TC Energy (TRP) 40-F 15 Feb 18 2017 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2017shares
Document and Entity Information
Entity Registrant Name	TRANSCANADA CORP
Entity Central Index Key	1,232,384
Document Type	40-F
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	881,375,600
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY

Consolidated statement of incom

Consolidated statement of income - CAD shares in Millions, CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Liquids Pipelines	CAD 2,009	CAD 1,755	CAD 1,879
Energy	3,593	4,206	4,091
Revenues	13,449	12,547	11,353
Income from Equity Investments (Note 9)	773	514	440
Operating and Other Expenses
Plant operating costs and other	3,906	3,861	3,303
Commodity purchases resold	2,382	2,172	2,237
Property taxes	569	555	517
Depreciation and amortization	2,055	1,939	1,765
Goodwill and other asset impairment charges (Notes 8, 11 and 12)	1,257	1,388	3,745
Total Operating and Other Expenses	10,169	9,915	11,567
Gain/(Loss) on Assets Held for Sale/Sold (Notes 6 and 26)	631	(833)	(125)
Financial Charges
Interest expense (Note 17)	2,069	1,998	1,370
Allowance for funds used during construction	(507)	(419)	(295)
Interest income and other	(184)	(103)	132
Total Financial Charges	1,378	1,476	1,207
Income/(Loss) before Income Taxes	3,306	837	(1,106)
Income Tax (Recovery)/Expense (Note 16)
Current	149	156	136
Deferred	566	196	(102)
Deferred – U.S. Tax Reform	(804)	0	0
Income Tax (Recovery)/Expense	(89)	352	34
Net Income/(Loss)	3,395	485	(1,140)
Net income attributable to non-controlling interests (Note 19)	238	252	6
Net Income/(Loss) Attributable to Controlling Interests	3,157	233	(1,146)
Preferred share dividends	160	109	94
Net Income/(Loss) Attributable to Common Shares	CAD 2,997	CAD 124	CAD (1,240)
Net Income/(Loss) per Common Share (Note 20)
Basic (in dollars per share)	CAD 3.44	CAD 0.16	CAD (1.75)
Diluted (in dollars per share)	3.43	0.16	(1.75)
Dividends Declared per Common Share (in dollars per share)	CAD 2.50	CAD 2.26	CAD 2.08
Weighted Average Number of Common Shares (millions) (Note 20)
Basic (in shares)	872	759	709
Diluted (in shares)	874	760	709
Canadian Natural Gas Pipelines
Revenues
Revenues	CAD 3,693	CAD 3,682	CAD 3,680
U.S. Natural Gas Pipelines
Revenues
Revenues	3,584	2,526	1,444
Mexico Natural Gas Pipelines
Revenues
Revenues	CAD 570	CAD 378	CAD 259

Consolidated statement of compr

Consolidated statement of comprehensive income - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net Income/(Loss)	CAD 3,395	CAD 485	CAD (1,140)
Other Comprehensive (Loss)/Income, Net of Income Taxes
Foreign currency translation losses and gains on net investment in foreign operations	(749)	3	813
Reclassification of foreign currency translation gains on net investment on disposal of foreign operations	(77)	0	0
Change in fair value of net investment hedges	0	(10)	(372)
Change in fair value of cash flow hedges	3	30	(57)
Reclassification to net income of gains and losses on cash flow hedges	(2)	42	88
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(11)	(26)	51
Reclassification of actuarial loss and prior service costs on pension and other post-retirement benefit plans	16	16	32
Other comprehensive (loss)/income on equity investments	(106)	(87)	47
Other comprehensive (loss)/income (Note 22)	(926)	(32)	602
Comprehensive Income/(Loss)	2,469	453	(538)
Comprehensive income attributable to non-controlling interests	83	241	312
Comprehensive Income/(Loss) Attributable to Controlling Interests	2,386	212	(850)
Preferred share dividends	160	109	94
Comprehensive Income/(Loss) Attributable to Common Shares	CAD 2,226	CAD 103	CAD (944)

Consolidated statement of cash

Consolidated statement of cash flows - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Generated from Operations
Net income/(loss)	CAD 3,395	CAD 485	CAD (1,140)
Depreciation and amortization	2,055	1,939	1,765
Goodwill and other asset impairment charges (Notes 8, 11 and 12)	1,257	1,388	3,745
Deferred income taxes (Note 16)	566	196	(102)
Deferred income taxes – U.S. Tax Reform (Note 16)	(804)	0	0
Income from equity investments (Note 9)	(773)	(514)	(440)
Distributions received from operating activities of equity investments (Note 9)	970	844	793
Employee post-retirement benefits funding, net of expense (Note 23)	(64)	(3)	44
(Gain)/loss on assets held for sale/sold (Notes 6 and 26)	(631)	833	125
Equity allowance for funds used during construction	(362)	(253)	(165)
Unrealized (gains)/losses on financial instruments	(149)	(149)	58
Other	43	55	47
(Increase)/decrease in operating working capital (Note 25)	(273)	248	(346)
Net cash provided by operations	5,230	5,069	4,384
Investing Activities
Capital expenditures (Note 4)	(7,383)	(5,007)	(3,918)
Capital projects in development (Note 4)	(146)	(295)	(511)
Contributions to equity investments (Notes 4 and 9)	(1,681)	(765)	(493)
Acquisitions, net of cash acquired	0	(13,608)	(236)
Proceeds from sale of assets, net of transaction costs	5,317	6	0
Other distributions from equity investments (Note 9)	362	727	9
Deferred amounts and other	(168)	159	270
Net cash used in investing activities	(3,699)	(18,783)	(4,879)
Financing Activities
Notes payable issued/(repaid), net	1,038	(329)	(1,382)
Long-term debt issued, net of issue costs	3,643	12,333	5,045
Long-term debt repaid	(7,085)	(7,153)	(2,105)
Junior subordinated notes issued, net of issue costs	3,468	1,549	917
Dividends on common shares	(1,339)	(1,436)	(1,446)
Dividends on preferred shares	(155)	(100)	(92)
Distributions paid to non-controlling interests	(283)	(279)	(224)
Common shares issued, net of issue costs	274	7,747	27
Common shares repurchased (Note 20)	0	(14)	(294)
Preferred shares issued, net of issue costs	0	1,474	243
Partnership units of TC PipeLines, LP issued, net of issue costs	225	215	55
Common units of Columbia Pipeline Partners LP acquired	(1,205)	0	0
Net cash (used in)/provided by financing activities	(1,419)	14,007	744
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(39)	(127)	112
Increase in Cash and Cash Equivalents	73	166	361
Cash and Cash Equivalents, Beginning of year	1,016	850	489
Cash and Cash Equivalents, End of year	CAD 1,089	CAD 1,016	CAD 850

Consolidated balance sheet

Consolidated balance sheet - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	CAD 1,089	CAD 1,016
Accounts receivable	2,522	2,075
Inventories	378	368
Assets held for sale	0	3,717
Other (Note 7)	691	908
Total Current Assets	4,680	8,084
Plant, Property and Equipment (Note 8)	57,277	54,475
Equity Investments (Note 9)	6,366	6,544
Regulatory Assets (Note 10)	1,376	1,322
Goodwill (Note 11)	13,084	13,958
Loan Receivable from Affiliate (Note 9)	919	0
Intangible and Other Assets (Note 12)	1,484	3,026
Restricted Investments	915	642
Total Assets	86,101	88,051
Current Liabilities
Notes payable (Note 13)	1,763	774
Accounts payable and other (Note 14)	4,057	3,861
Dividends payable	586	526
Accrued interest	605	595
Liabilities related to assets held for sale	0	86
Current portion of long-term debt (Note 17)	2,866	1,838
Total Current Liabilities	9,877	7,680
Regulatory Liabilities (Note 10)	4,321	2,121
Other Long-Term Liabilities (Note 15)	727	1,183
Deferred Income Tax Liabilities (Note 16)	5,403	7,662
Long-Term Debt (Note 17)	31,875	38,312
Junior Subordinated Notes (Note 18)	7,007	3,931
Total Liabilities	59,210	60,889
Common Units Subject to Rescission or Redemption (Note 19)	0	1,179
EQUITY
Common shares, no par value (Note 20)	21,167	20,099
Preferred shares (Note 21)	3,980	3,980
Additional paid-in capital	0	0
Retained earnings	1,623	1,138
Accumulated other comprehensive loss (Note 22)	(1,731)	(960)
Controlling Interests	25,039	24,257
Non-controlling interests (Note 19)	1,852	1,726
Total Equity	26,891	25,983
Total Liabilities and Equity	CAD 86,101	CAD 88,051

Consolidated balance sheet (Par

Consolidated balance sheet (Parenthetical) - shares shares in Millions	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common shares issued (in shares)	881	864
Common shares outstanding (in shares)	881	864

Consolidated statement of equit

Consolidated statement of equity - CAD 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, 2014			CAD 12,202	CAD 2,255	CAD 370	CAD 5,478	CAD (1,235)	CAD 1,583
Shares issued:
Shares issued under public offering, net of issue costs				244
On exercise of stock options			30
Shares repurchased			(130)		(164)
Issuance of stock options, net of exercises					8
Dilution from TC PipeLines, LP units issued					6			55
Asset drop downs to TC PipeLines, LP					(213)
Columbia Pipeline Partners LP acquisition								(11)
Net income/(loss) attributable to controlling interests	CAD (1,146)					(1,146)
Common share dividends						(1,471)
Preferred share dividends						(92)
Other comprehensive (loss)/income attributable to controlling interests (Note 22)	602						296
Net income attributable to non-controlling interests	(6)							6
Other comprehensive (loss)/income attributable to non-controlling interests								306
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					6			55
Decrease in TransCanada's ownership of TC PipeLines, LP								(11)
Distributions declared to non-controlling interests								(222)
Balance at end of year at Dec. 31, 2015	18,155	CAD 16,438	12,102	2,499	7	2,769	(939)	1,717
Shares issued:
Shares issued under public offering, net of issue costs			7,752	1,481
Under dividend reinvestment and share purchase plan			177
On exercise of stock options			74
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/(loss) 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 (loss)/income attributable to controlling interests (Note 22)	(32)						(21)
Acquisition of non-controlling interests in Columbia Pipeline Partners LP								1,051
Net income attributable to non-controlling interests	(252)							252
Other comprehensive (loss)/income 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)
Reclassification from/(to) common units subject to rescission or redemption (Note 19)								(1,179)
Distributions declared to non-controlling interests								(279)
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 dividend reinvestment and share purchase plan			790
Under at-the-market equity issuance program, net of issue costs			216
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/(loss) 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 (loss)/income attributable to controlling interests (Note 22)	(926)						(771)
Net income attributable to non-controlling interests	(238)							238
Other comprehensive (loss)/income 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)
Reclassification from/(to) common units subject to rescission or redemption (Note 19)								106
Distributions declared to non-controlling interests								(280)
Impact of Columbia Pipeline Partners LP acquisition								33
Balance at end of year at Dec. 31, 2017	CAD 26,891	CAD 25,039	CAD 21,167	CAD 3,980	CAD 0	1,623	CAD (1,731)	CAD 1,852
Shares issued:
Adjustment related to employee share-based payments (Note 3)						CAD 12

DESCRIPTION OF TRANSCANADA'S BU

DESCRIPTION OF TRANSCANADA'S BUSINESS	12 Months Ended
	Dec. 31, 2017
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 which is non-operational, consisting of corporate and administrative functions. Canadian Natural Gas Pipelines The Canadian Natural Gas Pipelines segment consists of the Company's investments in 40,429 km ( 25,121 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 49,779 km ( 30,931 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 1,680 km ( 1,044 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 11 power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These include assets in Alberta, Ontario, Québec, New Brunswick and Arizona.

ACCOUNTING POLICIES

ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
ACCOUNTING POLICIES	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. Significant estimates and judgments used in the preparation of the consolidated financial statements include, but are not limited to: • fair value of assets and liabilities acquired in a business combination (Note 5) • fair value and depreciation rates of plant, property and equipment (Note 8) • carrying value of regulatory assets and liabilities (Note 10) • fair value of goodwill (Note 11) • fair value of intangible assets (Note 12) • 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 • provision 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) or the Alberta Energy Regulator (AER). 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. 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 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. Revenue Recognition Natural Gas Pipelines and Liquids Pipelines Capacity Arrangements and Transportation Revenues from the Company's natural gas and liquids pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made. Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline tolls are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines generally are 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 rates. The Company's Canadian natural gas pipelines, at times, are subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues on firm contracted capacity are recognized ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenues are recorded when the NEB decision is received. The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. 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. Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and recognized ratably over the contract period. Other volumes shipped on these pipelines are subject to CRE-approved tariffs. The Company does not take ownership of the natural gas that it transports for its customers. Regulated Natural Gas Storage Revenues from the Company's regulated natural gas storage services are recognized either ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, or when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the natural gas that it stores for its customers. Midstream and Other 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 contract period regardless of the amount of natural gas that is subject to these services. The Company also owns mineral rights associated with certain storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest. Royalties from mineral interests are recognized when commodities are produced. Energy Power Generation Revenues from the Company's Energy business are primarily derived from the sale of electricity, which is recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative instruments and hedging activities policy in this note. Non-Regulated Natural Gas Storage Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded net of the cost of the proprietary natural gas in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues. 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 natural gas inventory in storage, crude oil in transit, materials and supplies including spare parts and fuel. 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. Depreciation expense is no longer recorded once an asset is classified as held for sale. 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 six 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 a 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. When the asset is ready for its intended use and available for operations, capitalized project costs are depreciated in accordance with the Company's plant, property and equipment depreciation policies. Impairment of Long-Lived Assets The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets 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 or the estimated selling price 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. 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 first step of a two- step impairment test is performed by comparing the fair value of the reporting unit to its carrying value, which includes goodwill. If the fair value of the reporting unit is less than its carrying value, an impairment is indicated and the second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference. The Company can elect to move directly to the first step of the two-step impairment test for any of its reporting units when performing its annual impairment test. 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 were subleased to third parties under terms and conditions similar to the PPAs, and were 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 during 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. D eferred 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. 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. 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. These estimates 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. 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/(loss) (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/(loss) (AOCI) and into net income over the 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 effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in net income in the same financial statement category as the underlying transaction. 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 effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in net income. 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 the 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 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 increa

