated Statement of Income
Net (loss)/income attributable to non-controlling interests	(185)	238	$ 252
Noncontrolling Interest
Non-controlling interests included in the Consolidated Statement of Income
Net (loss)/income attributable to non-controlling interests	185	(238)	(252)
TC PipeLines, LP \| Noncontrolling Interest
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest in TC PipeLines, LP	1,655	1,852
Non-controlling interests included in the Consolidated Statement of Income
Net (loss)/income attributable to non-controlling interests	(185)	220	215
Portland Natural Gas Transmission System \| Noncontrolling Interest
Non-controlling interests included in the Consolidated Statement of Income
Net (loss)/income attributable to non-controlling interests	0	9	20
Columbia Pipeline Partners LP \| Noncontrolling Interest
Non-controlling interests included in the Consolidated Statement of Income
Net (loss)/income attributable to non-controlling interests	$ 0	$ 9	$ 17

NON-CONTROLLING INTERESTS - Narrative (Details) $ / shares in Units, shares in Millions, $ in Millions, $ in Millions				2 Months Ended	12 Months Ended
	Jun. 01, 2017	Feb. 17, 2017 USD ($) $ / shares	Jan. 01, 2016	May 19, 2016 shares	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)	Dec. 31, 2016 USD ($)	Jul. 01, 2016
Noncontrolling Interest
Non-controlling interests
Aggregate transaction value \| $					$ 9	$ 41	$ 40
TC Pipe Lines LP
Non-controlling interests
Common units outstanding, subject to rescission, amount							$ 106	$ 82
Reclassification to Common Units of CPPL, subject to redemption (in shares) \| shares				1.6
Expiration period from the date of purchase				1 year
TC Pipe Lines LP \| Noncontrolling Interest
Non-controlling interests
Percentage of non-controlling interests					74.50%	74.30%
TC Pipe Lines LP \| Noncontrolling Interest \| Minimum
Non-controlling interests
Percentage of non-controlling interests						73.20%	72.00%	72.00%
TC Pipe Lines LP \| Noncontrolling Interest \| Maximum
Non-controlling interests
Percentage of non-controlling interests						74.30%	73.20%	73.20%
Portland Natural Gas Transmission System \| Noncontrolling Interest
Non-controlling interests
Percentage of non-controlling interests						0.00%
Ownership interest before transaction, percent	11.81%		49.90%
Columbia Pipeline Partners LP
Non-controlling interests
Common units outstanding, subject to rescission, amount							$ 1,073	$ 799
Columbia Pipeline Partners LP \| Noncontrolling Interest
Non-controlling interests
Percentage of non-controlling interests									53.50%
Share price (in dollars per share) \| $ / shares		$ 17.00
Stub period distribution payments acquired (in dollars per share) \| $ / shares		$ 0.10
Aggregate transaction value \| $		$ 921

COMMON SHARES - Reconciliation and Weighted Average Common Shares Outstanding (Details) - CAD ($) $ in Millions	1 Months Ended		12 Months Ended
	Nov. 30, 2016	Jan. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)			881,000,000
Outstanding at the beginning of the period			$ 21,167
Issued under public offerings (in shares)	60,200,000
Exercise of options (in shares)			734,000
Repurchase of shares (in shares)		(305,407)
Repurchase of shares		$ (14)
Outstanding at the end of the period (in shares)			918,000,000	881,000,000
Outstanding at the end of the period			$ 23,174	$ 21,167
Weighted Average Common Shares Outstanding
Basic (in shares)			902,000,000	872,000,000	759,000,000
Diluted (in shares)			903,000,000	874,000,000	760,000,000
Common Shares
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)		702,614,000	881,376,000	863,759,000	702,614,000
Outstanding at the beginning of the period		$ 12,102	$ 21,167	$ 20,099	$ 12,102
Issued under public offerings (in shares)					156,825,000
Issued under public offerings					$ 7,752
Dividend reinvestment and share purchase plan (in shares)			15,937,000	12,824,000	2,942,000
Dividend reinvestment and share purchase plan			$ 855	$ 790	$ 177
At-the-market equity issuance program (in shares)			20,050,000	3,462,000
At-the-market equity issuance program			$ 1,118	$ 216
Exercise of options (in shares)			734,000	1,331,000	1,683,000
Exercise of options			$ 34	$ 62	$ 74
Repurchase of shares (in shares)					(305,000)
Repurchase of shares		$ (6)			$ (6)
Outstanding at the end of the period (in shares)			918,097,000	881,376,000	863,759,000
Outstanding at the end of the period			$ 23,174	$ 21,167	$ 20,099
Weighted Average Common Shares Outstanding
Basic (in shares)			902,000,000	872,000,000	759,000,000
Diluted (in shares)			903,000,000	874,000,000	760,000,000

COMMON SHARES - Dividend Reinvestment and Share Purchase Plan (Details)	Jul. 01, 2016
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Discount of shares issued from treasury (percent)	2.00%

COMMON SHARES - TransCanada Corporation At-the-Market Equity Issuance Program (Details) - CAD ($) $ / shares in Units, shares in Millions		1 Months Ended		12 Months Ended
	Dec. 31, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2018	Nov. 30, 2016
Subsidiary, Sale of Stock [Line Items]
Price per share (in Canadian dollars per share)					$ 58.50
At-the-Market Equity Issuance Program
Subsidiary, Sale of Stock [Line Items]
Stock issuance program, period in effect (in months)			25 months
Authorized amount		$ 2,000,000,000	$ 1,000,000,000.0
Treasury stock reissued during period (in shares)	3.5			20.0
Price per share (in Canadian dollars per share)	$ 63.03			$ 56.13
Consideration received on transaction	$ 216,000,000			$ 1,100,000,000
Payments of stock issuance costs	$ 2,000,000			$ 10,000,000
Additional authorized amount		$ 1,000,000,000

COMMON SHARES - Common Share Public Offering and Subscription Receipts (Details) $ / shares in Units, $ in Millions, $ in Billions	1 Months Ended			12 Months Ended
	Nov. 30, 2016 CAD ($) $ / shares shares	Nov. 30, 2016 USD ($) shares	Apr. 30, 2016 CAD ($) $ / shares shares	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)
Class of Stock [Line Items]
Subscription receipt (in shares) \| shares			96,600,000
Share price (in CAD per share) \| $ / shares			$ 45.75
Common stock, value, subscriptions			$ 4,400
Common stock subscriptions, number of common shares issuable per subscription (in shares) \| shares			1
Issued under public offerings (in shares) \| shares	60,200,000	60,200,000
Sale of stock, price per share (in CAD per share) \| $ / shares	$ 58.50
Common shares issued, net of issue costs	$ 3,500			$ 1,148	$ 274	$ 7,747
Acquisition Bridge Facility
Class of Stock [Line Items]
Proceeds from lines of credit		$ 6.9
Interest Expense
Class of Stock [Line Items]
Dividend equivalent payments recorded as interest expense					$ 109	$ 109

COMMON SHARES - Common Shares Repurchased (Details) - CAD ($) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2016	Nov. 30, 2015	Dec. 31, 2016
Class of Stock [Line Items]
Number of shares approved to be repurchased and canceled from the Toronto Stock Exchange (in shares)		21,000,000
Number of common shares repurchased (in shares)	305,407
Average price per share of common shares repurchased (in Canadian dollars per share)	$ 44.90
Value recorded for common stock repurchased	$ 14
Common Shares
Class of Stock [Line Items]
Percentage of shares authorized to be repurchased and canceled		3.00%
Number of common shares repurchased (in shares)			305,000
Value recorded for common stock repurchased	6		$ 6
Additional Paid-In Capital
Class of Stock [Line Items]
Value recorded for common stock repurchased	$ 8		$ 8

COMMON SHARES - Options (Details)	12 Months Ended
COMMON SHARES - Options (Details)	Dec. 31, 2018 $ / shares shares
Number of Options (thousands)
Outstanding at the beginning of the period (in shares)	11,026,000
Granted (in shares)	2,250,000
Exercised (in shares)	(734,000)
Options forfeited/expired (in shares)	(138,000)
Outstanding at the end of the period (in shares)	12,404,000
Options Exercisable (in shares)	8,189,000
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share) \| $ / shares	$ 51.38
Granted (in Canadian dollars per share) \| $ / shares	56.89
Exercised (in Canadian dollars per share) \| $ / shares	42.65
Options forfeited/expired (in Canadian dollars per share) \| $ / shares	57.23
Outstanding at the end of the period (in Canadian dollars per share) \| $ / shares	52.83
Options Exercisable at December 31, 2017 (in Canadian dollars per share) \| $ / shares	$ 50.72
Weighted Average Remaining Contractual Life (years)
Options Outstanding	3 years 7 months 6 days
Options Exercisable	2 years 7 months 6 days
Number of shares available for grant (in shares)	9,790,373
Options expiration term	7 years
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Vesting in year one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights percentage	33.33%
Vesting in year two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights percentage	33.33%
Vesting in year three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights percentage	33.34%

COMMON SHARES - Stock Options Assumptions Used (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Weighted average fair value (in dollars per share)	$ 5.80	$ 7.22	$ 5.67
Expected life	5 years 8 months 12 days	5 years 8 months 12 days	5 years 9 months 18 days
Interest rate	2.10%	1.20%	0.70%
Volatility	16.00%	18.00%	21.00%
Dividend yield	4.20%	3.60%	4.90%
Forfeiture rate	0.00%	0.00%	5.00%
Expense for stock options	$ 13	$ 12	$ 15
Unrecognized compensation costs related to non-vested stock options	$ 16
Employee Stock Option
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Expense recognition period	3 years

COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Total intrinsic value of options exercised	$ 10	$ 28	$ 31
Fair value of options that have vested	$ 101	$ 140	$ 126
Total options vested (in shares)	2.1	2.3	2.1
Options, exercisable, intrinsic value	$ 8
Options, outstanding, intrinsic value	$ 9

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2018 shares
Shareholder Rights Plan
Number of rights entitled to each common share (in shares)	1

PREFERRED SHARES (Details) - CAD ($) $ / shares in Units, $ in Millions		1 Months Ended			12 Months Ended
	Dec. 31, 2015	Nov. 30, 2016	Apr. 30, 2016	Feb. 29, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Preferred Shares [Line Items]
Carrying value					$ 3,980	$ 3,980	$ 3,980
Number of shares issued (in shares)		60,200,000
Series 1
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					9,498,000
Current Yield					3.266%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 0.8165
Redemption Price Per Share (in Canadian dollars per share)					$ 25.00
Carrying value					$ 233	233	233
Series 1 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					1.92%
Series 2
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					12,502,000
Current Yield					3.633%
Redemption Price Per Share (in Canadian dollars per share)					$ 25
Carrying value					$ 306	306	306
Series 2 \| Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					1.92%
Series 3
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					8,533,000
Current Yield					2.152%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 0.538
Redemption Price Per Share (in Canadian dollars per share)					$ 25.00
Carrying value					$ 209	209	209
Series 3 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					1.28%
Series 4
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					5,467,000
Current Yield	2.993%
Redemption Price Per Share (in Canadian dollars per share)					$ 25
Carrying value					$ 134	134	134
Series 4 \| Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					1.28%
Series 5
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					12,714,000
Current Yield					2.263%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 0.56575
Redemption Price Per Share (in Canadian dollars per share)					$ 25.00
Carrying value					$ 310	310	310
Number of shares converted (in shares)				1,285,739
Series 5 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					1.54%
Series 6
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					1,286,000
Current Yield					3.086%
Redemption Price Per Share (in Canadian dollars per share)					$ 25.00
Carrying value					$ 32	32	32
Series 6 \| Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					1.54%
Series 7
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					24,000,000
Current Yield					4.00%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 1.00
Redemption Price Per Share (in Canadian dollars per share)					$ 25
Carrying value					$ 589	589	589
Series 7 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					2.38%
Series 9
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					18,000,000
Current Yield					4.25%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 1.0625
Redemption Price Per Share (in Canadian dollars per share)					$ 25
Carrying value					$ 442	442	442
Series 9 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					2.35%
Series 11
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					10,000,000
Current Yield					3.80%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 0.95
Redemption Price Per Share (in Canadian dollars per share)					$ 25
Carrying value					$ 244	244	244
Series 11 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					2.96%
Series 13
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					20,000,000
Current Yield					5.50%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 1.375
Redemption Price Per Share (in Canadian dollars per share)					$ 25
Carrying value					$ 493	493	493
Number of shares issued (in shares)			20,000,000
Price per share (in Canadian dollars per share)			$ 25
Gross proceeds from public offering of preferred shares			$ 500
Series 13 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					4.69%
Preferred stock, fixed percentage added To Bond Or Treasury Bill rate for calculating dividend yield, minimum					5.50%
Series 15
Preferred Shares [Line Items]
Preferred shares, outstanding (in shares)					40,000,000
Current Yield					4.90%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 1.225
Redemption Price Per Share (in Canadian dollars per share)					$ 25
Carrying value					$ 988	$ 988	$ 988
Number of shares issued (in shares)		40,000,000
Price per share (in Canadian dollars per share)		$ 25
Gross proceeds from public offering of preferred shares		$ 1,000
Series 15 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					3.85%
Preferred stock, fixed percentage added To Bond Or Treasury Bill rate for calculating dividend yield, minimum					4.90%
Even numbered series of preferred shares
Preferred Shares [Line Items]
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum					90 days
Series 8 \| Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					2.38%
Series 10 \| Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					2.35%
Series 12 \| Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum						2.96%
Series 14 \| Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					4.69%
Series 16 \| Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum					3.85%
Odd numbered series of preferred shares
Preferred Shares [Line Items]
Period of time preferred stock or bond is considered for dividend yield calculation					5 years
Series 2 and Series 4 and Series 6
Preferred Shares [Line Items]
Redemption Price Per Share (in Canadian dollars per share)					$ 25.50

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Before Tax Amount
Other Comprehensive Income (Loss)	$ 1,259	$ (957)	$ (29)
Income Tax Recovery/(Expense)
Other Comprehensive Income (Loss)	55	31	(3)
Net of Tax Amount
Other comprehensive income/(loss) (Note 22)	1,314	(926)	(32)
Foreign currency translation gains on net investment in foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	1,323	(746)	3
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	35	(3)	0
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	1,358	(749)	3
Change in fair value of net investment hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(57)	(77)	(14)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	15	0	4
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(42)	(77)	(10)
Change in fair value and reclassification of gains and losses of cash flow hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(14)	(3)	44
Reclassification from accumulated other comprehensive Income	27	3	71
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	4	1	(14)
Reclassification from AOCI	(6)	0	(29)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(10)	(2)	30
Reclassification from accumulated other comprehensive income	21	3	42
Unrealized actuarial gains and losses and reclassification of actuarial gains and losses of pension and other post-retirement benefits
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(153)	(14)	(38)
Reclassification from accumulated other comprehensive Income	20	21	22
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	39	3	12
Reclassification from AOCI	(5)	(5)	(6)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(114)	(11)	(26)
Reclassification from accumulated other comprehensive income	15	16	16
Other comprehensive income on equity investments
Before Tax Amount
Other comprehensive income (loss), before reclassifications	113
Other Comprehensive Income (Loss)		(141)	(117)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	(27)
Other Comprehensive Income (Loss)		35	30
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	$ 86
Other comprehensive income/(loss) (Note 22)		$ (106)	$ (87)