ACCOUNTING CHANGES

ACCOUNTING CHANGES	12 Months Ended
	Dec. 31, 2017
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES Changes in Accounting Policies for 2017 Inventory In July 2015, the Financial Accounting Standards Board (FASB) issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this guidance at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Company's Consolidated balance sheet. Derivatives and hedging In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks of their debt hosts. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements. Equity method investments In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements. Employee share-based payments In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. The Company has elected to account for forfeitures when they occur. This new guidance was effective January 1, 2017 and resulted in a cumulative-effect adjustment of $12 million to retained earnings and the recognition of a deferred tax asset related to employee share-based payments that were made prior to the adoption of this guidance. Consolidation In October 2016, the FASB issued new guidance on consolidation relating to VIEs held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to the Company's consolidation conclusions. Future Accounting Changes Revenue from contracts with customers In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Company will adopt the new guidance on the effective date of January 1, 2018. There are two methods in which the new guidance can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Company will adopt the guidance using the modified retrospective approach with the cumulative-effect of the adjustment, if any, recognized at the date of adoption, subject to allowable and elected practical expedients. The Company identified all existing customer contracts that are within the scope of the new guidance by operating segment. The Company has completed its analysis of the contracts and has not identified any material differences in the amount and timing of revenue recognition as a result of implementing the new guidance. Therefore, the Company will not require a cumulative-effect adjustment to opening retained earnings on January 1, 2018. Although consolidated revenues will not be materially impacted by the new guidance, the Company will be required to add significant disclosures based on the prescribed requirements. These new disclosures will include information regarding the significant judgments used in evaluating when and how revenues, are recognized and information related to contract assets and deferred revenues. In addition, the new guidance requires that the Company’s revenue recognition policy disclosure include additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenues and cash flows generated from contracts with customers. The Company has developed draft disclosures required in first quarter 2018 with a particular focus on the scope of contracts subject to disclosure of future revenues from remaining performance obligations. The Company has addressed system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. Financial instruments In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in the fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018 and a method of adoption is specified for each component of the guidance. The Company has completed its analysis and does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the lessor to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for an arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is continuing to identify and analyze existing lease agreements to determine the effect of application of the new guidance on its consolidated financial statements. The Company is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance and continues to monitor and analyze additional guidance and clarification provided by the FASB. Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Income taxes In October 2016, the FASB issued new guidance on the income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied using a modified retrospective approach. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. Restricted cash In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents balance, and amounts generally described as restricted cash or restricted cash equivalents. Restricted cash and cash equivalents will be included with Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively. Goodwill impairment In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating Step 2 of the impairment test, which is the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted. Employee post-retirement benefits In March 2017, the FASB issued new guidance that will require entities to disaggregate the current service cost component from the other components of net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance is effective January 1, 2018. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. Amortization on purchased callable debt securities In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Hedge accounting In August 2017, the FASB issued new guidance on hedge accounting, 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 additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019, with early adoption permitted. The Company has elected to apply this guidance effective January 1, 2018. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION year ended December 31, 2017 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,693 3,584 570 2,009 3,593 — 13,449 Intersegment revenues — 51 — — — (51 ) — 3,693 3,635 570 2,009 3,593 (51 ) 13,449 Income from equity investments 11 240 (9 ) (3 ) 471 63 2 773 Plant operating costs and other (1,300 ) (1,340 ) (42 ) (623 ) (550 ) (51 ) (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 assets held for sale/sold — — — — 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 other 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 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. 2 This Inc ome from equity investments relates to foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture. 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 Energy Corporate 1 Total (millions of Canadian $) Revenues 3,682 2,526 378 1,755 4,206 — 12,547 Intersegment revenues — 56 — — — (56 ) — 3,682 2,582 378 1,755 4,206 (56 ) 12,547 Income from equity investments 12 214 (3 ) (1 ) 292 — 514 Plant operating costs and other (1,245 ) (1,057 ) (43 ) (568 ) (884 ) (64 ) (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 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. year ended December 31, 2015 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,680 1,444 259 1,879 4,091 — 11,353 Intersegment revenues — 47 — — — (47 ) — 3,680 1,491 259 1,879 4,091 (47 ) 11,353 Income from equity investments 12 162 5 — 261 — 440 Plant operating costs and other (1,204 ) (606 ) (51 ) (492 ) (845 ) (105 ) (3,303 ) Commodity purchases resold — — — — (2,237 ) — (2,237 ) Property taxes (272 ) (77 ) — (79 ) (89 ) — (517 ) Depreciation and amortization (849 ) (248 ) (44 ) (283 ) (341 ) — (1,765 ) Asset impairment charges — — — (3,686 ) (59 ) — (3,745 ) Loss on assets held for sale/sold — (125 ) — — — — (125 ) Segmented earnings/(losses) 1,367 597 169 (2,661 ) 781 (152 ) 101 Interest expense (1,370 ) Allowance for funds used during construction 295 Interest income and other (132 ) Loss before income taxes (1,106 ) Income tax expense (34 ) Net loss (1,140 ) Net income attributable to non-controlling interests (6 ) Net loss attributable to controlling interests (1,146 ) Preferred share dividends (94 ) Net loss attributable to common shares (1,240 ) Capital spending Capital expenditures 1,366 534 566 1,012 376 64 3,918 Capital projects in development 230 3 — 278 — — 511 Contributions to equity investments — — — 311 182 — 493 1,596 537 566 1,601 558 64 4,922 1 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. at December 31 2017 2016 (millions of Canadian $) Total Assets Canadian Natural Gas Pipelines 16,904 15,816 U.S. Natural Gas Pipelines 35,898 34,422 Mexico Natural Gas Pipelines 5,716 5,013 Liquids Pipelines 15,438 16,896 Energy 8,503 13,169 Corporate 3,642 2,735 86,101 88,051 Geographic Information year ended December 31 2017 2016 2015 (millions of Canadian $) Revenues Canada – domestic 3,618 3,697 3,930 Canada – export 1,255 1,177 1,292 United States 8,006 7,295 5,872 Mexico 570 378 259 13,449 12,547 11,353 at December 31 2017 2016 (millions of Canadian $) Plant, Property and Equipment Canada 21,632 20,531 United States 30,693 29,414 Mexico 4,952 4,530 57,277 54,475

ACQUISITION OF COLUMBIA

ACQUISITION OF COLUMBIA	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
ACQUISITION OF COLUMBIA	ACQUISITION OF COLUMBIA On July 1, 2016 , TransCanada acquired 100 per cent ownership of Columbia Pipeline Group, Inc. (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 17, Long-term debt and Note 20, Common shares for further information on the acquisition bridge facilities and the subscription receipts, respectively. 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. Canadian 1 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 (Note 11) 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 ). This adjustment did not impact the Company's net income. At December 31, 2017, goodwill related to the acquisition of Columbia is US$7,802 million (2016 – US$7,747 million ). Refer to Note 11, Goodwill, for further information. 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 U.S. effective tax rate of 39 per cent . The fair value of Columbia’s non-controlling interest was based on the approximately 53.8 million Columbia Pipeline Partners LP (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 )

ASSETS HELD FOR SALE

ASSETS HELD FOR SALE	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
ASSETS HELD FOR SALE	ASSETS HELD FOR SALE U.S. Northeast Power Assets The Company's monetization of its U.S. Northeast power assets, for the purpose of permanently financing the Columbia acquisition, included the sales of TC Hydro, Ravenswood, Ironwood, Kibby Wind and Ocean State Power that closed in second quarter 2017. On November 1, 2016 , the Company entered into an agreement to sell TC Hydro to a third party. At December 31, 2016, the related assets and liabilities were classified as held for sale in the Energy segment. On April 19, 2017, the Company completed the sale of TC Hydro for proceeds of approximately US$1.07 billion , before post-closing adjustments. Refer to Note 26, Other acquisitions and dispositions, for further information. On November 1, 2016 , the Company entered into an agreement to sell Ravenswood, Ironwood, Kibby Wind and Ocean State Power to a third party. As a result, the Company recorded a loss of approximately $829 million ( $863 million after tax) in 2016 which was included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income. This included the impact of an estimated $70 million of foreign currency translation gains to be reclassified from AOCI to net income on close. At December 31, 2016, the related assets and liabilities were classified as held for sale in the Energy segment and were recorded at their fair values less costs to sell based on the proceeds expected from the sale. On June 2, 2017, TransCanada completed the sale of these assets for proceeds of approximately US$2.029 billion , before post-closing adjustments. Refer to Note 26, Other acquisitions and dispositions, for further information.

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2017
Other Assets [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS at December 31 2017 2016 (millions of Canadian $) Fair value of derivative contracts (Note 24) 332 376 Prepaid expenses 109 131 Cash provided as collateral 99 313 Regulatory assets (Note 10) 23 33 Other 128 55 691 908

PLANT, PROPERTY AND EQUIPMENT

PLANT, PROPERTY AND EQUIPMENT	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
PLANT, PROPERTY AND EQUIPMENT	PLANT, PROPERTY AND EQUIPMENT 2017 2016 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 10,153 4,190 5,963 8,814 3,951 4,863 Compression 3,021 1,593 1,428 2,447 1,499 948 Metering and other 1,188 569 619 1,124 519 605 14,362 6,352 8,010 12,385 5,969 6,416 Under construction 940 — 940 1,151 — 1,151 15,302 6,352 8,950 13,536 5,969 7,567 Canadian Mainline Pipeline 9,763 6,455 3,308 9,502 6,221 3,281 Compression 3,605 2,499 1,106 3,537 2,361 1,176 Metering and other 655 207 448 605 198 407 14,023 9,161 4,862 13,644 8,780 4,864 Under construction 156 — 156 219 — 219 14,179 9,161 5,018 13,863 8,780 5,083 Other Canadian Natural Gas Pipelines Other 1 1,815 1,363 452 1,728 1,273 455 Under construction 4 — 4 112 — 112 1,819 1,363 456 1,840 1,273 567 31,300 16,876 14,424 29,239 16,022 13,217 U.S. Natural Gas Pipelines Columbia Gas Pipeline 3,550 125 3,425 3,317 42 3,275 Compression 1,547 64 1,483 1,636 29 1,607 Metering and other 2,306 37 2,269 2,550 8 2,542 7,403 226 7,177 7,503 79 7,424 Under construction 3,332 — 3,332 1,127 — 1,127 10,735 226 10,509 8,630 79 8,551 ANR Pipeline 1,427 365 1,062 1,468 349 1,119 Compression 1,582 286 1,296 1,494 260 1,234 Metering and other 961 268 693 988 254 734 3,970 919 3,051 3,950 863 3,087 Under construction 358 — 358 232 — 232 4,328 919 3,409 4,182 863 3,319 2017 2016 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,107 822 1,285 2,221 810 1,411 Great Lakes 1,988 1,113 875 2,106 1,155 951 Columbia Gulf 1,115 37 1,078 880 5 875 Midstream 1,085 54 1,031 1,072 23 1,049 Other 2 1,950 574 1,376 2,120 567 1,553 8,245 2,600 5,645 8,399 2,560 5,839 Under construction 699 — 699 346 — 346 8,944 2,600 6,344 8,745 2,560 6,185 24,007 3,745 20,262 21,557 3,502 18,055 Mexico Natural Gas Pipelines Pipeline 2,486 214 2,272 2,734 180 2,554 Compression 388 30 358 422 19 403 Metering and other 522 65 457 502 40 462 3,396 309 3,087 3,658 239 3,419 Under construction 1,865 — 1,865 1,108 — 1,108 5,261 309 4,952 4,766 239 4,527 Liquids Pipelines Keystone Pipeline System Pipeline 9,002 992 8,010 10,572 901 9,671 Pumping equipment 1,022 152 870 928 121 807 Tanks and other 3,314 385 2,929 2,521 286 2,235 13,338 1,529 11,809 14,021 1,308 12,713 Under construction 456 — 456 479 — 479 13,794 1,529 12,265 14,500 1,308 13,192 Intra-Alberta Pipelines 3 Pipeline 748 3 745 — — — Pumping equipment 104 — 104 — — — Tanks and other 259 1 258 — — — 1,111 4 1,107 — — — Under construction 47 — 47 955 — 955 1,158 4 1,154 955 — 955 14,952 1,533 13,419 15,455 1,308 14,147 Energy Natural Gas 4,5 2,645 743 1,902 2,696 696 2,000 Wind and Solar 6 673 204 469 1,180 245 935 Natural Gas Storage and Other 734 156 578 731 146 585 4,052 1,103 2,949 4,607 1,087 3,520 Under construction 1,028 — 1,028 729 — 729 5,080 1,103 3,977 5,336 1,087 4,249 Corporate 411 168 243 410 130 280 81,011 23,734 57,277 76,763 22,288 54,475 1 Includes Foothills, Ventures LP and Great Lakes Canada . 2 Includes Bison, Portland Natural Gas Transmission System, North Baja, Tuscarora and Crossroads. 3 Includes Northern Courier, placed in-service on November 1, 2017 and White Spruce. 4 Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities was $ 1,264 million and $ 354 million , respectively, at December 31, 2017 ( 2016 – $ 1,319 million and $ 335 million , respectively). Revenues of $ 215 million were recognized in 2017 ( 2016 – $ 212 million ; 2015 – $ 235 million ) through the sale of electricity under the related PPAs. 5 Includes Coolidge, Grandview, and Bécancour assets which operate under operating leases, along with Halton Hills and Alberta cogeneration natural gas-fired facilities. 6 Ontario solar assets are excluded from the Wind and Solar net book value at December 31, 2017 as they were sold on December 19, 2017. Refer to Note 26, Other acquisitions and dispositions, for further information. 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 Following the evaluation of specific capital project opportunities in 2015, it was determined that the carrying value of certain Energy turbine equipment was not fully recoverable. These turbines had been previously purchased for a power development project that did not proceed. As a result, at December 31, 2015 , the Company recognized a non-cash impairment charge of $ 59 million ($ 43 million after tax) in the Energy segment. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. This impairment charge was based on the excess of the carrying value over the estimated fair value of the turbines, which was determined based on a comparison to similar assets available for sale in the market. At December 31, 2017, the Company again re-assessed the remaining carrying value of this Energy turbine equipment and determined that it was not recoverable. As a result, 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. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. Keystone XL Impairment At December 31, 2015 , the Company evaluated its investment in Keystone XL and related projects for impairment in connection with the November 6, 2015 denial of the U.S. Presidential permit. As a result of the analysis, the Company recognized a non-cash impairment charge in its Liquids Pipelines segment of $ 3,686 million ($ 2,891 million after tax) based on the excess of the carrying value over the estimated fair value of $621 million of these assets. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income.

EQUITY INVESTMENTS

EQUITY INVESTMENTS	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	EQUITY INVESTMENTS (millions of Canadian $) Ownership Income/(Loss) from Equity Investments Equity Investments year ended December 31 at December 31 2017 2016 2015 2017 2016 Canadian Natural Gas Pipelines TQM 50.0 % 11 12 12 68 71 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 87 92 85 641 597 Iroquois 2 50.0 % 59 54 51 280 309 Millennium 3 47.5 % 66 33 — 291 295 Pennant Midstream 3 47.0 % 11 6 — 228 246 Other Various 17 29 26 92 93 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % 66 (3 ) — 399 255 TransGas 46.5 % (12 ) — 5 — 28 Liquids Pipelines Grand Rapids 5 50.0 % 17 (1 ) — 996 876 Other 6 Various (20 ) — — 20 39 Energy Bruce Power 7 48.4 % 434 293 249 2,987 3,356 Portlands Energy 8 50.0 % 31 33 30 301 313 ASTC Power Partnership 50.0 % — (37 ) (23 ) — — Other Various 6 3 5 63 66 773 514 440 6,366 6,544 1 At December 31, 2017 , 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 ( 2016 – US$116 million ) due to the fair value assessment of assets at the time of acquisition. 2 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million ( 2016 – US$48 million ) due mainly to the fair value assessment of the assets at the time of acquisition. 3 Acquired as part of 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 amounts recorded in the Corporate segment. 5 Grand Rapids was placed in service in August 2017. At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $105 million ( 2016 – $86 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, 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil . 7 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $902 million ( 2016 – $942 million ) due to the fair value assessment of assets at the time of acquisitions. 8 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million ( 2016 – $70 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 impairment charge represents the write-down of the remaining carrying value of the equity investment. The non-cash impairment charge 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 its Liquids Pipelines segment Income from equity investments 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, 2017 were $ 1,332 million ( 2016 – $ 1,571 million ; 2015 – $ 802 million ) of which $ 362 million ( 2016 – $ 727 million ; 2015 – $ 9 million ) was included in Investing activities in the Consolidated statement of cash flows with respect to distributions received from Bruce Power in 2017 and 2016 from its financing program. Undistributed earnings from equity investments were $ 198 million at December 31, 2015 . Contributions made to equity investments for the year ended December 31, 2017 were $ 1,681 million ( 2016 – $ 765 million ; 2015 – $ 493 million ) and are included in Investing activities in the Consolidated statement of cash flows. For 2017, contributions include $ 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 2017 2016 2015 (millions of Canadian $) Income Revenues 4,913 4,336 4,337 Operating and other expenses (2,993 ) (3,068 ) (3,142 ) Net income 1,636 1,080 1,046 Net income attributable to TransCanada 773 514 440 at December 31 2017 2016 (millions of Canadian $) Balance Sheet Current assets 2,176 1,669 Non-current assets 17,869 15,853 Current liabilities (1,577 ) (1,120 ) Non-current liabilities (8,217 ) (5,867 ) 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. On April 21, 2017, TransCanada entered into a MXN$13.6 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. On December 6, 2017, TransCanada and the joint venture entered into an amended agreement to increase the credit facility to MXN$21.3 billion . At December 31, 2017 , the Company’s consolidated balance sheet included a $919 million loan receivable from the Sur de Texas joint venture which represents TransCanada’s proportionate share of the debt financing requirements related to the joint venture. Interest income and other included interest income of $34 million in 2017 from this joint venture with a corresponding proportionate share of interest expense recorded in Income from equity investments.

RATE-REGULATED BUSINESSES

RATE-REGULATED BUSINESSES	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
RATE-REGULATED BUSINESSES	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 The NGTL System’s 2017 and 2016 results reflect the terms of the 2016-2017 Revenue Requirement Settlement approved by the NEB in April 2016. This settlement includes an ROE of 10.1 per cent on 40 per cent deemed equity, a composite depreciation rate of approximately 3.16 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. The NGTL System’s 2015 results reflect the terms of the 2015 Revenue Requirement Settlement. This one -year settlement included a 10.1 per cent ROE on deemed common equity of 40 per cent , a composite depreciation rate of approximately 3.1 per cent , a mechanism for sharing variances above and below a fixed annual 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 continued 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 six -year fixed toll term of the NEB 2014 Decision. As directed by the NEB, the Canadian Mainline filed an application for approval of 2018-2020 tolls on December 18, 2017. 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. 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. ANR Pipeline Company ANR Pipeline Company previously operated under rates established pursuant to a settlement approved by the FERC that was effective for all periods presented beginning in 1997 through July 31, 2016. Effective August 1, 2016, ANR Pipeline Company began operating under new rates pursuant to a FERC-approved rate settlement in September 2016. Under terms of the September 2016 settlement, neither ANR Pipeline Company nor the settling parties can file for new rates to become effective earlier than August 1, 2019. However, ANR Pipeline Company is required to file for new rates to be effective no later than August 1, 2022. Great Lakes On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its previous 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, if approved by FERC, will result in a decrease in Great Lakes' maximum transportation rates effective October 1, 2017. The 2017 Great Lakes Settlement does not contain any 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. Columbia Gulf Columbia Gulf’s natural gas transportation services are provided under a tariff at rates subject to FERC approval. In September 2016, the 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 requires 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. Mexico Regulated Operations TransCanada's Mexico natural gas pipelines operations 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. Regulatory Assets and Liabilities at December 31 2017 2016 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 967 861 n/a Deferred income taxes – U.S. Tax Reform 2 (27 ) — n/a Operating and debt-service regulatory assets 3 — 1 1 Pensions and other post-retirement benefits 1,4 388 382 n/a Foreign exchange on long-term debt 1,5 — 37 1-12 Other 71 74 n/a 1,399 1,355 Less: Current portion included in Other current assets (Note 7) 23 33 1,376 1,322 Regulatory Liabilities Operating and debt-service regulatory liabilities 3 188 47 1 Pensions and other post-retirement benefits 4 164 180 n/a ANR related post-employment and retirement benefits other than pension 6 66 141 n/a Long term adjustment account 7 1,142 659 46 Pipeline abandonment trust balance 825 541 n/a Bridging amortization account 7 202 451 13 Cost of removal 8 216 226 n/a Deferred income taxes 75 — n/a Deferred income taxes – U.S. Tax Reform 2 1,659 — n/a Other 47 54 n/a 4,584 2,299 Less: Current portion included in Accounts payable and other (Note 14) 263 178 4,321 2,121 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 These balances represent the impact of U.S. Tax Reform. The regulatory assets and regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax assets and liabilities that gave rise to the regulatory assets and liabilities. See Note 16, Income taxes, for further information. 3 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar years. 4 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 customers in future rates. 5 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. 6 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, $26 million ( US$21 million ) of the regulatory liability balance at December 31, 2017 (2016 – $46 million , US$34 million ) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $40 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. 7 These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. 8 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 subsidiaries for future costs to be incurred.

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL The Company has recorded the following Goodwill on its acquisitions in the U.S.: (millions of Canadian $) U.S. Natural Gas Pipelines Energy Total Balance at January 1, 2016 3,667 1,145 4,812 Acquisition of Columbia (Note 5) 10,078 — 10,078 Impairment charge — (1,085 ) (1,085 ) Foreign exchange rate changes 213 (60 ) 153 Balance at December 31, 2016 13,958 — 13,958 Columbia adjustment (Note 5) 71 — 71 Foreign exchange rate changes (945 ) — (945 ) Balance at December 31, 2017 13,084 — 13,084 At December 31, 2017 , 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. Assumptions used in the analysis regarding Great Lakes’ ability to realize long-term value in the North American energy market included the reduction in Great Lakes' rates effective October 1, 2017 as a result of the expected outcome of the 2017 Great Lakes Settlement. The reduction in rates was offset by expected cash flows from the long-term transportation contract with the Canadian Mainline, other opportunities to increase utilization on the system and the 2017 Great Lakes Settlement's elimination of the revenue sharing mechanism with its customers. 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 relating to Great Lakes. The goodwill balance related to Great Lakes at December 31, 2017 was US$573 million ( 2016 – US$573 million ). 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 approach 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

INTANGIBLE AND OTHER ASSETS	12 Months Ended
	Dec. 31, 2017
Intangible Assets, Net (Excluding Goodwill) [Abstract]
INTANGIBLE AND OTHER ASSETS	INTANGIBLE AND OTHER ASSETS at December 31 2017 2016 (millions of Canadian $) Capital projects in development 596 2,094 Deferred income tax assets (Note 16) 316 392 Employee post-retirement benefits (Note 23) 193 189 Fair value of derivative contracts (Note 24) 73 133 Other 306 218 1,484 3,026 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, are 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 issued notice to the Balancing Pool of the decision to terminate 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. 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 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. Upon final settlement of the PPA terminations 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. Amortization expense of $ 9 million was recognized in the Consolidated statement of income for the year ended December 31, 2016 ( 2015 – $ 52 million ), prior to the termination of the PPAs.

NOTES PAYABLE

NOTES PAYABLE	12 Months Ended
	Dec. 31, 2017
Short-term Debt [Abstract]
NOTES PAYABLE	NOTES PAYABLE 2017 2016 (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 Canadian 884 1.6 % 509 0.9 % U.S. (2017 – US$688; 2016 – US$197) 862 2.2 % 265 0.5 % MXN (2017 – MXN$275) 17 8.0 % — — 1,763 774 At December 31, 2017 , Notes payable consists of short-term borrowing by TransCanada PipeLines Limited (TCPL), TransCanada American Investments Ltd. (TAIL), TransCanada PipeLine USA Ltd. (TCPL USA), Columbia and a Mexican subsidiary. At December 31, 2017 , total committed revolving and demand credit facilities were $ 11.0 billion ( 2016 – $11.1 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) 2017 2016 Borrower Description Matures Total Facilities Unused Capacity Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 1 : TCPL Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes December 2022 3.0 3.0 3.0 TCPL Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes December 2018 US 2.0 US 2.0 US 2.0 TCPL USA Used for TCPL USA general corporate purposes, guaranteed by TCPL December 2018 US 1.0 US 0.6 US 1.0 Columbia Used for Columbia general corporate purposes, guaranteed by TCPL December 2018 US 1.0 US 1.0 US 1.0 TAIL Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL December 2018 US 0.5 US 0.5 US 0.5 Demand senior unsecured revolving credit facilities 1 : TCPL/TCPL USA Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL Demand 1.9 0.5 1.9 Mexican subsidiary Used for Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 MXN 4.7 — 1 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, 2017, the Company was in compliance with all debt covenants. For the year ended December 31, 2017, the cost to maintain the above facilities was $ 7 million (2016 – $ 10 million ; 2015 – $ 11 million ). At December 31, 2017, the Company's operated affiliates had an additional $ 0.4 billion (2016 – $ 0.5 billion ) of undrawn capacity on committed credit facilities.

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2017
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER at December 31 2017 2016 (millions of Canadian $) Trade payables 2,847 2,443 Fair value of derivative contracts (Note 24) 387 607 Unredeemed shares of Columbia 312 317 Regulatory liabilities (Note 10) 263 178 Other 248 316 4,057 3,861

OTHER LONG-TERM LIABILITIES

OTHER LONG-TERM LIABILITIES	12 Months Ended
	Dec. 31, 2017
Deferred Costs, Noncurrent [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES at December 31 2017 2016 (millions of Canadian $) Employee post-retirement benefits (Note 23) 389 448 Fair value of derivative contracts (Note 24) 72 330 Asset retirement obligations 98 108 Guarantees (Note 27) 16 82 Other 152 215 727 1,183

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
INCOME TAXES	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, 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 deferred income tax expense of $816 million . 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 on the Consolidated balance sheet in the amount of $1,686 million . Net deferred income tax liabilities related to the cumulative remeasurements of employee post-retirement benefits included in AOCI have been adjusted with a corresponding increase in deferred income tax expense of $12 million . Given the significance of the legislation, the Securities and Exchange Commission (SEC) staff issued guidance which allows registrants to record provisional amounts which may be adjusted as information becomes available, prepared or analyzed during a measurement period not to exceed one year. The SEC guidance summarizes 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 considers all amounts recorded related to U.S. Tax Reform to be reasonable estimates. Amounts related to businesses subject to RRA are provisional as the Company’s interpretation, assessment and presentation of the impact of the tax law change, may be further clarified with additional guidance from regulatory, tax and accounting authorities. Should additional guidance be provided by these authorities or other sources during the one-year measurement period, TransCanada will review the provisional amounts and adjust as appropriate. Provision for Income Taxes year ended December 31 2017 2016 2015 (millions of Canadian $) Current Canada 113 116 44 Foreign 36 40 92 149 156 136 Deferred Canada (185 ) 101 33 Foreign 751 95 (135 ) Foreign – U.S. Tax Reform (804 ) — — (238 ) 196 (102 ) Income Tax (Recovery)/Expense (89 ) 352 34 Geographic Components of Income/(Loss) before Income Taxes year ended December 31 2017 2016 2015 (millions of Canadian $) Canada (339 ) 219 (624 ) Foreign 3,645 618 (482 ) Income/(Loss) before Income Taxes 3,306 837 (1,106 ) Reconciliation of Income Tax (Recovery)/Expense year ended December 31 2017 2016 2015 (millions of Canadian $) Income/(loss) before income taxes 3,306 837 (1,106 ) Federal and provincial statutory tax rate 27 % 27 % 26 % Expected income tax expense/(recovery) 893 226 (288 ) U.S. Tax Reform (804 ) — — Foreign income tax rate differentials (81 ) (196 ) 14 Income from equity investments and non-controlling interests (64 ) (68 ) (56 ) Income tax differential related to regulated operations (42 ) 81 159 Non-taxable portion of capital gains (42 ) — — Asset impairment charges 1 34 242 170 Non-deductible amounts 4 46 — Tax rate and legislative changes — — 34 Other 13 21 1 Income Tax (Recovery)/Expense (89 ) 352 34 1 Net of nil (2016 – $112 million ; 2015 – $311 million ) attributed to higher foreign tax rates. Deferred Income Tax Assets and Liabilities at December 31 2017 2016 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,379 2,063 Difference in accounting and tax bases of impaired assets and assets held for sale 651 1,168 Regulatory and other deferred amounts 512 277 Unrealized foreign exchange losses on long-term debt 216 446 Financial instruments 10 34 Other 227 352 2,995 4,340 Less: valuation allowance 832 1,336 2,163 3,004 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 6,240 9,015 Equity investments 632 905 Taxes on future revenue requirement 238 198 Other 140 156 7,250 10,274 Net Deferred Income Tax Liabilities 5,087 7,270 The above deferred tax amounts have been classified in the Consolidated balance sheet as follows: at December 31 2017 2016 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 12) 316 392 Deferred Income Tax Liabilities Deferred income tax liabilities 5,403 7,662 Net Deferred Income Tax Liabilities 5,087 7,270 At December 31, 2017 , the Company has recognized the benefit of unused non-capital loss carryforwards of $1,280 million ( 2016 – $1,786 million ) for federal and provincial purposes in Canada, which expire from 2030 to 2037. The Company has no t recognized the benefit of capital loss carry forwards of $668 million (2016 – $654 million ) for federal and provincial purposes in Canada. The Company also has Ontario minimum tax credits of $82 million (2016 – $68 million ), which expire from 2026 to 2037. At December 31, 2017 , the Company has recognized the benefit of unused net operating loss carryforwards of US$1,800 million ( 2016 – US$2,545 million ) for federal purposes in the U.S., which expire from 2028 to 2037. The Company has no t recognized the benefit of unused net operating loss carryforwards of US$710 million (2016 – US$58 million ) for federal purposes in the U.S. The Company also has alternative minimum tax credits of US$56 million (2016 – US$37 million ). At December 31, 2017 , the Company has recognized the benefit of unused net operating loss carryforwards of US$7 million (2016 – US$54 million ) in Mexico, which expire from 2024 to 2027. 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, 2017 by approximately $569 million ( 2016 – $481 million ) if there had been a provision for these taxes. Income Tax Payments Income tax payments of $247 million , net of refunds, were made in 2017 ( 2016 – payments, net of refunds, of $105 million ; 2015 – payments, net of refunds, of $162 million ). Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2017 2016 2015 (millions of Canadian $) Unrecognized tax benefit at beginning of year 18 17 18 Gross increases – tax positions in prior years — 3 2 Gross decreases – tax positions in prior years (1 ) — (2 ) Gross increases – tax positions in current year 2 2 1 Settlement — (1 ) — Lapse of statutes of limitations (4 ) (3 ) (2 ) Unrecognized Tax Benefit at End of Year 15 18 17 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 2009. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2010. 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, 2017 reflects nil of interest expense and nil for penalties ( 2016 – nil of interest expense and nil for penalties; 2015 – $ 1 million reversal of interest expense and nil for penalties). At December 31, 2017 , the Company had $ 4 million accrued for interest expense and nil accrued for penalties ( December 31, 2016 – $ 4 million accrued for interest expense and nil accrued for penalties).