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	$ 26,891	$ 25,983
Other comprehensive income/(loss) (Note 22)	1,314	(926)	$ (32)
Balance at end of year	30,993	26,891	25,983
Accumulated benefit obligation, (increase) decrease for settlement and curtailment	27
Cash flow hedge loss reported in AOCI and expected to be reclassified to net income in the next 12 months, net of tax	15
Cash flow hedge gain (loss) to be reclassified within twelve months, net of tax	(11)
Currency Translation Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(1,043)	(376)	(383)
Other comprehensive income/(loss), before reclassifications	1,150	(590)	7
Amounts reclassified from AOCI	0	(77)	0
Other comprehensive income/(loss) (Note 22)	1,150	(667)	7
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	0
Balance at end of year	107	(1,043)	(376)
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(31)	(28)	(97)
Other comprehensive income/(loss), before reclassifications	(9)	(1)	27
Amounts reclassified from AOCI	16	(2)	42
Other comprehensive income/(loss) (Note 22)	7	(3)	69
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	1
Balance at end of year	(23)	(31)	(28)
Pension and Other Post-Retirement Benefit Plan Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(203)	(208)	(198)
Other comprehensive income/(loss), before reclassifications	(114)	(11)	(26)
Amounts reclassified from AOCI	15	16	16
Other comprehensive income/(loss) (Note 22)	(99)	5	(10)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	(12)
Balance at end of year	(314)	(203)	(208)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(454)	(348)	(261)
Other comprehensive income/(loss), before reclassifications	72	(117)	(101)
Amounts reclassified from AOCI	12	11	14
Other comprehensive income/(loss) (Note 22)	84	(106)	(87)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	(6)
Balance at end of year	(376)	(454)	(348)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(1,731)	(960)	(939)
Other comprehensive income/(loss), before reclassifications	1,099	(719)	(93)
Amounts reclassified from AOCI	43	(52)	72
Other comprehensive income/(loss) (Note 22)	1,142	(771)	(21)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	(17)
Balance at end of year	(606)	(1,731)	(960)
Accumulated foreign currency adjustment attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive income/(loss), before reclassifications	166	(159)	(14)
Accumulated net gain (loss) from cash flow hedges attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive income/(loss), before reclassifications	(1)	$ 4	$ 3
Amounts reclassified from AOCI	5
Accumulated net gain (loss) from equity investments attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts reclassified from AOCI	$ 2

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Energy)	$ 13,679	$ 13,449	$ 12,547
Interest expense	(2,265)	(2,069)	(1,998)
Plant operating costs and other	3,591	3,906	3,861
Income from equity investments	714	773	514
Gain/(loss) on assets held for sale/sold	170	631	(833)
Total before tax	3,949	3,306	837
Income tax expense	(432)	89	(352)
Net Income Attributable to Common Shares	3,539	2,997	124
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	(22)	3	(71)
Income tax expense	6	(1)	29
Net Income Attributable to Common Shares	(16)	2	(42)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Cash flow hedges \| Interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(18)	(17)	(14)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Amortization of actuarial gains and losses
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other	(16)	(15)	(22)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Settlement charge
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other	(4)	(2)	0
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Pension and other post-retirement benefit plan adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	(20)	(17)	(22)
Income tax expense	5	5	6
Net Income Attributable to Common Shares	(15)	(12)	(16)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income from equity investments	(16)	(15)	(19)
Income tax expense	4	4	5
Net Income Attributable to Common Shares	(12)	(11)	(14)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Currency translation adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Gain/(loss) on assets held for sale/sold		77	0
Income tax expense		0	0
Net Income Attributable to Common Shares		77	0
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Accumulated net gain (loss) from cash flow hedges attributable to noncontrolling interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income Attributable to Common Shares	5	0	0
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Accumulated net gain (loss) from equity investments attributable to noncontrolling interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income Attributable to Common Shares	2	0	0
Energy \| Amounts Reclassified From Accumulated Other Comprehensive Loss \| Cash flow hedges \| Commodities
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Energy)	$ (4)	$ 20	$ (57)

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments, Changes and Balance Sheet Presentation (Details) - CAD ($) $ in Millions		12 Months Ended
	Sep. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized (in years)		12 years	12 years	12 years
Expense for savings plan and DC Plans		$ 59	$ 42	$ 52
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Savings and DC Plans		59	42	52
Total cash contributions		185	212	$ 171
Other comprehensive income (loss), defined benefit plan, settlement and curtailment gain (loss)		(27)
Change in Plan Assets
Plan assets at fair value – beginning of year		3,816
Plan assets at fair value – end of year		3,697	3,816
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 12)		192	193
Other long-term liabilities (Note 15)		$ (569)	$ (389)
Pension Benefit Plans
Employee post-retirement benefits
Consecutive period of employment for highest average earnings (in years)		3 years
Expected average remaining service life of employees over which past service costs are amortized (in years)		9 years	9 years	9 years
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans		$ 103	$ 163	$ 111
Total amount outstanding under letters of credit		$ 17	$ 27
Discount rate		3.90%	3.60%
Remeasurement impact on unrealized actuarial gain (loss), recorded in regulated assets		$ 0	$ (2)	0
Change in Benefit Obligation
Benefit obligation – beginning of year		3,646	3,456
Service cost		121	113
Interest cost		134	135
Employee contributions		5	5
Benefits paid		(177)	(166)
Actuarial (gain)/loss		(92)	253
Curtailment		0	(14)
Settlement		(71)	(66)
Foreign exchange rate changes		87	(70)
Benefit obligation – end of year		3,653	3,646	3,456
Change in Plan Assets
Plan assets at fair value – beginning of year		3,451	3,208
Actual return on plan assets		(73)	358
Employer contributions		103	163
Employee contributions		5	5
Benefits paid		(176)	(166)
Settlement		(71)	(57)
Foreign exchange rate changes		82	(60)
Plan assets at fair value – end of year		3,321	3,451	3,208
Funded Status – Plan Deficit		(332)	(195)
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 12)		0	0
Accounts payable and other		(1)	(1)
Other long-term liabilities (Note 15)		(331)	(194)
Net		(332)	(195)
Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans		$ 23	$ 7	8
Discount rate		4.10%	3.70%
Remeasurement impact on unrealized actuarial gain (loss), recorded in regulated assets		$ 0	$ 0	0
Change in Benefit Obligation
Benefit obligation – beginning of year		375	372
Service cost		4	4
Interest cost		14	14
Employee contributions		0	3
Benefits paid		(23)	(19)
Actuarial (gain)/loss		43	19
Curtailment		0	(2)
Settlement		0	0
Foreign exchange rate changes		17	(16)
Benefit obligation – end of year		430	375	372
Change in Plan Assets
Plan assets at fair value – beginning of year		365	354
Actual return on plan assets		(15)	45
Employer contributions		23	7
Employee contributions		0	3
Benefits paid		(27)	(19)
Settlement		0	0
Foreign exchange rate changes		30	(25)
Plan assets at fair value – end of year		376	365	354
Funded Status – Plan Deficit		(54)	(10)
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 12)		192	193
Accounts payable and other		(8)	(8)
Other long-term liabilities (Note 15)		(238)	(195)
Net		(54)	(10)
Canadian \| Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Letter of credit to the DB Plan		17	27	$ 20
Total amount outstanding under letters of credit		277
U.S. \| Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Other comprehensive income (loss), defined benefit plan, settlement and curtailment gain (loss)		4	3
Net periodic benefit cost (credit), gain (loss) due to settlement		$ (4)	$ (2)
Discount rate			4.10%
Columbia DB Plan \| Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Discount rate	3.70%
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	$ 16
Remeasurement impact on unrealized actuarial gain (loss), recorded in regulated assets	14
Remeasurement impact recorded in OCI	$ 2

EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 3,697	$ 3,816
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	$ (3,653)	$ (3,646)	$ (3,456)
Plan assets at fair value	3,321	3,451	3,208
Funded Status – Plan Deficit	(332)	(195)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(3,347)	(3,372)
Plan assets at fair value	3,321	3,451
Funded Status	$ (26)	$ 79
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans \| Debt securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	33.00%	30.00%
Company debt or common shares included in plan assets, amount	$ 8	$ 7
Company debt or common shares included in plan assets, percentage	0.30%	0.20%
Pension Benefit Plans \| Debt securities \| Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	25.00%
Pension Benefit Plans \| Debt securities \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	45.00%
Pension Benefit Plans \| Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	56.00%	64.00%
Company debt or common shares included in plan assets, amount	$ 7	$ 3
Company debt or common shares included in plan assets, percentage	0.20%	0.10%
Pension Benefit Plans \| Equity securities \| Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	40.00%
Pension Benefit Plans \| Equity securities \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	70.00%
Pension Benefit Plans \| Alternatives
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	11.00%	6.00%
Pension Benefit Plans \| Alternatives \| Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	5.00%
Pension Benefit Plans \| Alternatives \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	15.00%
Pension Benefit Plans \| Not fully funded
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	$ (3,653)	$ (3,646)
Plan assets at fair value	3,321	3,451
Funded Status – Plan Deficit	(332)	(195)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(3,347)	(944)
Plan assets at fair value	3,321	925
Funded Status	(26)	(19)
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(430)	(375)	(372)
Plan assets at fair value	376	365	$ 354
Funded Status – Plan Deficit	(54)	(10)
Other Post-Retirement Benefit Plans \| Not fully funded
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(246)	(203)
Plan assets at fair value	0	0
Funded Status – Plan Deficit	$ (246)	$ (203)

EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	$ 3,816
Plan assets at fair value – end of year	3,697	$ 3,816
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	216	199
Purchases and sales	127	11
Realized and unrealized gains	19	6
Plan assets at fair value – end of year	$ 362	$ 216

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	$ 61
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits	6.00%
Percentage level to which average annual rate was assumed to decrease	4.50%
Effects of a one per cent change in assumed health care cost trend rates
Effect on total of service and interest cost components, Increase	$ 1
Effect on total of service and interest cost components, Decrease	(1)
Effect on post-retirement benefit obligation, Increase	25
Effect on post-retirement benefit obligation, Decrease	(21)
Pension Benefit Plans
DB Plans
Company's expected funding contributions	113
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	17
Estimated future benefit payments, which reflect expected future service
2019	190
2020	193
2021	198
2022	203
2023	207
2024 to 2028	$ 1,081
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	3.90%	3.60%
Rate of compensation increase	3.00%	3.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	3.60%	3.95%	4.20%
Expected long-term rate of return on plan assets	6.70%	6.50%	6.70%
Rate of compensation increase	3.00%	1.20%	0.80%
Net benefit cost
Service cost	$ 121	$ 108	$ 107
Other components of net benefit cost
Interest cost	134	122	127
Expected return on plan assets	(221)	(178)	(175)
Amortization of actuarial loss	15	14	20
Amortization of regulatory asset	18	37	27
Amortization of transitional obligation related to regulated business	0	0	0
Settlement charge – regulatory asset	0	2	0
Settlement charge – AOCI	4	2	0
Other components of net benefit cost	(50)	(1)	(1)
Net Benefit Cost Recognized	71	107	106
Pre-tax amounts recognized in AOCI
Net loss	364	273	270
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	12
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(15)	(18)	(20)
Curtailment	0	(14)	0
Settlement	(4)	(11)	0
Funded status adjustment	110	46	43
Total pre-tax amounts recognized in OCI	91	$ 3	$ 23
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	7
Estimated future benefit payments, which reflect expected future service
2019	24
2020	23
2021	23
2022	23
2023	23
2024 to 2028	$ 114
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.10%	3.70%
Rate of compensation increase	0.00%	0.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	3.70%	4.15%	4.30%
Expected long-term rate of return on plan assets	4.00%	6.05%	5.95%
Rate of compensation increase	0.00%	0.00%	0.00%
Net benefit cost
Service cost	$ 4	$ 4	$ 3
Other components of net benefit cost
Interest cost	14	14	13
Expected return on plan assets	(16)	(21)	(11)
Amortization of actuarial loss	1	1	2
Amortization of regulatory asset	0	1	1
Amortization of transitional obligation related to regulated business	0	0	2
Settlement charge – regulatory asset	0	0	0
Settlement charge – AOCI	0	0	0
Other components of net benefit cost	(1)	(5)	7
Net Benefit Cost Recognized	3	(1)	10
Pre-tax amounts recognized in AOCI
Net loss	53	11	21
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	2
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(1)	(1)	(2)
Curtailment	0	(2)	0
Settlement	0	0	0
Funded status adjustment	43	(7)	(5)
Total pre-tax amounts recognized in OCI	$ 42	$ (10)	$ (7)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Derivative [Line Items]
Fair Value	$ (166)	$ (54)
Designated as a net investment hedge
Derivative [Line Items]
Fair Value	(90)	(194)
Designated as a net investment hedge \| US$ denominated
Derivative [Line Items]
Notional Amount			$ 2,800	$ 1,700
Designated as a net investment hedge \| U.S. dollar cross-currency interest rate swaps (maturing 2019)
Derivative [Line Items]
Fair Value	(43)	(199)
Designated as a net investment hedge \| U.S. dollar cross-currency interest rate swaps (maturing 2019) \| US$ denominated
Derivative [Line Items]
Notional Amount			300	1,200
Net realized gains related to the interest component	2	4
Designated as a net investment hedge \| U.S. dollar foreign exchange options (maturing 2019 to 2020)
Derivative [Line Items]
Fair Value	$ (47)	$ 5
Designated as a net investment hedge \| U.S. dollar foreign exchange options (maturing 2019 to 2020) \| US$ denominated
Derivative [Line Items]
Notional Amount			$ 2,500	$ 500

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge $ in Millions, $ in Millions	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2017 USD ($)
Derivative [Line Items]
Notional amount	$ 31,000		$ 25,400
Fair value	$ 31,700		$ 28,900
US$ denominated
Derivative [Line Items]
Notional amount		$ 22,700		$ 20,200
Fair value		$ 23,200		$ 23,100