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT 2017 2016 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Debentures Canadian 2018 to 2020 500 10.8 % 600 10.7 % U.S. (2017 and 2016 – US$400) 2021 501 9.9 % 537 9.9 % Medium Term Notes Canadian 2019 to 2047 6,504 4.9 % 5,804 4.6 % Senior Unsecured Notes U.S. (2017 – US$14,892; 2016 – US$14,642) 2018 to 2045 18,644 5.1 % 19,660 5.1 % Acquisition Bridge Facility (2017 – nil; 2016 – US$2,013) — — — 2,702 1.9 % 26,149 29,303 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2017 and 2016 – US$200) 2023 250 7.9 % 269 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2017 and 2016 – US$33) 2026 41 7.5 % 44 7.5 % 895 917 TRANSCANADA PIPELINE USA LTD. Acquisition Bridge Facility (2017 – nil; 2016 – US$1,700) — — — 2,283 1.9 % COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2017 and 2016 – US$2,750) 2 2018 to 2045 3,443 4.0 % 3,692 4.0 % TC PIPELINES, LP Unsecured Loan Facility U.S. (2017 – US$185; 2016 – US$160) 2021 232 2.7 % 215 1.9 % Unsecured Term Loan U.S. (2017 and 2016 – US$670) 3 2020 to 2022 839 2.7 % 899 1.9 % Senior Unsecured Notes U.S. (2017 – US$1,200; 2016 – US$700) 2021 to 2027 1,502 4.4 % 940 4.7 % 2,573 2,054 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2017 and 2016 – US$672) 2021 to 2026 842 7.2 % 903 7.2 % GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2017 – US$55; 2016 – US$65) 2019 69 1.1 % 87 1.6 % Senior Unsecured Notes U.S. (2017 and 2016 – US$250) 2020 to 2035 313 5.6 % 336 5.6 % 382 423 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2017 – US$259; 2016 – US$278) 2018 to 2030 324 7.7 % 373 7.7 % 2017 2016 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Secured Notes 4 U.S. (2017 – US$30; 2016 – US$53) 2018 38 6.0 % 71 6.0 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2017 – US$25; 2016 – US$10) 2020 31 1.1 % 13 1.9 % Senior Secured Notes U.S. (2017 – nil; 2016 – US$12) — — — 16 4.0 % 31 29 34,677 40,048 Current portion of long-term debt (2,866 ) (1,838 ) Unamortized debt discount and issue costs (174 ) (191 ) Fair value adjustments 5 238 293 31,875 38,312 1 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. 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$170 million and US$500 million term loan facilities were amended in September 2017 to extend the maturity dates from 2018 to 2020 and 2022, respectively. 4 These notes are secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements. 5 The fair value adjustments include $242 million (2016 – $293 million ) related to the acquisition of Columbia. Refer to Note 5, Acquisition of Columbia, for further information. The fair value adjustments also include a decrease of $4 million (2016 – nil ) related to hedged interest rate risk. Refer to Note 24, Risk management and financial instruments, for further information. Principal Repayments At December 31, 2017, principal repayments for the next five years on the Company's Long-term debt are approximately as follows: (millions of Canadian $) 2018 2019 2020 2021 2022 Principal repayments on long-term debt 2,866 3,189 2,834 2,085 1,929 Long-Term Debt Issued The Company issued long-term debt over the three years ended December 31, 2017 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 Facility 1 June 2018 US 5,213 Floating June 2016 Medium Term Notes July 2023 300 3.69 % 2 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 % November 2015 Senior Unsecured Notes November 2017 US 1,000 1.625 % October 2015 Medium Term Notes November 2041 400 4.55 % July 2015 Medium Term Notes July 2025 750 3.30 % March 2015 Senior Unsecured Notes March 2045 US 750 4.60 % January 2015 Senior Unsecured Notes January 2018 US 500 1.875 % January 2015 Senior Unsecured Notes January 2018 US 250 Floating TUSCARORA GAS TRANSMISSION COMPANY August 2017 Term Loan August 2020 US 25 Floating April 2016 Term Loan April 2019 US 10 Floating TC PIPELINES, LP May 2017 Senior Unsecured Notes May 2027 US 500 3.90 % September 2015 Unsecured Term Loan October 2018 US 170 Floating March 2015 Senior Unsecured Notes March 2025 US 350 4.375 % TRANSCANADA PIPELINE USA LTD. June 2016 Acquisition Bridge Facility 1 June 2018 US 1,700 Floating ANR PIPELINE COMPANY June 2016 Senior Unsecured Notes June 2026 US 240 4.14 % GAS TRANSMISSION NORTHWEST LLC June 2015 Unsecured Term Loan June 2019 US 75 Floating 1 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 the second quarter 2017. 2 Reflects coupon rate on re-opening of a pre-existing medium term notes (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, 2017 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED December 2017 Debentures 100 9.80 % November 2017 Senior Unsecured Notes US 1,000 1.625 % June 2017 Acquisition Bridge Facility 1 US 1,513 Floating February 2017 Acquisition Bridge Facility 1 US 500 Floating January 2017 Medium Term Notes 300 5.10 % November 2016 Acquisition Bridge Facility 1 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 % August 2015 Debentures 150 11.90 % June 2015 Senior Unsecured Notes US 500 3.40 % March 2015 Senior Unsecured Notes US 500 0.875 % January 2015 Senior Unsecured Notes US 300 4.875 % TUSCARORA GAS TRANSMISSION COMPANY August 2017 Senior Secured Notes US 12 3.82 % TRANSCANADA PIPELINE USA LTD. June 2017 Acquisition Bridge Facility 1 US 630 Floating April 2017 Acquisition Bridge Facility 1 US 1,070 Floating NOVA GAS TRANSMISSION LTD. February 2016 Debentures 225 12.20 % GAS TRANSMISSION NORTHWEST LLC June 2015 Senior Unsecured Notes US 75 5.09 % 1 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 the second quarter 2017. Interest Expense Interest expense in the three years ended December 31 was as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) Interest on long-term debt 1,794 1,765 1,487 Interest on junior subordinated notes 348 180 116 Interest on short-term debt 33 18 16 Capitalized interest (173 ) (176 ) (280 ) Amortization and other financial charges 1 67 211 31 2,069 1,998 1,370 1 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 $ 1,987 million in 2017 ( 2016 – $ 1,721 million ; 2015 – $ 1,266 million ) on long-term debt, junior subordinated notes and notes payable, net of interest capitalized.

JUNIOR SUBORDINATED NOTES

JUNIOR SUBORDINATED NOTES	12 Months Ended
	Dec. 31, 2017
Junior Subordinated Notes [Abstract]
JUNIOR SUBORDINATED NOTES	JUNIOR SUBORDINATED NOTES 2017 2016 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED U.S.$1,000 notes issued 2007 1 2067 1,252 5.0 % 3 1,343 6.4 % U.S.$750 notes issued 2015 1,2 2075 939 5.9 % 1,007 5.5 % U.S.$1,200 notes issued 2016 1,2 2076 1,502 6.6 % 1,611 6.2 % U.S.$1,500 notes issued 2017 1, 2 2077 1,878 5.6 % — — $1,500 notes issued 2017 1, 2 2077 1,500 5.1 % — — 7,071 3,961 Unamortized debt discount and issue costs (64 ) (30 ) 7,007 3,931 1 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 2 The Junior subordinated notes were issued to TransCanada Trust, 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. 3 In May 2017, Junior subordinated notes of US $1 billion converted from fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three month LIBOR plus 2.21 per cent . In March 2017, TransCanada Trust (the Trust) issued US$ 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 three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the 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

NON-CONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2017
Noncontrolling Interest [Abstract]
NON-CONTROLLING INTERESTS	NON-CONTROLLING INTERESTS The Company's Non-controlling interests included in the Consolidated balance sheet are as follows: at December 31 2017 2016 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,852 1,596 Non-controlling interest in Portland Natural Gas Transmission System — 130 1,852 1,726 The Company's Net income attributable to non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 220 215 (13 ) Non-controlling interest in Portland Natural Gas Transmission System 1 9 20 19 Non-controlling interest in Columbia Pipeline Partners LP 2 9 17 — 238 252 6 1 Non-controlling interest in 2017 for the period January 1 to May 31 when TransCanada sold its remaining interest in PNGTS to TC PipeLines, LP. Refer to Note 26, Other acquisitions and dispositions for further information. 2 Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of CPPL. TC PipeLines, LP During 2017 , the non-controlling interest in TC PipeLines, LP increased from 73.2 per cent to 74.3 per cent due to periodic issuances of common units in TC PipeLines, LP to third parties under an at-the-market issuance program (ATM program). In 2016 , the non-controlling interest in TC PipeLines, LP ranged between 72.0 per cent and 73.2 per cent and, in 2015 , between 71.7 per cent and 72.0 per cent . In December 2015, TC PipeLines, LP recorded an impairment charge of US$199 million related to its equity investment in Great Lakes. The non-controlling interest's share of this charge was US$143 million and was included in the Net income attributable to non-controlling interests in 2015 . Portland Natural Gas Transmission System On June 1, 2017, TransCanada sold its remaining 11.81 per cent directly held interest in Portland Natural Gas Transmission System (PNGTS) to TC PipeLines, LP and, as a result, at December 31, 2017 , non-controlling interest in PNGTS was nil . The non-controlling interest in PNGTS as at December 31, 2016 represented the 38.3 per cent interest held by third parties. On January 1, 2016, TransCanada sold 49.9 per cent of PNGTS to TC PipeLines, LP. Refer to Note 26, Other acquisitions and dispositions for further information. In 2017 , TransCanada received fees of $ 5 million from TC PipeLines, LP ( 2016 – $5 million and 2015 – $4 million ) and $ 4 million from PNGTS prior to June 1, 2017 ( 2016 – $ 10 million ; 2015 – $11 million ) for services provided . Columbia Pipeline Partners LP On July 1, 2016 , TransCanada acquired Columbia, which included a 53.5 per cent non-controlling interest in 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 ATM 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 have 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

COMMON SHARES	12 Months Ended
	Dec. 31, 2017
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
COMMON SHARES	COMMON SHARES Number of Shares Amount (thousands) (millions of Canadian $) Outstanding at January 1, 2015 708,662 12,202 Exercise of options 737 30 Repurchase of shares (6,785 ) (130 ) Outstanding at December 31, 2015 702,614 12,102 Issued under public offerings 1 156,825 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 program 1 3,462 216 Exercise of options 1,331 62 Outstanding at December 31, 2017 881,376 21,167 1 Net of underwriting commissions 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. Common shares are 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 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 ATM program, the Company can 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 gross proceeds of $218 million . Related commissions and fees were approximately $2 million , resulting in net proceeds of $216 million . 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 closing of 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. In December 2015, the Company repurchased 6,784,738 of its common shares at an average price of $43.29 for a total of $294 million . These shares had a weighted average cost of $130 million with the difference of $164 million between the total price paid and the weighted average cost recorded in A dditional paid-in capital. Basic and Diluted Net Income/(Loss) per Common Share Net income/(loss) per common share is calculated by dividing Net income/(loss) 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 outstanding shares issued under the DRP. Weighted Average Common Shares Outstanding (millions) 2017 2016 2015 Basic 872 759 709 Diluted 874 760 709 Stock Options Number of (thousands) Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (years) Options outstanding at January 1, 2017 10,630 $48.28 Options granted 2,066 $62.22 Options exercised (1,331 ) $42.03 Options forfeited/expired (339 ) $56.89 Options Outstanding at December 31, 2017 11,026 $51.38 3.9 Options Exercisable at December 31, 2017 6,559 $48.59 3.0 At December 31, 2017 , an additional 11,902,759 common shares were reserved for future issuance 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 2017 2016 2015 Weighted average fair value $7.22 $5.67 $6.45 Expected life (years) 5.7 5.8 5.8 Interest rate 1.2 % 0.7 % 1.1 % Volatility 1 18 % 21 % 18 % Dividend yield 3.6 % 4.9 % 3.7 % Forfeiture rate 2 — 5 % 5 % 1 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. 2 On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance. Refer to Note 3, Accounting changes, for further information. The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $12 million in 2017 ( 2016 – $15 million ; 2015 – $13 million ). At December 31, 2017 , unrecognized compensation costs related to non-vested stock options was $15 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 2017 2016 2015 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 28 31 10 Fair value of options that have vested 140 126 91 Total options vested 2.3 million 2.1 million 2.0 million As at December 31, 2017 , the aggregate intrinsic value of the total options exercisable was $83 million and the total intrinsic value of options outstanding was $110 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

PREFERRED SHARES	12 Months Ended
	Dec. 31, 2017
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
PREFERRED SHARES	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 2017 2016 2015 (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 Floating 4 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 Floating 4 Floating $25.00 June 30, 2020 Series 3 134 134 134 Series 5 12,714 2.263 % $0.56575 $5 $25.00 January 30, 2021 Series 6 310 310 342 Series 6 1,286 Floating 4 Floating $25.00 January 30, 2021 Series 5 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 — Series 15 40,000 4.90 % $1.225 $25.00 May 31, 2022 Series 16 988 988 — 3,980 3,980 2,499 1 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. 2 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. 4 The floating quarterly dividend rate for the Series 2 preferred shares is 2.792 per cent and for the Series 4 preferred shares is 2.152 per cent for the period starting December 29, 2017 to, but excluding, March 29, 2018. The floating quarterly dividend rate for the Series 6 preferred shares is 2.549 per cent for the period starting October 30, 2017 to, but excluding, January 30, 2018. 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 . In March 2015, TransCanada completed a public offering of 10 million Series 11 cumulative redeemable first preferred shares at $25 per share, resulting in gross proceeds of $ 250 million . In June 2015, holders of 5,466,595 Series 3 cumulative redeemable first preferred shares exercised their option to convert to Series 4 cumulative first preferred shares. 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 (LOSS)_INCO

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS	OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS Components of Other comprehensive (loss)/income, including the portion attributable to non-controlling interests and related tax effects, are as follows: year ended December 31, 2017 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation losses on net investment in foreign operations (746 ) (3 ) (749 ) Reclassification of foreign currency translation gains on net investment on disposal of foreign operations (77 ) — (77 ) Change in fair value of net investment hedges — — — 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 $) 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 ) year ended December 31, 2015 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 798 15 813 Change in fair value of net investment hedges (505 ) 133 (372 ) Change in fair value of cash flow hedges (92 ) 35 (57 ) Reclassification to net income of gains and losses on cash flow hedges 144 (56 ) 88 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 74 (23 ) 51 Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 41 (9 ) 32 Other comprehensive income on equity investments 62 (15 ) 47 Other Comprehensive Income 522 80 602 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 Total 1 AOCI balance at January 1, 2015 (518 ) (128 ) (281 ) (308 ) (1,235 ) Other comprehensive income/(loss) before reclassifications 2 135 (57 ) 51 33 162 Amounts reclassified from AOCI — 88 32 14 134 Net current period other comprehensive income 135 31 83 47 296 AOCI balance at December 31, 2015 (383 ) (97 ) (198 ) (261 ) (939 ) Other comprehensive income/(loss) before reclassifications 2 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 4 (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 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 In 2017 , other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $159 million ( 2016 – $14 million losses; 2015 – $306 million gains) and gains of $4 million ( 2016 – $3 million gains and 2015 – nil ), 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. 4 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 $19 million ( $14 million , net of tax) at December 31, 2017 . These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. Details about reclassifications out of AOCI into the Consolidated statement of income are as follows: Amounts Reclassified 1 Affected Line Item year ended December 31 2017 2016 2015 (millions of Canadian $) Cash flow hedges Commodities 20 (57 ) (128 ) Revenues (Energy) Interest (17 ) (14 ) (16 ) Interest expense 3 (71 ) (144 ) Total before tax (1 ) 29 56 Income tax (recovery)/expense 2 (42 ) (88 ) Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial loss and past service cost (15 ) (22 ) (41 ) Plant operating costs and other 2 Settlement charge (2 ) — — Plant operating costs and other 2 (17 ) (22 ) (41 ) Total before tax 5 6 9 Income tax (recovery)/expense (12 ) (16 ) (32 ) Net of tax Equity investments Equity income (15 ) (19 ) (19 ) Income from equity investments 4 5 5 Income tax (recovery)/expense (11 ) (14 ) (14 ) Net of tax Currency translation adjustments Realization of foreign currency translation gains on disposal of foreign operations 77 — — Gain/(loss) on sale of assets held for sale/sold — — — Income tax (recovery)/expense 77 — — Net of tax 1 All 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.

EMPLOYEE POST-RETIREMENT BENEFI

EMPLOYEE POST-RETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
EMPLOYEE POST-RETIREMENT BENEFITS	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, 2017 ( 2016 and 2015 – nine years ). 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. 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 DC plan. This election was effective December 31, 2017 . 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 are amortized out of AOCI over the expected average remaining service life of employees, which was approximately 12 years at December 31, 2017 ( 2016 and 2015 – 12 years ). In 2017 , the Company expensed $42 million ( 2016 – $52 million ; 2015 – $41 million ) for the savings and DC Plans. Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) DB Plans 163 111 96 Other post-retirement benefit plans 7 8 6 Savings and DC Plans 42 52 41 212 171 143 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 $27 million letter of credit to the Canadian DB Plan in 2017 ( 2016 – $20 million ; 2015 – $33 million ), resulting in a total of $260 million provided to the Canadian DB Plan under letters of credit at December 31, 2017 . The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2017 and the next required valuation will be as at January 1, 2018. 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 in 2017 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 Other comprehensive income, 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. 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 . All other assumptions were consistent with those employed at December 31, 2016. 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 Other comprehensive income. The Company's funded status at December 31 is comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,456 2,780 372 225 Service cost 113 107 4 3 Interest cost 135 127 14 13 Employee contributions 5 4 3 2 Benefits paid (166 ) (204 ) (19 ) (16 ) Actuarial loss/(gain) 253 111 19 (8 ) Acquisition of Columbia — 527 — 151 Curtailment (14 ) — (2 ) — Settlement (66 ) 2 — — Foreign exchange rate changes (70 ) 2 (16 ) 2 Benefit obligation – end of year 3,646 3,456 375 372 Change in Plan Assets Plan assets at fair value – beginning of year 3,208 2,591 354 45 Actual return on plan assets 358 227 45 14 Employer contributions 2 163 111 7 8 Employee contributions 5 4 3 2 Benefits paid (166 ) (204 ) (19 ) (16 ) Acquisition of Columbia — 475 — 294 Settlement (57 ) — — — Foreign exchange rate changes (60 ) 4 (25 ) 7 Plan assets at fair value – end of year 3,451 3,208 365 354 Funded Status – Plan Deficit (195 ) (248 ) (10 ) (18 ) 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 $260 million in letters of credit provided to the Canadian DB Plan for funding purposes ( 2016 – $233 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 Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Intangible and other assets (Note 12) — — 193 189 Accounts payable and other (1 ) — (8 ) (7 ) Other long-term liabilities (Note 15) (194 ) (248 ) (195 ) (200 ) (195 ) (248 ) (10 ) (18 ) 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 Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Projected benefit obligation 1 (3,646 ) (3,456 ) (203 ) (207 ) Plan assets at fair value 3,451 3,208 — — Funded Status – Plan Deficit (195 ) (248 ) (203 ) (207 ) 1 The projected benefit obligation for the pension benefit plan differs 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 2017 2016 (millions of Canadian $) Accumulated benefit obligation (3,372 ) (3,202 ) Plan assets at fair value 3,451 3,208 Funded Status – Plan Surplus 79 6 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 2017 2016 (millions of Canadian $) Accumulated benefit obligation (944 ) (990 ) Plan assets at fair value 925 868 Funded Status – Plan Deficit (19 ) (122 ) The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: Percentage of Target Allocations at December 31 2017 2016 2017 Debt securities 30 % 31 % 25% to 40% Equity securities 64 % 63 % 45% to 75% Alternatives 6 % 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 (millions of Canadian $) 2017 2016 2017 2016 Debt securities 7 9 0.2 % 0.2 % Equity securities 3 4 0.1 % 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 Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 Asset Category Cash and Cash Equivalents 44 22 17 12 — — 61 34 2 1 Equity Securities: Canadian 410 388 151 143 — — 561 531 15 15 U.S. 543 504 354 476 — — 897 980 24 27 International 45 39 322 327 — — 367 366 10 10 Global — — 301 235 — — 301 235 8 7 Emerging 8 7 147 137 — — 155 144 4 4 Fixed Income Securities: Canadian Bonds: Federal — — 193 192 — — 193 192 5 5 Provincial — — 194 179 — — 194 179 5 5 Municipal — — 8 8 — — 8 8 — — Corporate — — 122 126 — — 122 126 3 4 U.S. Bonds: Federal — — 244 82 — — 244 82 6 2 State — — 41 41 — — 41 41 1 1 Municipal — — 4 39 — — 4 39 — 1 Corporate — — 234 188 — — 234 188 6 5 International: Government — — 4 6 — — 4 6 — — Corporate — — 5 21 — — 5 21 — 1 Mortgage backed — — 73 62 — — 73 62 2 2 Other Investments: Real estate — — — — 140 133 140 133 4 4 Infrastructure — — — — 70 58 70 58 2 2 Private equity funds — — — — 6 8 6 8 — — Funds held on deposit 136 129 — — — — 136 129 3 4 1,186 1,089 2,414 2,274 216 199 3,816 3,562 100 100 The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2015 14 Purchases and sales 183 Realized and unrealized gains 2 Balance at December 31, 2016 199 Purchases and sales 11 Realized and unrealized gains 6 Balance at December 31, 2017 216 The Company's expected funding contributions in 2018 are approximately $98 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $45 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $27 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 2018 181 19 2019 187 20 2020 190 20 2021 196 20 2022 200 20 2023 to 2027 1,054 98 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, 2017 . 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 Other Post-Retirement at December 31 2017 2016 2017 2016 Discount rate 3.60 % 4.00 % 3.70 % 4.15 % Rate of compensation increase 3.00 % 1.20 % — — The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows: Pension Other Post-Retirement year ended December 31 2017 2016 2015 2017 2016 2015 Discount rate 3.95 % 4.20 % 4.15 % 4.15 % 4.30 % 4.20 % Expected long-term rate of return on plan assets 6.50 % 6.70 % 6.95 % 6.05 % 5.95 % 4.60 % Rate of compensation increase 1.20 % 0.80 % 3.15 % — — — 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 seven per cent weighted average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2024 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 15 (13 ) The Company's net benefit cost recognized is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2015 2017 2016 2015 Service cost 108 107 108 4 3 3 Interest cost 122 127 115 14 13 10 Expected return on plan assets (178 ) (175 ) (155 ) (21 ) (11 ) (2 ) Amortization of actuarial loss 14 20 35 1 2 3 Amortization of past service cost — — 2 — — 1 Amortization of regulatory asset 37 27 23 1 1 1 Amortization of transitional obligation related to regulated business — — — — 2 2 Settlement charge – regulatory asset 2 — — — — — Settlement charge – AOCI 2 — — — — — Net Benefit Cost Recognized 107 106 128 (1 ) 10 18 Pre-tax amounts recognized in AOCI were as follows: 2017 2016 2015 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 273 11 270 21 247 28 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 2018 is $19 million and $1 million , respectively. Pre-tax amounts recognized in OCI were as follows: 2017 2016 2015 at December 31 Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits (millions of Canadian $) Amortization of net loss from AOCI to OCI (18 ) (1 ) (20 ) (2 ) (34 ) (4 ) Amortization of prior service costs from AOCI to OCI — — — — (2 ) (1 ) Curtailment (14 ) (2 ) — — — — Settlement (11 ) — — — — — Funded status adjustment 46 (7 ) 43 (5 ) (67 ) (7 ) 3 (10 ) 23 (7 ) (103 ) (12 )