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk [Line Items]
Financing receivable, recorded investment, past due	$ 0	$ 0
Provision for other credit losses	0	0
Customer Concentration Risk
Concentration Risk [Line Items]
Credit risk concentration	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion (Note 17)	$ (39,982)	$ (34,677)
Junior subordinated notes (Note 18)	(7,508)	(7,007)
Long-term debt			$ 750	$ 1,100
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Unrealized gains (losses) on hedged items	(2)	4
Long-term debt hedged			$ 750	$ 1,100
Level II \| Carrying Amount
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion (Note 17)	(39,971)	(34,741)
Junior subordinated notes (Note 18)	(7,508)	(7,007)
Total liabilities	(47,479)	(41,748)
Level II \| Fair Value
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion (Note 17)	(42,284)	(40,180)
Junior subordinated notes (Note 18)	(6,665)	(7,233)
Total liabilities	$ (48,949)	$ (47,413)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Total Derivatives
Derivative Assets	$ 798	$ 405
Derivative Liabilities	(964)	(459)
Total Derivatives	(166)	(54)
Total trading activity
Total Derivatives
Derivative Assets	767	389
Derivative Liabilities	(838)	(244)
Total Derivatives	(71)	145
Cash Flow Hedges
Total Derivatives
Derivative Assets	13	8
Derivative Liabilities	(15)	(8)
Total Derivatives	(2)	0
Fair Value Hedges
Total Derivatives
Derivative Assets	1	0
Derivative Liabilities	(4)	(5)
Total Derivatives	(3)	(5)
Net Investment Hedges
Total Derivatives
Derivative Assets	17	8
Derivative Liabilities	(107)	(202)
Total Derivatives	(90)	(194)
Foreign exchange
Total Derivatives
Derivative Assets	18	78
Derivative Liabilities	(295)	(212)
Interest rate
Total Derivatives
Derivative Assets	12	8
Derivative Liabilities	(15)	(5)
Other current assets
Total Derivatives
Derivative Assets	737	332
Other current assets \| Total trading activity
Total Derivatives
Derivative Assets	717	320
Other current assets \| Cash Flow Hedges
Total Derivatives
Derivative Assets	4	4
Other current assets \| Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Net Investment Hedges
Total Derivatives
Derivative Assets	16	8
Other current assets \| Commodities
Total Derivatives
Derivative Assets	717	250
Other current assets \| Commodities \| Commodities
Total Derivatives
Derivative Assets	716	249
Other current assets \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Assets	1	1
Other current assets \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Foreign exchange
Total Derivatives
Derivative Assets	17	78
Other current assets \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Assets	1	70
Other current assets \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Assets	16	8
Other current assets \| Interest rate
Total Derivatives
Derivative Assets	3	4
Other current assets \| Interest rate \| Interest rate
Total Derivatives
Derivative Assets	0	1
Other current assets \| Interest rate \| Cash Flow Hedges
Total Derivatives
Derivative Assets	3	3
Other current assets \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Intangible and other assets
Total Derivatives
Derivative Assets	61	73
Intangible and other assets \| Total trading activity
Total Derivatives
Derivative Assets	50	69
Intangible and other assets \| Cash Flow Hedges
Total Derivatives
Derivative Assets	9	4
Intangible and other assets \| Fair Value Hedges
Total Derivatives
Derivative Assets	1	0
Intangible and other assets \| Net Investment Hedges
Total Derivatives
Derivative Assets	1	0
Intangible and other assets \| Commodities
Total Derivatives
Derivative Assets	51	69
Intangible and other assets \| Commodities \| Commodities
Total Derivatives
Derivative Assets	50	69
Intangible and other assets \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Assets	1	0
Intangible and other assets \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Intangible and other assets \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Intangible and other assets \| Foreign exchange
Total Derivatives
Derivative Assets	1
Intangible and other assets \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Assets	0
Intangible and other assets \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0
Intangible and other assets \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Assets	0
Intangible and other assets \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Assets	1
Intangible and other assets \| Interest rate
Total Derivatives
Derivative Assets	9	4
Intangible and other assets \| Interest rate \| Interest rate
Total Derivatives
Derivative Assets	0	0
Intangible and other assets \| Interest rate \| Cash Flow Hedges
Total Derivatives
Derivative Assets	8	4
Intangible and other assets \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Assets	1	0
Intangible and other assets \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Accounts payable and other
Total Derivatives
Derivative Liabilities	(922)	(387)
Accounts payable and other \| Total trading activity
Total Derivatives
Derivative Liabilities	(810)	(218)
Accounts payable and other \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(4)	(6)
Accounts payable and other \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	(3)	(4)
Accounts payable and other \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	(105)	(159)
Accounts payable and other \| Commodities
Total Derivatives
Derivative Liabilities	(626)	(214)
Accounts payable and other \| Commodities \| Commodities
Total Derivatives
Derivative Liabilities	(622)	(208)
Accounts payable and other \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(4)	(6)
Accounts payable and other \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Foreign exchange
Total Derivatives
Derivative Liabilities	(293)	(169)
Accounts payable and other \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Liabilities	(188)	(10)
Accounts payable and other \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	(105)	(159)
Accounts payable and other \| Interest rate
Total Derivatives
Derivative Liabilities	(3)	(4)
Accounts payable and other \| Interest rate \| Interest rate
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Interest rate \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	(3)	(4)
Accounts payable and other \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities
Total Derivatives
Derivative Liabilities	(42)	(72)
Other long-term liabilities \| Total trading activity
Total Derivatives
Derivative Liabilities	(28)	(26)
Other long-term liabilities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(11)	(2)
Other long-term liabilities \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Other long-term liabilities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	(2)	(43)
Other long-term liabilities \| Commodities
Total Derivatives
Derivative Liabilities	(28)	(28)
Other long-term liabilities \| Commodities \| Commodities
Total Derivatives
Derivative Liabilities	(28)	(26)
Other long-term liabilities \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	(2)
Other long-term liabilities \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Foreign exchange
Total Derivatives
Derivative Liabilities	(2)	(43)
Other long-term liabilities \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	(2)	(43)
Other long-term liabilities \| Interest rate
Total Derivatives
Derivative Liabilities	(12)	(1)
Other long-term liabilities \| Interest rate \| Interest rate
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Interest rate \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(11)	0
Other long-term liabilities \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Other long-term liabilities \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
LMCI Restricted Investments
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains/(losses)	11	(3)	$ (28)
Net realized losses	(4)	(1)	0
Other Restricted Investments
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains/(losses)	0	1	(1)
Net realized losses	0	0	$ 0
Fixed income securities \| LMCI Restricted Investments
Fair value
Fixed income securities (maturing within 1 year)	0	0
Fixed income securities (maturing within 1-5 years)	0	0
Fixed income securities (maturing within 5-10 years)	140	14
Fixed income securities (maturing after 10 years)	952	790
Fixed income securities	1,092	804
Fixed income securities \| Other Restricted Investments
Fair value
Fixed income securities (maturing within 1 year)	22	23
Fixed income securities (maturing within 1-5 years)	110	107
Fixed income securities (maturing within 5-10 years)	0	0
Fixed income securities (maturing after 10 years)	0	0
Fixed income securities	$ 132	$ 130

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Fair Value Hedging Relationships (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value hedging adjustments, discontinued hedges	$ 0	$ 0
Current portion of long-term debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Carrying amount	(748)	(688)
Fair value hedging adjustments	3	1
Long-term debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Carrying amount	(273)	(685)
Fair value hedging adjustments	0	4
Long-term debt, including current portion
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Carrying amount	(1,021)	(1,373)
Fair value hedging adjustments	$ 3	$ 5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional and Maturity Summary (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) GWh Bcf MMBbls	Dec. 31, 2017 MXN ($) GWh Bcf MMBbls	Dec. 31, 2017 USD ($)
Commodities \| Power \| Purchases
Derivative [Line Items]
Notional amount, energy (gwh) \| GWh	23,865	66,132
Commodities \| Power \| Sales
Derivative [Line Items]
Notional amount, energy (gwh) \| GWh	17,689	42,836
Commodities \| Natural Gas \| Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| Bcf	44	133
Commodities \| Natural Gas \| Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| Bcf	56	135
Commodities \| Liquids \| Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| MMBbls	59	6
Commodities \| Liquids \| Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| MMBbls	79	7
Foreign exchange
Derivative [Line Items]
Notional amount	$ 3,862	$ 100	$ 2,931
Interest rate
Derivative [Line Items]
Notional amount \| $	$ 1,650		$ 2,300

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses)/Gains (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
U.S. Northeast Merchant Power Assets
Derivative [Line Items]
Gain (loss) on cash flow hedge	$ 0	$ 0	$ (42,000,000)
Commodities
Derivative [Line Items]
Amount of unrealized gains/(losses) in the year	28,000,000	62,000,000	123,000,000
Amount of realized gains/(losses) in the year	351,000,000	(107,000,000)	(204,000,000)
Commodities \| Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	(1,000,000)	23,000,000	(167,000,000)
Foreign exchange
Derivative [Line Items]
Amount of unrealized gains/(losses) in the year	(248,000,000)	88,000,000	25,000,000
Amount of realized gains/(losses) in the year	(24,000,000)	18,000,000	62,000,000
Foreign exchange \| Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	0	5,000,000	(101,000,000)
Interest rate
Derivative [Line Items]
Amount of unrealized gains/(losses) in the year	0	(1,000,000)	0
Amount of realized gains/(losses) in the year	0	1,000,000	0
Interest rate \| Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	$ (1,000,000)	$ 1,000,000	$ 4,000,000

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - Cash Flow Hedges - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	$ (14)	$ 3	$ 44
Commodities \| Power
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	(1)	(1)	39
Interest rate
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	$ (13)	$ 4	$ 5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effect of Fair Value and Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues (Energy)	$ 13,679	$ 13,449	$ 12,547
Interest Expense	(2,265)	(2,069)	(1,998)
Energy
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues (Energy)	2,124	3,593	4,206
Interest Expense \| Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged items	(71)	(74)	(74)
Derivatives designated as hedging instruments	(4)	1	8
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	22	17	14
Revenue \| Commodity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	$ 5	$ (20)	$ 57

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative – Asset
Gross Derivative Instruments	$ 798	$ 405
Amounts Available for Offset	(648)	(255)
Net Amounts	150	150
Derivative – Liability
Gross Derivative Instruments	(964)	(459)
Amounts Available for Offset	648	255
Net Amounts	(316)	(204)
Cash collateral provided by the Company	143	165
Letters of credit provided by the Company	22	30
Cash collateral received by the Company	0	0
Letters of credit received by the Company	1	3
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	6	2
Additional collateral required if credit-risk-related contingent features were triggered	6	2
Foreign exchange
Derivative – Asset
Gross Derivative Instruments	18	78
Amounts Available for Offset	(18)	(56)
Net Amounts	0	22
Derivative – Liability
Gross Derivative Instruments	(295)	(212)
Amounts Available for Offset	18	56
Net Amounts	(277)	(156)
Interest rate
Derivative – Asset
Gross Derivative Instruments	12	8
Amounts Available for Offset	(4)	(1)
Net Amounts	8	7
Derivative – Liability
Gross Derivative Instruments	(15)	(5)
Amounts Available for Offset	4	1
Net Amounts	(11)	(4)
Power \| Commodities
Derivative – Asset
Gross Derivative Instruments	768	319
Amounts Available for Offset	(626)	(198)
Net Amounts	142	121
Derivative – Liability
Gross Derivative Instruments	(654)	(242)
Amounts Available for Offset	626	198
Net Amounts	$ (28)	$ (44)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value Hierarchy
Derivative Instrument Assets:	$ 798	$ 405
Derivative Instrument Liabilities:	(964)	(459)
Commodities \| Power
Fair Value Hierarchy
Derivative Instrument Assets:	768	319
Derivative Instrument Liabilities:	(654)	(242)
Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets:	18	78
Derivative Instrument Liabilities:	(295)	(212)
Interest rate
Fair Value Hierarchy
Derivative Instrument Assets:	12	8
Derivative Instrument Liabilities:	(15)	(5)
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	(166)	(54)
Recurring basis \| Commodities \| Power
Fair Value Hierarchy
Derivative Instrument Assets:	768	319
Derivative Instrument Liabilities:	(654)	(242)
Recurring basis \| Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets:	18	78
Derivative Instrument Liabilities:	(295)	(212)
Recurring basis \| Interest rate
Fair Value Hierarchy
Derivative Instrument Assets:	12	8
Derivative Instrument Liabilities:	(15)	(5)
Recurring basis \| Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	26	(6)
Recurring basis \| Quoted Prices in Active Markets (Level I) \| Commodities \| Power
Fair Value Hierarchy
Derivative Instrument Assets:	581	21
Derivative Instrument Liabilities:	(555)	(27)
Recurring basis \| Quoted Prices in Active Markets (Level I) \| Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets:	0	0
Derivative Instrument Liabilities:	0	0
Recurring basis \| Quoted Prices in Active Markets (Level I) \| Interest rate
Fair Value Hierarchy
Derivative Instrument Assets:	0	0
Derivative Instrument Liabilities:	0	0
Recurring basis \| Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Assets and (liabilities), net	(188)	(41)
Recurring basis \| Significant Other Observable Inputs (Level II) \| Commodities \| Power
Fair Value Hierarchy
Derivative Instrument Assets:	187	283
Derivative Instrument Liabilities:	(95)	(193)
Recurring basis \| Significant Other Observable Inputs (Level II) \| Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets:	18	78
Derivative Instrument Liabilities:	(295)	(212)
Recurring basis \| Significant Other Observable Inputs (Level II) \| Interest rate
Fair Value Hierarchy
Derivative Instrument Assets:	12	8
Derivative Instrument Liabilities:	(15)	(5)
Recurring basis \| Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	(4)	(7)
Recurring basis \| Significant Unobservable Inputs (Level III) \| Commodities \| Power
Fair Value Hierarchy
Derivative Instrument Assets:	0	15
Derivative Instrument Liabilities:	(4)	(22)
Recurring basis \| Significant Unobservable Inputs (Level III) \| Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets:	0	0
Derivative Instrument Liabilities:	0	0
Recurring basis \| Significant Unobservable Inputs (Level III) \| Interest rate
Fair Value Hierarchy
Derivative Instrument Assets:	0	0
Derivative Instrument Liabilities:	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue
Net change in the Level III fair value category
Unrealized gains (losses) attributed to derivatives in the Level III category	$ (5)	$ (7)
Commodity contracts \| Power
Net change in the Level III fair value category
Balance at beginning of year	(7)	16
Transfers out of Level III	5	(19)
Total gains/(losses) included in Net income	8	(17)
Settlements	(9)	18
Sales	0	(5)
Foreign exchange	(1)	0
Balance at end of year	(4)	$ (7)
Commodity contracts \| Power \| Level III
Net change in the Level III fair value category
Decrease in fair value of outstanding derivative instruments included in Level III due to a 10% increase in commodity prices	2
Increase in fair value of outstanding derivative instruments included in Level III due to a 10% decrease in commodity prices	$ 2

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CHANGES IN OPERATING WORKING CAPITAL
Increase in Accounts receivable	$ (69)	$ (576)	$ (482)
Increase in Inventories	(49)	(38)	(87)
Decrease/(increase) in Assets held for sale	0	14	(13)
Decrease in Other current assets	45	189	328
(Decrease)/increase in Accounts payable and other	(70)	151	424
Increase in Accrued interest	41	12	62
(Decrease)/increase in Liabilities related to assets held for sale	0	(25)	16
(Increase)/decrease in Operating Working Capital	$ (102)	$ (273)	$ 248

ACQUISITIONS AND DISPOSITIONS - Narrative (Details) $ / shares in Units, shares in Millions, $ in Millions, $ in Millions									1 Months Ended			3 Months Ended		6 Months Ended	12 Months Ended
	Oct. 24, 2018 CAD ($)	Dec. 19, 2017 CAD ($)	Jun. 02, 2017 USD ($)	Jun. 01, 2017 USD ($)	Apr. 19, 2017 USD ($)	Jul. 01, 2016 CAD ($) mi km Bcf	Jul. 01, 2016 USD ($)	May 01, 2016 USD ($)	Mar. 31, 2016 USD ($)	Feb. 29, 2016 USD ($)	Jan. 31, 2016 USD ($)	Jun. 30, 2017 CAD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2016 CAD ($)	Dec. 31, 2018 CAD ($) mi km Bcf	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Jul. 01, 2016 USD ($) mi km $ / shares Bcf	Jun. 30, 2016 $ / shares shares	Apr. 30, 2016 CAD ($) shares	Apr. 01, 2016 shares
Business Acquisition [Line Items]
Contributions to equity investments															$ 1,015	$ 1,681	$ 765
Common stock, value, subscriptions																						$ 4,400
Subscription receipt (in shares) \| shares																						96.6
Goodwill															14,178	13,084
Proceeds from sale of assets, net of transaction costs															614	4,683	6
Columbian Pipeline
Business Acquisition [Line Items]
Percentage of interests acquired						100.00%														100.00%
Purchase price							$ 10,300
Share price (in usd per share) \| $ / shares																				$ 25.5
Common stock, value, subscriptions						$ 4,400
Subscription receipt (in shares) \| shares																							96.6
Investments of regulated natural gas pipelines (in kilometers) \| km						24,500														24,500
Investments of regulated natural gas pipelines (in miles) \| mi						15,200														15,200
Investments of regulated natural gas storage facilities (in billion cubic feet) \| Bcf						285														285
Decrease in deferred income tax liabilities												$ 45	$ 35
Goodwill adjustment												71	55
Goodwill						$ 10,078												$ 7,802	$ 7,747	$ 7,747
Increase (decrease) in fair value of acquired liabilities, long-term debt												300	231		$ 232	242
Common unit, outstanding (in shares) \| shares																					53.8
Share price (in USD per share) \| $ / shares																					$ 15
Acquisition costs														$ 36			36
Revenue of acquiree since acquisition date														929
Earnings of acquiree since acquisition date														132
Columbian Pipeline \| U.S. federal
Business Acquisition [Line Items]
Effective income tax rate percent						39.00%	39.00%
Columbian Pipeline \| Pension Benefit Plans
Business Acquisition [Line Items]
Increase in fair value of regulatory assets						$ 15	$ 12
Increase in fair value of other long-term liabilities						5	4
Decrease in fair value of intangibles and other assets						14	11
Decrease in fair value of regulatory liabilities						2	2
Columbian Pipeline \| Mining Properties and Mineral Rights
Business Acquisition [Line Items]
Increase (decrease) in fair value of property, plant, and equipment						241	185					$ 116	$ 90
Columbian Pipeline \| Natural Gas
Business Acquisition [Line Items]
Increase (decrease) in fair value of property, plant, and equipment						$ 840	646
Columbian Pipeline \| Bridge Facility
Business Acquisition [Line Items]
Proceeds from lines of credit							$ 6,900
Natural Gas – Ironwood
Business Acquisition [Line Items]
Purchase price										$ 653
Ravenswood, Ironwood, Kibby Wind and Ocean State Power
Business Acquisition [Line Items]
Proceeds from sale of assets, net of transaction costs			$ 2,029
Gain (loss) on disposition of property plant equipment																	(829)
Gain (loss) on disposition of property plant equipment, net of tax																	(863)
U.S. Natural Gas Pipelines
Business Acquisition [Line Items]
Investments of regulated natural gas pipelines (in kilometers) \| km															50,199
Investments of regulated natural gas pipelines (in miles) \| mi															31,192
Investments of regulated natural gas storage facilities (in billion cubic feet) \| Bcf															535
Goodwill														$ 13,958	$ 14,178	13,084	13,958
U.S. Natural Gas Pipelines \| Columbian Pipeline
Business Acquisition [Line Items]
Goodwill adjustment																71
Iroquois
Business Acquisition [Line Items]
Ownership interest percentage								50.00%	49.35%
Additional ownership acquired (percent)								0.65%	4.87%
Contributions to equity investments								$ 7	$ 54
Iroquois \| U.S. Natural Gas Pipelines
Business Acquisition [Line Items]
Ownership interest percentage			0.66%	50.00%											50.00%
Ontario Solar Assets
Business Acquisition [Line Items]
Proceeds from sale of assets, net of transaction costs		$ 541
Gain (loss) on disposition of property plant equipment		127
Gain (loss) on disposition of property plant equipment, net of tax		$ 136
TC Hydro
Business Acquisition [Line Items]
Proceeds from sale of assets, net of transaction costs					$ 1,070
Gain (loss) on disposition of property plant equipment																715
Gain (loss) on disposition of property plant equipment, net of tax																440
Income tax recovery related to sale															$ 27
Gain (loss) on disposition of property plant and equipment foreign currency translation amount																5
Ravenswood, Ironwood, Kibby Wind and Ocean State Power
Business Acquisition [Line Items]
Gain (loss) on disposition of property plant equipment																(211)
Gain (loss) on disposition of property plant equipment, net of tax																(167)
Foreign currency translation gain on assets held for sale																$ 2	$ 70
Disposal group, disposed of by sale, not discontinued operations \| PNGTS And Iroquois Transmission systems
Business Acquisition [Line Items]
Total consideration				$ 765
Cash received				597
Assumption of debt by purchaser				$ 168
Disposal group, disposed of by sale, not discontinued operations \| Cartier Wind
Business Acquisition [Line Items]
Ownership interest before transaction, percent	62.00%
Proceeds from sale of assets, net of transaction costs	$ 630
Gain (loss) on disposition of property plant equipment	170
Gain (loss) on disposition of property plant equipment, net of tax	$ 143
Disposal group, disposed of by sale, not discontinued operations \| Iroquois
Business Acquisition [Line Items]
Ownership interest before transaction, percent				49.34%
Disposal group, disposed of by sale, not discontinued operations \| PNGTS
Business Acquisition [Line Items]
Ownership interest before transaction, percent				11.81%							49.90%
Total consideration											$ 223
Cash received											188
Assumption of debt by purchaser											$ 35