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2017
Risk Management and Financial Instruments [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings and cash flow. 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 ultimately 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. Power generation commodity price risk The Company is exposed to commodity price movements as part of its normal business operations. A number of strategies are used to manage these exposures, including the following: • committing a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to manage operational and price risks in its asset portfolio • purchasing a portion of the natural gas required to fuel certain of its power plants or entering into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin • meeting power sales commitments using power generation or fixed price purchase contracts, thereby reducing the Company's exposure to fluctuating commodity prices. In April and June 2017, the Company sold its U.S. Northeast power assets. In December 2017, TransCanada entered into an agreement to sell its outstanding U.S. power retail contracts as part of the wind down of the U.S. power marketing operations. The sale of the U.S. power retail contracts is expected to close in the first quarter of 2018, subject to regulatory and other approvals. As a result of these sales, the exposure to commodity price risk has been reduced significantly. Natural gas storage commodity price risk TransCanada manages its exposure to seasonal natural gas price spreads in its non-regulated natural gas storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TransCanada simultaneously enters into forward purchase contracts of natural gas for injection into storage and offsetting forward sale contracts of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to natural gas price movements. Unrealized gains and losses on fair value adjustments recorded each period on these forward contracts are not necessarily representative of the amounts that will be realized on settlement. Liquids marketing commodity price risk The liquids marketing business began operations in 2016. TransCanada enters into short-term or long-term liquids 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. Foreign exchange and interest rate risk Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates. 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 expected to fluctuate. A portion of TransCanada’s business generates 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 the Company’s net income. As the Company’s U.S. dollar-denominated operations continue to grow, exposure to changes in currency rates increases. The majority of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives. TransCanada is exposed to interest rate risk resulting from financial instruments and contractual obligations containing variable interest rate components. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk. Net investment in foreign operations The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps and foreign exchange forward contracts and options. The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows: 2017 2016 at December 31 Fair 1 Notional or Fair 1 Notional or (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019) 2 (199 ) US 1,200 (425 ) US 2,350 U.S. dollar foreign exchange options (maturing 2018) 5 US 500 — — U.S. dollar foreign exchange forward contracts — — (7 ) US 150 (194 ) US 1,700 (432 ) US 2,500 1 Fair value equals carrying value. 2 In 2017 , Net income includes net realized gains of $4 million ( 2016 – gains of $6 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 2017 2016 (millions of Canadian $, unless otherwise noted) Notional amount 25,400 (US 20,200) 26,600 (US 19,800) Fair value 28,900 (US 23,100) 29,400 (US 21,900) Counterparty Credit Risk 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 using recognized credit management techniques, including: • dealing with creditworthy counterparties – a significant amount of the Company’s credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties • setting limits on the amount TransCanada can transact with any one counterparty – the Company monitors and manages the concentration of risk exposure with any one counterparty, and reduces the exposure when necessary and when it is allowed under the terms of the contracts • using contract netting arrangements and obtaining financial assurances such as guarantees, letters of credit or cash when deemed necessary. There is no guarantee that these techniques will protect the Company from material losses. TransCanada's maximum counterparty credit exposure with respect to financial instruments at December 31, 2017 , without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets, derivative assets and loan receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2017 , there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the year. At December 31, 2016 , we had a credit risk concentration with one counterparty of $200 million ( US$149 million ). 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. For TransCanada's Canadian regulated natural gas pipeline assets, counterparty credit risk is managed through application of tariff provisions as approved by the NEB. Fair Value of Non-Derivative Financial Instruments The fair value of long-term debt and junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers. Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy. Credit risk has been taken into consideration when calculating the fair value of non-derivative 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: 2017 2016 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Long-term debt, including current portion 1,2 (Note 17) (34,741 ) (40,180 ) (40,150 ) (45,047 ) Junior subordinated notes (Note 18) (7,007 ) (7,233 ) (3,931 ) (3,825 ) (41,748 ) (47,413 ) (44,081 ) (48,872 ) 1 Long-term debt is recorded at amortized cost, except for US$1.1 billion ( 2016 – US$850 million ) that is attributed to hedged risk and recorded at fair value. 2 Net income in 2017 included unrealized gains of $4 million ( 2016 – gains of $2 million ) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.1 billion of long-term debt at December 31, 2017 ( 2016 – US$850 million ). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. Available for Sale Assets Summary The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets: 2017 2016 LMCI Restricted Investments Other Restricted Investments 2 LMCI Restricted Investments Other Restricted Investments 2 (millions of Canadian $) Fair value 1 Fixed income securities (maturing within 1 year) — 23 — 19 Fixed income securities (maturing within 1-5 years) — 107 — 117 Fixed income securities (maturing within 5-10 years) 14 — 9 — Fixed income securities (maturing after 10 years) 790 — 513 — 804 130 522 136 1 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. 2 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. 2017 2016 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized (losses)/gains in the year ended December 31 (3 ) 1 (28 ) (1 ) Net realized (losses)/gains in the year ended December 31 3 (1 ) — — — 1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. 2 Unrealized gains and losses on other restricted investments are included in OCI. 3 The realized gains or 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. 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, 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 Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 1 — — 249 250 Foreign exchange — — 8 70 78 Interest rate 3 — — 1 4 4 — 8 320 332 Intangible and other assets (Note 12) Commodities 2 — — — 69 69 Interest rate 4 — — — 4 4 — — 69 73 Total Derivative Assets 8 — 8 389 405 Accounts payable and other (Note 14) Commodities 2 (6 ) — — (208 ) (214 ) Foreign exchange — — (159 ) (10 ) (169 ) Interest rate — (4 ) — — (4 ) (6 ) (4 ) (159 ) (218 ) (387 ) Other long-term liabilities (Note 15) Commodities 2 (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 balance sheet classification of the fair value of derivative instruments as at December 31, 2016 is as follows: at December 31, 2016 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 6 — — 351 357 Foreign exchange — — 6 10 16 Interest rate 1 1 — 1 3 7 1 6 362 376 Intangible and other assets (Note 12) Commodities 2 4 — — 118 122 Foreign exchange — — 10 — 10 Interest rate 1 — — — 1 5 — 10 118 133 Total Derivative Assets 12 1 16 480 509 Accounts payable and other (Note 14) Commodities 2 — — — (330 ) (330 ) Foreign exchange — — (237 ) (38 ) (275 ) Interest rate (1 ) (1 ) — — (2 ) (1 ) (1 ) (237 ) (368 ) (607 ) Other long-term liabilities (Note 15) Commodities 2 — — — (118 ) (118 ) Foreign exchange — — (211 ) — (211 ) Interest rate — (1 ) — — (1 ) — (1 ) (211 ) (118 ) (330 ) Total Derivative Liabilities (1 ) (2 ) (448 ) (486 ) (937 ) Total Derivatives 11 (1 ) (432 ) (6 ) (428 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk. Notional and Maturity Summary The maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows: at December 31, 2017 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 66,132 133 6 — — Sales 1 42,836 135 7 — — Millions of U.S. dollars — — — US 2,931 US 2,300 Millions of Mexican pesos — — — MXN 100 — Maturity dates 2018-2022 2018-2021 2018 2018 2018-2022 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. at December 31, 2016 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 86,887 182 6 — — Sales 1 58,561 147 6 — — Millions of U.S. dollars — — — US 2,394 US 1,550 Maturity dates 2017-2021 2017-2020 2017 2017 2017-2019 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively . Unrealized and Realized Gains/(Losses) on Derivative Instruments The following summary does not include hedges of the net investment in foreign operations. year ended December 31 2017 2016 2015 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 2 62 123 (37 ) Foreign exchange 88 25 (21 ) Interest rate (1 ) — — Amount of realized (losses)/gains in the year Commodities (107 ) (204 ) (151 ) Foreign exchange 18 62 (112 ) Interest rate 1 — — Derivative instruments in hedging relationships Amount of realized gains/(losses) in the year Commodities 23 (167 ) (179 ) Foreign exchange 5 (101 ) — Interest rate 1 4 8 1 Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively. 2 In 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 2017 2016 2015 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI (effective portion) 1 Commodities (1 ) 39 (92 ) Interest rate 4 5 — 3 44 (92 ) Reclassification of (losses)/gains on derivative instruments from AOCI to Net income (effective portion) 1 Commodities 2 (20 ) 57 128 Interest rate 3 17 14 16 (3 ) 71 144 1 No amounts have been excluded from the assessment of hedge effectiveness. In 2017 and 2016 , there were no gains or losses included in Net Income related to ineffective portions. Amounts in parentheses indicate losses recorded to OCI and AOCI. 2 Reported within Revenues on the Consolidated statement of income. 3 Reported within Interest expense on the Consolidated statement of income. Offsetting of derivative instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the 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, 2017 : at December 31, 2017 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) 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. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2016 : at December 31, 2016 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 479 (362 ) 117 Foreign exchange 26 (26 ) — Interest rate 4 (1 ) 3 509 (389 ) 120 Derivative – Liability Commodities (448 ) 362 (86 ) Foreign exchange (486 ) 26 (460 ) Interest rate (3 ) 1 (2 ) (937 ) 389 (548 ) 1 Amounts available for offset do not include cash collateral pledged or received. With respect to the derivative instruments presented above as at December 31, 2017 , the Company had provided cash collateral of $165 million ( 2016 – $305 million ) and letters of credit of $30 million ( 2016 – $27 million ) to its counterparties. The Company held nil ( 2016 – nil ) in cash collateral and $3 million ( 2016 – $3 million ) in letters of credit from counterparties on asset exposures at December 31, 2017 . Credit risk related contingent features of derivative instruments Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at December 31, 2017 , the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $2 million ( 2016 – $19 million ), for which the Company has provided collateral in the normal course of business of nil ( 2016 – nil ). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2017 , the Company would have been required to provide additional collateral of $2 million ( 2016 – $19 million ) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving 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 2017 , are categorized as follows: at December 31, 2017 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) 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 fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2016 , are categorized as follows: at December 31, 2016 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 134 326 19 479 Foreign exchange — 26 — 26 Interest rate — 4 — 4 Derivative Instrument Liabilities: Commodities (102 ) (343 ) (3 ) (448 ) Foreign exchange — (486 ) — (486 ) Interest rate — (3 ) — (3 ) 32 (476 ) 16 (428 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016 . The following table presents the net change in fair value of derivative assets and liabilities classified in Level III of the fair value hierarchy: (millions of Canadian $, pre-tax) 2017 2016 Balance at beginning of year 16 9 Transfers out of Level III (19 ) (1 ) Total (losses)/gains included in Net income (17 ) 13 Sales (5 ) (3 ) Settlements 18 (2 ) Balance at end of year 1 (7 ) 16 1 Revenues include unrealized losses attributed to derivatives in the Level III category that were still held at December 31, 2017 of $7 million ( 2016 — gains 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 increase or decrease , respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2017 .

CHANGES IN OPERATING WORKING CA

CHANGES IN OPERATING WORKING CAPITAL	12 Months Ended
	Dec. 31, 2017
CHANGES IN OPERATING WORKING CAPITAL
CHANGES IN OPERATING WORKING CAPITAL	CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2017 2016 2015 (millions of Canadian $) Increase in Accounts receivable (576 ) (482 ) (65 ) Increase in Inventories (38 ) (87 ) (3 ) Decrease/(increase) in Assets held for sale 14 (13 ) — Decrease/(increase) in Other current assets 189 328 (272 ) Increase/(decrease) in Accounts payable and other 151 424 (97 ) Increase in Accrued interest 12 62 91 (Decrease)/increase in Liabilities related to assets held for sale (25 ) 16 — (Increase)/decrease in Operating Working Capital (273 ) 248 (346 )

OTHER ACQUISITIONS AND DISPOSIT

OTHER ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
OTHER ACQUISITIONS AND DISPOSITIONS	OTHER 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, a long 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 PNGTS to TC PipeLines, LP. Proceeds from these transactions were US$765 million , before post-closing adjustments. Proceeds were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and PNGTS debt. In January 2016 , TransCanada closed the sale of a 49.9 per cent interest in PNGTS 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 PNGTS 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 . TC Offshore LLC In December 2015 , the Company entered into an agreement to sell TC Offshore LLC to a third party which resulted in a pre-tax loss on sale of $125 million in 2015. In March 2016 , the Company closed the sale which resulted in an additional loss of $4 million pre-tax. Losses from the sale were included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income. Gas Transmission Northwest LLC In April 2015 , TransCanada completed the sale of its remaining 30 per cent interest in GTN to TC PipeLines, LP for an aggregate purchase price of US$457 million . Proceeds were comprised of US$264 million in cash, the assumption of US$98 million of a proportional share of GTN debt and US$95 million of new Class B units of TC PipeLines, LP. Energy Ontario Solar Assets On December 19, 2017, the Company completed the sale of its Ontario solar assets to a third party for proceeds of approximately $541 million , before post-closing adjustments. As a result, the Company recorded a gain on sale of approximately $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 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 approximately $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 approximately $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. Bruce Power In December 2015, TransCanada exercised its option to acquire an additional 14.89 per cent ownership interest in Bruce B from the Ontario Municipal Employees Retirement System for $236 million , increasing its ownership interest to 46.5 per cent . The difference between the purchase price and the underlying carrying value of Bruce B is primarily related to the estimated fair value of the amended agreement with Ontario's Independent Electricity System Operator to extend the oper ating life of the Bruce Power facility to 2064. In December 2015, Bruce A and Bruce B merged to form a single limited partnership, Bruce Power. This merger was accounted for as a transaction between entities under common control whereby the assets and liabilities of Bruce A and Bruce B were combined at their carrying values. Upon completion of the merger, TransCanada applied equity method accounting to its resulting 48.5 per cent ownership interest in Bruce Power. Prior to the acquisition, TransCanada applied equity method accounting to its 48.9 per cent ownership interest in Bruce A and its 31.6 per cent ownership interest in Bruce B.

COMMITMENTS, CONTINGENCIES AND

COMMITMENTS, CONTINGENCIES AND GUARANTEES	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, CONTINGENCIES AND GUARANTEES	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 Amounts Net (millions of Canadian $) 2018 75 4 71 2019 76 2 74 2020 73 2 71 2021 71 1 70 2022 63 — 63 2023 and thereafter 443 2 441 801 11 790 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 2017 was $93 million ( 2016 – $145 million ; 2015 – $131 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, 2017 , TransCanada was committed to approximately $0.3 billion of capital expenditures for its Canadian Natural Gas Pipelines, primarily related to construction costs associated with NGTL System natural gas pipeline projects. At December 31, 2017 , TransCanada was committed to approximately $0.4 billion of capital expenditures for its U.S. Natural Gas Pipelines, primarily related to construction costs associated with Columbia Gas and Columbia Gulf growth projects. At December 31, 2017 , TransCanada was committed to approximately $0.7 billion of capital expenditures for its Mexico Natural Gas Pipelines, primarily related to construction of the Sur de Texas and Villa de Reyes gas pipeline projects. At December 31, 2017 , the Company was committed to approximately $0.1 billion of capital expenditures for its Liquids Pipelines, primarily related to capital projects on operating pipelines. At December 31, 2017 , the Company was committed to approximately $0.4 billion of capital expenditures for its Energy business, primarily related to construction costs of the Napanee Generating Station. At December 31, 2017 , the Company was committed to approximately $0.1 billion of Corporate expenditures 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, 2017 , the Company had accrued approximately $34 million ( 2016 – $39 million ) related to operating facilities, which represents the present value of the estimated future amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur 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. In March 2017, the U.S. Department of State issued a U.S. Presidential Permit authorizing construction of the U.S./Canada border crossing facilities of the Keystone XL pipeline. TransCanada discontinued its claim under Chapter 11 of the North American Free Trade Agreement and has also withdrawn the U.S. Constitutional challenge that was filed in June 2016 and arose from the November 2015 denial of our Presidential Permit application to construct the Keystone XL pipeline. Guarantees TransCanada and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the obligations for construction services during the construction of the pipeline. TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, construction services and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners. The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees is as follows: 2017 2016 year ended December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas ranging to 2020 315 2 805 53 Bruce Power ranging to 2018 88 1 88 1 Other jointly owned entities ranging to 2059 104 13 87 28 507 16 980 82 1 TransCanada's share of the potential estimated current or contingent exposure.

CORPORATE RESTRUCTURING COSTS

CORPORATE RESTRUCTURING COSTS	12 Months Ended
	Dec. 31, 2017
Restructuring and Related Activities [Abstract]
CORPORATE RESTRUCTURING COSTS	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. Restructuring costs consist primarily of severance and expected future losses under lease commitments. In 2015, the Company incurred $122 million before tax of corporate restructuring costs and recorded a provision of $87 million before tax related to planned severance costs in 2016 and 2017 and expected future losses under lease commitments. Of the total corporate restructuring charges of $209 million pre-tax, $157 million was recorded in Plant operating costs and other which was partially offset by $58 million that was recorded in Revenues in the Consolidated statement of income related to costs that were recoverable through regulatory and tolling structures. In addition, $44 million was recorded as a Regulatory asset as it is expected to be recovered through regulatory and tolling structures in future periods, and $8 million was capitalized to projects impacted by the corporate restructuring. In 2016, an additional provision of $44 million before tax was recorded related to changes to the expected future losses under lease commitments. For the year ended December 31, 2016, $22 million was recorded in Plant operating costs and other in the Consolidated statement of income. In addition, $22 million was recorded as a Regulatory asset on the Consolidated balance sheet at December 31, 2016 as this amount is expected to be recovered through regulatory and tolling structures in future periods. In 2017, an additional provision of $6 million before tax was recorded related to changes to the expected future losses under lease commitments. For the year ended December 31, 2017, $3 million was recorded in Plant operating costs and other in the Consolidated statement of income. In addition, $3 million was recorded as a Regulatory asset on the Consolidated balance sheet at December 31, 2017 as this amount is expected to be recovered through regulatory and tolling structures in future periods. Cumulatively at December 31, 2017, the Company has incurred costs, net of recoverable amounts of $ 86 million for employee severance and $ 38 million for lease commitments under this initiative. The remaining employee severance provision at December 31, 2017 is expected to be settled in early 2018. Changes in the restructuring liability were as follows: (millions of Canadian $) Employee Severance Lease Commitments Total Restructuring liability as at December 31, 2015 60 27 87 Restructuring charges — 44 44 Cash payments (24 ) (8 ) (32 ) Restructuring liability as at December 31, 2016 36 63 99 Restructuring charges — 6 6 Cash payments (27 ) (16 ) (43 ) Restructuring Liability as at December 31, 2017 9 53 62

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
VARIABLE INTEREST ENTITIES	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 $) 2017 2016 ASSETS Current Assets Cash and cash equivalents 41 77 Accounts receivable 63 71 Inventories 23 25 Other 11 10 138 183 Plant, Property and Equipment 3,535 3,685 Equity Investments 917 606 Goodwill 490 525 Intangible and Other Assets 3 1 5,083 5,000 LIABILITIES Current Liabilities Accounts payable and other 137 80 Dividends payable 1 — Accrued interest 23 21 Current portion of long-term debt 88 76 249 177 Regulatory Liabilities 34 34 Other Long-Term Liabilities 3 4 Deferred Income Tax Liabilities 13 7 Long-Term Debt 3,244 2,827 3,543 3,049 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 $) 2017 2016 Balance sheet Equity investments 4,372 4,964 Off-balance sheet Potential exposure to guarantees 171 163 Maximum exposure to loss 4,543 5,127

ACCOUNTING POLICIES (Policies)

ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	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	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. Significant estimates and judgments used in the preparation of the consolidated financial statements include, but are not limited to: • fair value of assets and liabilities acquired in a business combination (Note 5) • fair value and depreciation rates of plant, property and equipment (Note 8) • carrying value of regulatory assets and liabilities (Note 10) • fair value of goodwill (Note 11) • fair value of intangible assets (Note 12) • 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 • provision for commitments, contingencies, guarantees (Note 27) and restructuring costs (Note 28). Actual results could differ from these estimates.
Regulation	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) or the Alberta Energy Regulator (AER). 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. 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 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.
Revenue Recognition	Revenue Recognition Natural Gas Pipelines and Liquids Pipelines Capacity Arrangements and Transportation Revenues from the Company's natural gas and liquids pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made. Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline tolls are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines generally are 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 rates. The Company's Canadian natural gas pipelines, at times, are subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues on firm contracted capacity are recognized ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenues are recorded when the NEB decision is received. The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. 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. Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and recognized ratably over the contract period. Other volumes shipped on these pipelines are subject to CRE-approved tariffs. The Company does not take ownership of the natural gas that it transports for its customers. Regulated Natural Gas Storage Revenues from the Company's regulated natural gas storage services are recognized either ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, or when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the natural gas that it stores for its customers. Midstream and Other 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 contract period regardless of the amount of natural gas that is subject to these services. The Company also owns mineral rights associated with certain storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest. Royalties from mineral interests are recognized when commodities are produced. Energy Power Generation Revenues from the Company's Energy business are primarily derived from the sale of electricity, which is recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative instruments and hedging activities policy in this note. Non-Regulated Natural Gas Storage Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded net of the cost of the proprietary natural gas in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues.
Cash and Cash Equivalents	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 Inventories primarily consist of natural gas inventory in storage, crude oil in transit, materials and supplies including spare parts and fuel. Inventories are carried at the lower of cost and net realizable value.
Assets Held For Sale	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. Depreciation expense is no longer recorded once an asset is classified as held for sale.
Plant, Property and Equipment	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 six 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 a 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. When the asset is ready for its intended use and available for operations, capitalized project costs are depreciated in accordance with the Company's plant, property and equipment depreciation policies.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets 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 or the estimated selling price 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	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. 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 first step of a two- step impairment test is performed by comparing the fair value of the reporting unit to its carrying value, which includes goodwill. If the fair value of the reporting unit is less than its carrying value, an impairment is indicated and the second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference. The Company can elect to move directly to the first step of the two-step impairment test for any of its reporting units when performing its annual impairment test.
Loans and Receivables	Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at cost.
Power Purchase Arrangements	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 were subleased to third parties under terms and conditions similar to the PPAs, and were also accounted for as operating leases with the margin earned from the subleases recorded in Revenues.
Restricted Investments	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	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 during 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. D eferred 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	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. 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. 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	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. These estimates 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. 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	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	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/(loss) (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/(loss) (AOCI) and into net income over the 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 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	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 effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in net income in the same financial statement category as the underlying transaction. 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 effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in net income. 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 the 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	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	Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of 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, Plant, property and equipment, or a charge to net income, 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	ACCOUNTING CHANGES Changes in Accounting Policies for 2017 Inventory In July 2015, the Financial Accounting Standards Board (FASB) issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this guidance at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Company's Consolidated balance sheet. Derivatives and hedging In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks of their debt hosts. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements. Equity method investments In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements. Employee share-based payments In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. The Company has elected to account for forfeitures when they occur. This new guidance was effective January 1, 2017 and resulted in a cumulative-effect adjustment of $12 million to retained earnings and the recognition of a deferred tax asset related to employee share-based payments that were made prior to the adoption of this guidance. Consolidation In October 2016, the FASB issued new guidance on consolidation relating to VIEs held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to the Company's consolidation conclusions. Future Accounting Changes Revenue from contracts with customers In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Company will adopt the new guidance on the effective date of January 1, 2018. There are two methods in which the new guidance can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Company will adopt the guidance using the modified retrospective approach with the cumulative-effect of the adjustment, if any, recognized at the date of adoption, subject to allowable and elected practical expedients. The Company identified all existing customer contracts that are within the scope of the new guidance by operating segment. The Company has completed its analysis of the contracts and has not identified any material differences in the amount and timing of revenue recognition as a result of implementing the new guidance. Therefore, the Company will not require a cumulative-effect adjustment to opening retained earnings on January 1, 2018. Although consolidated revenues will not be materially impacted by the new guidance, the Company will be required to add significant disclosures based on the prescribed requirements. These new disclosures will include information regarding the significant judgments used in evaluating when and how revenues, are recognized and information related to contract assets and deferred revenues. In addition, the new guidance requires that the Company’s revenue recognition policy disclosure include additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenues and cash flows generated from contracts with customers. The Company has developed draft disclosures required in first quarter 2018 with a particular focus on the scope of contracts subject to disclosure of future revenues from remaining performance obligations. The Company has addressed system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. Financial instruments In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in the fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018 and a method of adoption is specified for each component of the guidance. The Company has completed its analysis and does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the lessor to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for an arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is continuing to identify and analyze existing lease agreements to determine the effect of application of the new guidance on its consolidated financial statements. The Company is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance and continues to monitor and analyze additional guidance and clarification provided by the FASB. Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Income taxes In October 2016, the FASB issued new guidance on the income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied using a modified retrospective approach. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. Restricted cash In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents balance, and amounts generally described as restricted cash or restricted cash equivalents. Restricted cash and cash equivalents will be included with Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively. Goodwill impairment In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating Step 2 of the impairment test, which is the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted. Employee post-retirement benefits In March 2017, the FASB issued new guidance that will require entities to disaggregate the current service cost component from the other components of net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance is effective January 1, 2018. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. Amortization on purchased callable debt securities In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Hedge accounting In August 2017, the FASB issued new guidance on hedge accounting, 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 additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019, with early adoption permitted. The Company has elected to apply this guidance effective January 1, 2018. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements.

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	year ended December 31, 2017 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,693 3,584 570 2,009 3,593 — 13,449 Intersegment revenues — 51 — — — (51 ) — 3,693 3,635 570 2,009 3,593 (51 ) 13,449 Income from equity investments 11 240 (9 ) (3 ) 471 63 2 773 Plant operating costs and other (1,300 ) (1,340 ) (42 ) (623 ) (550 ) (51 ) (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 assets held for sale/sold — — — — 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 other 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 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. 2 This Inc ome from equity investments relates to foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture. 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 Energy Corporate 1 Total (millions of Canadian $) Revenues 3,682 2,526 378 1,755 4,206 — 12,547 Intersegment revenues — 56 — — — (56 ) — 3,682 2,582 378 1,755 4,206 (56 ) 12,547 Income from equity investments 12 214 (3 ) (1 ) 292 — 514 Plant operating costs and other (1,245 ) (1,057 ) (43 ) (568 ) (884 ) (64 ) (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 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. year ended December 31, 2015 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,680 1,444 259 1,879 4,091 — 11,353 Intersegment revenues — 47 — — — (47 ) — 3,680 1,491 259 1,879 4,091 (47 ) 11,353 Income from equity investments 12 162 5 — 261 — 440 Plant operating costs and other (1,204 ) (606 ) (51 ) (492 ) (845 ) (105 ) (3,303 ) Commodity purchases resold — — — — (2,237 ) — (2,237 ) Property taxes (272 ) (77 ) — (79 ) (89 ) — (517 ) Depreciation and amortization (849 ) (248 ) (44 ) (283 ) (341 ) — (1,765 ) Asset impairment charges — — — (3,686 ) (59 ) — (3,745 ) Loss on assets held for sale/sold — (125 ) — — — — (125 ) Segmented earnings/(losses) 1,367 597 169 (2,661 ) 781 (152 ) 101 Interest expense (1,370 ) Allowance for funds used during construction 295 Interest income and other (132 ) Loss before income taxes (1,106 ) Income tax expense (34 ) Net loss (1,140 ) Net income attributable to non-controlling interests (6 ) Net loss attributable to controlling interests (1,146 ) Preferred share dividends (94 ) Net loss attributable to common shares (1,240 ) Capital spending Capital expenditures 1,366 534 566 1,012 376 64 3,918 Capital projects in development 230 3 — 278 — — 511 Contributions to equity investments — — — 311 182 — 493 1,596 537 566 1,601 558 64 4,922 1 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. at December 31 2017 2016 (millions of Canadian $) Total Assets Canadian Natural Gas Pipelines 16,904 15,816 U.S. Natural Gas Pipelines 35,898 34,422 Mexico Natural Gas Pipelines 5,716 5,013 Liquids Pipelines 15,438 16,896 Energy 8,503 13,169 Corporate 3,642 2,735 86,101 88,051
Revenue from External Customers by Geographic Areas	year ended December 31 2017 2016 2015 (millions of Canadian $) Revenues Canada – domestic 3,618 3,697 3,930 Canada – export 1,255 1,177 1,292 United States 8,006 7,295 5,872 Mexico 570 378 259 13,449 12,547 11,353
Schedule of Long-Lived Assets by Country	at December 31 2017 2016 (millions of Canadian $) Plant, Property and Equipment Canada 21,632 20,531 United States 30,693 29,414 Mexico 4,952 4,530 57,277 54,475

ACQUISITION OF COLUMBIA (Tables

ACQUISITION OF COLUMBIA (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	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. Canadian 1 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 (Note 11) 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	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 )

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2017
Other Assets [Abstract]
Schedule of Other Current Assets	at December 31 2017 2016 (millions of Canadian $) Fair value of derivative contracts (Note 24) 332 376 Prepaid expenses 109 131 Cash provided as collateral 99 313 Regulatory assets (Note 10) 23 33 Other 128 55 691 908

PLANT, PROPERTY AND EQUIPMENT (

PLANT, PROPERTY AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Schedule of Plant, Property and Equipment	2017 2016 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 10,153 4,190 5,963 8,814 3,951 4,863 Compression 3,021 1,593 1,428 2,447 1,499 948 Metering and other 1,188 569 619 1,124 519 605 14,362 6,352 8,010 12,385 5,969 6,416 Under construction 940 — 940 1,151 — 1,151 15,302 6,352 8,950 13,536 5,969 7,567 Canadian Mainline Pipeline 9,763 6,455 3,308 9,502 6,221 3,281 Compression 3,605 2,499 1,106 3,537 2,361 1,176 Metering and other 655 207 448 605 198 407 14,023 9,161 4,862 13,644 8,780 4,864 Under construction 156 — 156 219 — 219 14,179 9,161 5,018 13,863 8,780 5,083 Other Canadian Natural Gas Pipelines Other 1 1,815 1,363 452 1,728 1,273 455 Under construction 4 — 4 112 — 112 1,819 1,363 456 1,840 1,273 567 31,300 16,876 14,424 29,239 16,022 13,217 U.S. Natural Gas Pipelines Columbia Gas Pipeline 3,550 125 3,425 3,317 42 3,275 Compression 1,547 64 1,483 1,636 29 1,607 Metering and other 2,306 37 2,269 2,550 8 2,542 7,403 226 7,177 7,503 79 7,424 Under construction 3,332 — 3,332 1,127 — 1,127 10,735 226 10,509 8,630 79 8,551 ANR Pipeline 1,427 365 1,062 1,468 349 1,119 Compression 1,582 286 1,296 1,494 260 1,234 Metering and other 961 268 693 988 254 734 3,970 919 3,051 3,950 863 3,087 Under construction 358 — 358 232 — 232 4,328 919 3,409 4,182 863 3,319 2017 2016 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,107 822 1,285 2,221 810 1,411 Great Lakes 1,988 1,113 875 2,106 1,155 951 Columbia Gulf 1,115 37 1,078 880 5 875 Midstream 1,085 54 1,031 1,072 23 1,049 Other 2 1,950 574 1,376 2,120 567 1,553 8,245 2,600 5,645 8,399 2,560 5,839 Under construction 699 — 699 346 — 346 8,944 2,600 6,344 8,745 2,560 6,185 24,007 3,745 20,262 21,557 3,502 18,055 Mexico Natural Gas Pipelines Pipeline 2,486 214 2,272 2,734 180 2,554 Compression 388 30 358 422 19 403 Metering and other 522 65 457 502 40 462 3,396 309 3,087 3,658 239 3,419 Under construction 1,865 — 1,865 1,108 — 1,108 5,261 309 4,952 4,766 239 4,527 Liquids Pipelines Keystone Pipeline System Pipeline 9,002 992 8,010 10,572 901 9,671 Pumping equipment 1,022 152 870 928 121 807 Tanks and other 3,314 385 2,929 2,521 286 2,235 13,338 1,529 11,809 14,021 1,308 12,713 Under construction 456 — 456 479 — 479 13,794 1,529 12,265 14,500 1,308 13,192 Intra-Alberta Pipelines 3 Pipeline 748 3 745 — — — Pumping equipment 104 — 104 — — — Tanks and other 259 1 258 — — — 1,111 4 1,107 — — — Under construction 47 — 47 955 — 955 1,158 4 1,154 955 — 955 14,952 1,533 13,419 15,455 1,308 14,147 Energy Natural Gas 4,5 2,645 743 1,902 2,696 696 2,000 Wind and Solar 6 673 204 469 1,180 245 935 Natural Gas Storage and Other 734 156 578 731 146 585 4,052 1,103 2,949 4,607 1,087 3,520 Under construction 1,028 — 1,028 729 — 729 5,080 1,103 3,977 5,336 1,087 4,249 Corporate 411 168 243 410 130 280 81,011 23,734 57,277 76,763 22,288 54,475 1 Includes Foothills, Ventures LP and Great Lakes Canada . 2 Includes Bison, Portland Natural Gas Transmission System, North Baja, Tuscarora and Crossroads. 3 Includes Northern Courier, placed in-service on November 1, 2017 and White Spruce. 4 Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities was $ 1,264 million and $ 354 million , respectively, at December 31, 2017 ( 2016 – $ 1,319 million and $ 335 million , respectively). Revenues of $ 215 million were recognized in 2017 ( 2016 – $ 212 million ; 2015 – $ 235 million ) through the sale of electricity under the related PPAs. 5 Includes Coolidge, Grandview, and Bécancour assets which operate under operating leases, along with Halton Hills and Alberta cogeneration natural gas-fired facilities. 6 Ontario solar assets are excluded from the Wind and Solar net book value at December 31, 2017 as they were sold on December 19, 2017. Refer to Note 26, Other acquisitions and dispositions, for further information.