ACQUISITIONS AND DISPOSITIONS - Schedule of Assets Acquired and Liabilities Assumed (Details) $ in Millions, $ in Millions	Jul. 01, 2016 CAD ($)	Jul. 01, 2016 USD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Jul. 01, 2016 USD ($)
Fair Value
Goodwill			$ 14,178	$ 13,084
Exchange rate	1.30						1.30
Columbian Pipeline
Business Acquisition [Line Items]
Purchase Price Consideration	$ 13,392	$ 10,294
Fair Value
Current assets	856						$ 658
Plant, property and equipment	9,835						7,560
Equity investments	574						441
Regulatory assets	248						190
Intangible and other assets	175						135
Current liabilities	(777)						(597)
Regulatory liabilities	(383)						(294)
Other long-term liabilities	(187)						(144)
Deferred income tax liabilities	(2,098)						(1,613)
Long-term debt	(3,878)						(2,981)
Non-controlling interests	(1,051)						(808)
Fair Value of Net Assets Acquired	3,314						2,547
Goodwill	$ 10,078				$ 7,802	$ 7,747	$ 7,747

ACQUISITIONS AND DISPOSITIONS - Schedule of Fair Value of Debt Acquired (Details) - Columbian Pipeline $ in Millions	Jul. 01, 2016 CAD ($)	Jul. 01, 2016 USD ($)
Debt Instrument [Line Items]
Fair Value	$ 3,878	$ 2,981,000,000
Senior Unsecured Notes
Debt Instrument [Line Items]
Fair Value		2,981,000,000
Senior Unsecured Notes (US$500) \| Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face amount		500,000,000
Fair Value		$ 506,000,000
Interest Rate	2.45%	2.45%
Senior Unsecured Notes (US$750) \| Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 750,000,000
Fair Value		$ 779,000,000
Interest Rate	3.30%	3.30%
Senior Unsecured Notes (US$1,000) \| Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,000,000,000
Fair Value		$ 1,092,000,000
Interest Rate	4.50%	4.50%
Senior Unsecured Notes (US$500) \| Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 500,000,000
Fair Value		$ 604,000,000
Interest Rate	5.80%	5.80%

ACQUISITIONS AND DISPOSITIONS - Pro Forma Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Business Combinations [Abstract]
Revenues	$ 13,404	$ 13,007
Net Income/(Loss)	627	(820)
Net Income/(Loss) Attributable to Common Shares	$ 234	$ (971)

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Operating Leases (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Minimum Lease Payments
2019	$ 81
2020	78
2021	76
2022	69
2023	67
2024 and thereafter	390
Minimum Lease Payments	761
Amounts Recoverable under Subleases
2019	7
2020	7
2021	4
2022	3
2023	3
2024 and thereafter	8
Amounts Recoverable under Subleases	32
Net Payments
2019	74
2020	71
2021	72
2022	66
2023	64
2024 and thereafter	382
Net Payments	729
Rent Expense
Net rental expense on operating leases	$ 84	$ 93	$ 145
Minimum
Rent Expense
Operating leases optional renewable terms, low end of range	1 year
Maximum
Rent Expense
Operating leases optional renewable terms, low end of range	25 years

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Other Commitments and Contingencies (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites	$ 40	$ 34
Operating segments \| Canadian Natural Gas Pipelines \| Capital expenditures
Other Commitments
Commitment for capital expenditures	4,600
Operating segments \| U.S. Natural Gas Pipelines \| Capital expenditures
Other Commitments
Commitment for capital expenditures	100
Operating segments \| Mexico Natural Gas Pipelines \| Capital expenditures
Other Commitments
Commitment for capital expenditures	300
Operating segments \| Liquids Pipelines \| Capital expenditures
Other Commitments
Commitment for capital expenditures	400
Operating segments \| Energy \| Capital expenditures
Other Commitments
Commitment for capital expenditures	700
Corporate \| Capital expenditures
Other Commitments
Commitment for capital expenditures	$ 100

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Guarantees
Potential Exposure	$ 375	$ 507
Carrying Value	12	16
Sur de Texas
Guarantees
Potential Exposure	183	315
Carrying Value	1	2
Bruce Power
Guarantees
Potential Exposure	88	88
Carrying Value	0	1
Other jointly owned entities
Guarantees
Potential Exposure	104	104
Carrying Value	$ 11	$ 13

CORPORATE RESTRUCTURING COSTS (Details) $ in Millions	Dec. 31, 2018 CAD ($)
Restructuring Cost and Reserve [Line Items]
Cumulative recoverable restructuring costs	$ 157
Employee Severance
Restructuring Cost and Reserve [Line Items]
Cumulative restructuring costs incurred	86
Lease Commitments
Restructuring Cost and Reserve [Line Items]
Cumulative restructuring costs incurred	$ 60

CORPORATE RESTRUCTURING COSTS - Schedule of Change In Restructuring Liability (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Restructuring Reserve [Roll Forward]
Restructuring liability as at the beginning of period	$ 62	$ 99
Restructuring charges	42	6
Accretion expense	1	1
Cash payments	(24)	(44)
Restructuring Liability as at the end of period	81	62
Recoverable restructuring costs incurred	21	3
Employee Severance
Restructuring Reserve [Roll Forward]
Restructuring liability as at the beginning of period	9	36
Restructuring charges	0	0
Accretion expense	0	0
Cash payments	(9)	(27)
Restructuring Liability as at the end of period	0	9
Lease Commitments
Restructuring Reserve [Roll Forward]
Restructuring liability as at the beginning of period	53	63
Restructuring charges	42	6
Accretion expense	1	1
Cash payments	(15)	(17)
Restructuring Liability as at the end of period	$ 81	$ 53

VARIABLE INTEREST ENTITIES (Details)	12 Months Ended
VARIABLE INTEREST ENTITIES (Details)	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable interest entity ownership percentage	100.00%

VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 446		$ 1,089	$ 1,016	$ 850
Accounts receivable	2,535	$ 2,460	2,522
Inventories	431		378
Other	1,180	770	691
Total Current Assets	5,135		4,680
Plant, Property and Equipment	66,503		57,277
Equity Investments	7,113		6,366
Goodwill	14,178		13,084
Total Assets	98,920		86,101
Current Liabilities
Accounts payable and other	5,408	$ 4,074	4,057
Accrued interest	646		605
Current portion of long-term debt	3,462		2,866
Total Current Liabilities	12,946		9,877
Total Regulatory Liabilities	3,930		4,321
Other Long-Term Liabilities	1,008		727
Deferred Income Tax Liabilities	6,026		5,403
Long-Term Debt	36,509		31,875
Total Liabilities	67,927		59,210
Variable Interest Entity, Primary Beneficiary
Current Assets
Cash and cash equivalents	45		41
Accounts receivable	79		63
Inventories	24		23
Other	13		11
Total Current Assets	161		138
Plant, Property and Equipment	3,026		3,535
Equity Investments	965		917
Goodwill	453		490
Intangible and Other Assets	8		3
Total Assets	4,613		5,083
Current Liabilities
Accounts payable and other	88		137
Dividends payable	0		1
Accrued interest	24		23
Current portion of long-term debt	79		88
Total Current Liabilities	191		249
Total Regulatory Liabilities	43		34
Other Long-Term Liabilities	3		3
Deferred Income Tax Liabilities	13		13
Long-Term Debt	3,125		3,244
Total Liabilities	$ 3,375		$ 3,543

VARIABLE INTEREST ENTITIES - Carrying Value of VIEs and Maximum Exposure (Details) - Variable Interest Entity, Not Primary Beneficiary - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Balance sheet
Equity investments	$ 4,575	$ 4,372
Off-balance sheet
Potential exposure to guarantees	170	171
Maximum exposure to loss	$ 4,745	$ 4,543

Label	Element	Value
Accounting Standards Update 2016-09 [Member] \| Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 12,000,000

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee post-retirement benefits
Fair value of plan assets	$ 3,697	$ 3,816
Percentage of Total Portfolio	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 1,817	$ 1,186
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1,518	2,414
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	362	216	$ 199
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	$ 48	$ 61
Percentage of Total Portfolio	1.00%	2.00%
Cash and Cash Equivalents \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 48	$ 44
Cash and Cash Equivalents \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	17
Cash and Cash Equivalents \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, Canadian
Employee post-retirement benefits
Fair value of plan assets	$ 493	$ 561
Percentage of Total Portfolio	13.00%	15.00%
Equity Securities, Canadian \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 355	$ 410
Equity Securities, Canadian \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	138	151
Equity Securities, Canadian \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 576	$ 897
Percentage of Total Portfolio	16.00%	24.00%
Equity Securities, U.S. \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 460	$ 543
Equity Securities, U.S. \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	116	354
Equity Securities, U.S. \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, International
Employee post-retirement benefits
Fair value of plan assets	$ 321	$ 367
Percentage of Total Portfolio	9.00%	10.00%
Equity Securities, International \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 40	$ 45
Equity Securities, International \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	281	322
Equity Securities, International \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, Global
Employee post-retirement benefits
Fair value of plan assets	$ 384	$ 301
Percentage of Total Portfolio	10.00%	8.00%
Equity Securities, Global \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 116	$ 0
Equity Securities, Global \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	268	301
Equity Securities, Global \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, Emerging
Employee post-retirement benefits
Fair value of plan assets	$ 146	$ 155
Percentage of Total Portfolio	4.00%	4.00%
Equity Securities, Emerging \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 8	$ 8
Equity Securities, Emerging \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	138	147
Equity Securities, Emerging \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Federal
Employee post-retirement benefits
Fair value of plan assets	$ 186	$ 193
Percentage of Total Portfolio	5.00%	5.00%
Fixed Income Securities, Canadian Bonds, Federal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Federal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	186	193
Fixed Income Securities, Canadian Bonds, Federal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Provincial
Employee post-retirement benefits
Fair value of plan assets	$ 198	$ 194
Percentage of Total Portfolio	5.00%	5.00%
Fixed Income Securities, Canadian Bonds, Provincial \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Provincial \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	198	194
Fixed Income Securities, Canadian Bonds, Provincial \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Municipal
Employee post-retirement benefits
Fair value of plan assets	$ 8	$ 8
Percentage of Total Portfolio	1.00%	0.00%
Fixed Income Securities, Canadian Bonds, Municipal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Municipal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	8	8
Fixed Income Securities, Canadian Bonds, Municipal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 112	$ 122
Percentage of Total Portfolio	3.00%	3.00%
Fixed Income Securities, Canadian Bonds, Corporate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	112	122
Fixed Income Securities, Canadian Bonds, Corporate \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, Federal
Employee post-retirement benefits
Fair value of plan assets	$ 350	$ 244
Percentage of Total Portfolio	9.00%	6.00%
Fixed Income Securities, U.S. Bonds, Federal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 350	$ 0
Fixed Income Securities, U.S. Bonds, Federal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	244
Fixed Income Securities, U.S. Bonds, Federal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, State
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 41
Percentage of Total Portfolio	0.00%	1.00%
Fixed Income Securities, U.S. Bonds, State \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, U.S. Bonds, State \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	41
Fixed Income Securities, U.S. Bonds, State \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, Municipal
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 4
Percentage of Total Portfolio	0.00%	0.00%
Fixed Income Securities, U.S. Bonds, Municipal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, U.S. Bonds, Municipal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	4
Fixed Income Securities, U.S. Bonds, Municipal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 196	$ 234
Percentage of Total Portfolio	5.00%	6.00%
Fixed Income Securities, U.S. Bonds, Corporate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 145	$ 0
Fixed Income Securities, U.S. Bonds, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	51	234
Fixed Income Securities, U.S. Bonds, Corporate \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, International, Government
Employee post-retirement benefits
Fair value of plan assets	$ 10	$ 4
Percentage of Total Portfolio	1.00%	0.00%
Fixed Income Securities, International, Government \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 6	$ 0
Fixed Income Securities, International, Government \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	4	4
Fixed Income Securities, International, Government \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, International, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 37	$ 5
Percentage of Total Portfolio	1.00%	0.00%
Fixed Income Securities, International, Corporate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 19	$ 0
Fixed Income Securities, International, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	18	5
Fixed Income Securities, International, Corporate \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, International, Mortgage-backed
Employee post-retirement benefits
Fair value of plan assets	$ 128	$ 73
Percentage of Total Portfolio	3.00%	2.00%
Fixed Income Securities, International, Mortgage-backed \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 128	$ 0
Fixed Income Securities, International, Mortgage-backed \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	73
Fixed Income Securities, International, Mortgage-backed \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Real estate
Employee post-retirement benefits
Fair value of plan assets	$ 196	$ 140
Percentage of Total Portfolio	5.00%	4.00%
Real estate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Real estate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Real estate \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	196	140
Infrastructure
Employee post-retirement benefits
Fair value of plan assets	$ 163	$ 70
Percentage of Total Portfolio	4.00%	2.00%
Infrastructure \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Infrastructure \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Infrastructure \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	163	70
Private equity funds
Employee post-retirement benefits
Fair value of plan assets	$ 3	$ 6
Percentage of Total Portfolio	1.00%	0.00%
Private equity funds \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Private equity funds \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Private equity funds \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	3	6
Funds held on deposit
Employee post-retirement benefits
Fair value of plan assets	$ 142	$ 136
Percentage of Total Portfolio	4.00%	3.00%
Funds held on deposit \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 142	$ 136
Funds held on deposit \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Funds held on deposit \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0