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Investments	(millions of Canadian $) Ownership Income/(Loss) from Equity Investments Equity Investments year ended December 31 at December 31 2017 2016 2015 2017 2016 Canadian Natural Gas Pipelines TQM 50.0 % 11 12 12 68 71 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 87 92 85 641 597 Iroquois 2 50.0 % 59 54 51 280 309 Millennium 3 47.5 % 66 33 — 291 295 Pennant Midstream 3 47.0 % 11 6 — 228 246 Other Various 17 29 26 92 93 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % 66 (3 ) — 399 255 TransGas 46.5 % (12 ) — 5 — 28 Liquids Pipelines Grand Rapids 5 50.0 % 17 (1 ) — 996 876 Other 6 Various (20 ) — — 20 39 Energy Bruce Power 7 48.4 % 434 293 249 2,987 3,356 Portlands Energy 8 50.0 % 31 33 30 301 313 ASTC Power Partnership 50.0 % — (37 ) (23 ) — — Other Various 6 3 5 63 66 773 514 440 6,366 6,544 1 At December 31, 2017 , 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 ( 2016 – US$116 million ) due to the fair value assessment of assets at the time of acquisition. 2 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million ( 2016 – US$48 million ) due mainly to the fair value assessment of the assets at the time of acquisition. 3 Acquired as part of 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 amounts recorded in the Corporate segment. 5 Grand Rapids was placed in service in August 2017. At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $105 million ( 2016 – $86 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, 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil . 7 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $902 million ( 2016 – $942 million ) due to the fair value assessment of assets at the time of acquisitions. 8 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million ( 2016 – $70 million ) due mainly to interest capitalized during construction.
Summary of Financial Information of Equity Investments	year ended December 31 2017 2016 2015 (millions of Canadian $) Income Revenues 4,913 4,336 4,337 Operating and other expenses (2,993 ) (3,068 ) (3,142 ) Net income 1,636 1,080 1,046 Net income attributable to TransCanada 773 514 440 at December 31 2017 2016 (millions of Canadian $) Balance Sheet Current assets 2,176 1,669 Non-current assets 17,869 15,853 Current liabilities (1,577 ) (1,120 ) Non-current liabilities (8,217 ) (5,867 )

RATE-REGULATED BUSINESSES (Tabl

RATE-REGULATED BUSINESSES (Tables)	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	at December 31 2017 2016 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 967 861 n/a Deferred income taxes – U.S. Tax Reform 2 (27 ) — n/a Operating and debt-service regulatory assets 3 — 1 1 Pensions and other post-retirement benefits 1,4 388 382 n/a Foreign exchange on long-term debt 1,5 — 37 1-12 Other 71 74 n/a 1,399 1,355 Less: Current portion included in Other current assets (Note 7) 23 33 1,376 1,322 Regulatory Liabilities Operating and debt-service regulatory liabilities 3 188 47 1 Pensions and other post-retirement benefits 4 164 180 n/a ANR related post-employment and retirement benefits other than pension 6 66 141 n/a Long term adjustment account 7 1,142 659 46 Pipeline abandonment trust balance 825 541 n/a Bridging amortization account 7 202 451 13 Cost of removal 8 216 226 n/a Deferred income taxes 75 — n/a Deferred income taxes – U.S. Tax Reform 2 1,659 — n/a Other 47 54 n/a 4,584 2,299 Less: Current portion included in Accounts payable and other (Note 14) 263 178 4,321 2,121 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 These balances represent the impact of U.S. Tax Reform. The regulatory assets and regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax assets and liabilities that gave rise to the regulatory assets and liabilities. See Note 16, Income taxes, for further information. 3 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar years. 4 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 customers in future rates. 5 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. 6 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, $26 million ( US$21 million ) of the regulatory liability balance at December 31, 2017 (2016 – $46 million , US$34 million ) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $40 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. 7 These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. 8 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 subsidiaries for future costs to be incurred.

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of goodwill recorded on the entity's acquisitions in the U.S.	The Company has recorded the following Goodwill on its acquisitions in the U.S.: (millions of Canadian $) U.S. Natural Gas Pipelines Energy Total Balance at January 1, 2016 3,667 1,145 4,812 Acquisition of Columbia (Note 5) 10,078 — 10,078 Impairment charge — (1,085 ) (1,085 ) Foreign exchange rate changes 213 (60 ) 153 Balance at December 31, 2016 13,958 — 13,958 Columbia adjustment (Note 5) 71 — 71 Foreign exchange rate changes (945 ) — (945 ) Balance at December 31, 2017 13,084 — 13,084

INTANGIBLE AND OTHER ASSETS (Ta

INTANGIBLE AND OTHER ASSETS (Tables)	12 Months Ended
	Dec. 31, 2017
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Schedule of Other Assets	at December 31 2017 2016 (millions of Canadian $) Capital projects in development 596 2,094 Deferred income tax assets (Note 16) 316 392 Employee post-retirement benefits (Note 23) 193 189 Fair value of derivative contracts (Note 24) 73 133 Other 306 218 1,484 3,026

NOTES PAYABLE (Tables)

NOTES PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2017
Short-term Debt [Abstract]
Schedule of Notes Payable	2017 2016 (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 Canadian 884 1.6 % 509 0.9 % U.S. (2017 – US$688; 2016 – US$197) 862 2.2 % 265 0.5 % MXN (2017 – MXN$275) 17 8.0 % — — 1,763 774
Schedule of Credit Facilities	These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2017 2016 Borrower Description Matures Total Facilities Unused Capacity Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 1 : TCPL Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes December 2022 3.0 3.0 3.0 TCPL Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes December 2018 US 2.0 US 2.0 US 2.0 TCPL USA Used for TCPL USA general corporate purposes, guaranteed by TCPL December 2018 US 1.0 US 0.6 US 1.0 Columbia Used for Columbia general corporate purposes, guaranteed by TCPL December 2018 US 1.0 US 1.0 US 1.0 TAIL Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL December 2018 US 0.5 US 0.5 US 0.5 Demand senior unsecured revolving credit facilities 1 : TCPL/TCPL USA Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL Demand 1.9 0.5 1.9 Mexican subsidiary Used for Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 MXN 4.7 — 1 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, 2017, the Company was in compliance with all debt covenants.

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2017
Payables and Accruals [Abstract]
Schedule of Accounts Payable and Other	at December 31 2017 2016 (millions of Canadian $) Trade payables 2,847 2,443 Fair value of derivative contracts (Note 24) 387 607 Unredeemed shares of Columbia 312 317 Regulatory liabilities (Note 10) 263 178 Other 248 316 4,057 3,861

OTHER LONG-TERM LIABILITIES (Ta

OTHER LONG-TERM LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2017
Deferred Costs, Noncurrent [Abstract]
Schedule of Other Long-Term Liabilities	at December 31 2017 2016 (millions of Canadian $) Employee post-retirement benefits (Note 23) 389 448 Fair value of derivative contracts (Note 24) 72 330 Asset retirement obligations 98 108 Guarantees (Note 27) 16 82 Other 152 215 727 1,183

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	year ended December 31 2017 2016 2015 (millions of Canadian $) Current Canada 113 116 44 Foreign 36 40 92 149 156 136 Deferred Canada (185 ) 101 33 Foreign 751 95 (135 ) Foreign – U.S. Tax Reform (804 ) — — (238 ) 196 (102 ) Income Tax (Recovery)/Expense (89 ) 352 34
Schedule of Geographic Components of Income	year ended December 31 2017 2016 2015 (millions of Canadian $) Canada (339 ) 219 (624 ) Foreign 3,645 618 (482 ) Income/(Loss) before Income Taxes 3,306 837 (1,106 )
Reconciliation of Income Tax Expense	year ended December 31 2017 2016 2015 (millions of Canadian $) Income/(loss) before income taxes 3,306 837 (1,106 ) Federal and provincial statutory tax rate 27 % 27 % 26 % Expected income tax expense/(recovery) 893 226 (288 ) U.S. Tax Reform (804 ) — — Foreign income tax rate differentials (81 ) (196 ) 14 Income from equity investments and non-controlling interests (64 ) (68 ) (56 ) Income tax differential related to regulated operations (42 ) 81 159 Non-taxable portion of capital gains (42 ) — — Asset impairment charges 1 34 242 170 Non-deductible amounts 4 46 — Tax rate and legislative changes — — 34 Other 13 21 1 Income Tax (Recovery)/Expense (89 ) 352 34 1 Net of nil (2016 – $112 million ; 2015 – $311 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 2017 2016 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,379 2,063 Difference in accounting and tax bases of impaired assets and assets held for sale 651 1,168 Regulatory and other deferred amounts 512 277 Unrealized foreign exchange losses on long-term debt 216 446 Financial instruments 10 34 Other 227 352 2,995 4,340 Less: valuation allowance 832 1,336 2,163 3,004 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 6,240 9,015 Equity investments 632 905 Taxes on future revenue requirement 238 198 Other 140 156 7,250 10,274 Net Deferred Income Tax Liabilities 5,087 7,270 The above deferred tax amounts have been classified in the Consolidated balance sheet as follows: at December 31 2017 2016 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 12) 316 392 Deferred Income Tax Liabilities Deferred income tax liabilities 5,403 7,662 Net Deferred Income Tax Liabilities 5,087 7,270
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 2017 2016 2015 (millions of Canadian $) Unrecognized tax benefit at beginning of year 18 17 18 Gross increases – tax positions in prior years — 3 2 Gross decreases – tax positions in prior years (1 ) — (2 ) Gross increases – tax positions in current year 2 2 1 Settlement — (1 ) — Lapse of statutes of limitations (4 ) (3 ) (2 ) Unrecognized Tax Benefit at End of Year 15 18 17

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	The Company issued long-term debt over the three years ended December 31, 2017 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 Facility 1 June 2018 US 5,213 Floating June 2016 Medium Term Notes July 2023 300 3.69 % 2 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 % November 2015 Senior Unsecured Notes November 2017 US 1,000 1.625 % October 2015 Medium Term Notes November 2041 400 4.55 % July 2015 Medium Term Notes July 2025 750 3.30 % March 2015 Senior Unsecured Notes March 2045 US 750 4.60 % January 2015 Senior Unsecured Notes January 2018 US 500 1.875 % January 2015 Senior Unsecured Notes January 2018 US 250 Floating TUSCARORA GAS TRANSMISSION COMPANY August 2017 Term Loan August 2020 US 25 Floating April 2016 Term Loan April 2019 US 10 Floating TC PIPELINES, LP May 2017 Senior Unsecured Notes May 2027 US 500 3.90 % September 2015 Unsecured Term Loan October 2018 US 170 Floating March 2015 Senior Unsecured Notes March 2025 US 350 4.375 % TRANSCANADA PIPELINE USA LTD. June 2016 Acquisition Bridge Facility 1 June 2018 US 1,700 Floating ANR PIPELINE COMPANY June 2016 Senior Unsecured Notes June 2026 US 240 4.14 % GAS TRANSMISSION NORTHWEST LLC June 2015 Unsecured Term Loan June 2019 US 75 Floating 1 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 the second quarter 2017. 2 Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent . 2017 2016 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Debentures Canadian 2018 to 2020 500 10.8 % 600 10.7 % U.S. (2017 and 2016 – US$400) 2021 501 9.9 % 537 9.9 % Medium Term Notes Canadian 2019 to 2047 6,504 4.9 % 5,804 4.6 % Senior Unsecured Notes U.S. (2017 – US$14,892; 2016 – US$14,642) 2018 to 2045 18,644 5.1 % 19,660 5.1 % Acquisition Bridge Facility (2017 – nil; 2016 – US$2,013) — — — 2,702 1.9 % 26,149 29,303 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2017 and 2016 – US$200) 2023 250 7.9 % 269 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2017 and 2016 – US$33) 2026 41 7.5 % 44 7.5 % 895 917 TRANSCANADA PIPELINE USA LTD. Acquisition Bridge Facility (2017 – nil; 2016 – US$1,700) — — — 2,283 1.9 % COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2017 and 2016 – US$2,750) 2 2018 to 2045 3,443 4.0 % 3,692 4.0 % TC PIPELINES, LP Unsecured Loan Facility U.S. (2017 – US$185; 2016 – US$160) 2021 232 2.7 % 215 1.9 % Unsecured Term Loan U.S. (2017 and 2016 – US$670) 3 2020 to 2022 839 2.7 % 899 1.9 % Senior Unsecured Notes U.S. (2017 – US$1,200; 2016 – US$700) 2021 to 2027 1,502 4.4 % 940 4.7 % 2,573 2,054 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2017 and 2016 – US$672) 2021 to 2026 842 7.2 % 903 7.2 % GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2017 – US$55; 2016 – US$65) 2019 69 1.1 % 87 1.6 % Senior Unsecured Notes U.S. (2017 and 2016 – US$250) 2020 to 2035 313 5.6 % 336 5.6 % 382 423 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2017 – US$259; 2016 – US$278) 2018 to 2030 324 7.7 % 373 7.7 % 2017 2016 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Secured Notes 4 U.S. (2017 – US$30; 2016 – US$53) 2018 38 6.0 % 71 6.0 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2017 – US$25; 2016 – US$10) 2020 31 1.1 % 13 1.9 % Senior Secured Notes U.S. (2017 – nil; 2016 – US$12) — — — 16 4.0 % 31 29 34,677 40,048 Current portion of long-term debt (2,866 ) (1,838 ) Unamortized debt discount and issue costs (174 ) (191 ) Fair value adjustments 5 238 293 31,875 38,312 1 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. 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$170 million and US$500 million term loan facilities were amended in September 2017 to extend the maturity dates from 2018 to 2020 and 2022, respectively. 4 These notes are secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements. 5 The fair value adjustments include $242 million (2016 – $293 million ) related to the acquisition of Columbia. Refer to Note 5, Acquisition of Columbia, for further information. The fair value adjustments also include a decrease of $4 million (2016 – nil ) 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, 2017, principal repayments for the next five years on the Company's Long-term debt are approximately as follows: (millions of Canadian $) 2018 2019 2020 2021 2022 Principal repayments on long-term debt 2,866 3,189 2,834 2,085 1,929
Schedule of Retired Long-Term Debt	The Company retired/repaid long-term debt over the three years ended December 31, 2017 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED December 2017 Debentures 100 9.80 % November 2017 Senior Unsecured Notes US 1,000 1.625 % June 2017 Acquisition Bridge Facility 1 US 1,513 Floating February 2017 Acquisition Bridge Facility 1 US 500 Floating January 2017 Medium Term Notes 300 5.10 % November 2016 Acquisition Bridge Facility 1 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 % August 2015 Debentures 150 11.90 % June 2015 Senior Unsecured Notes US 500 3.40 % March 2015 Senior Unsecured Notes US 500 0.875 % January 2015 Senior Unsecured Notes US 300 4.875 % TUSCARORA GAS TRANSMISSION COMPANY August 2017 Senior Secured Notes US 12 3.82 % TRANSCANADA PIPELINE USA LTD. June 2017 Acquisition Bridge Facility 1 US 630 Floating April 2017 Acquisition Bridge Facility 1 US 1,070 Floating NOVA GAS TRANSMISSION LTD. February 2016 Debentures 225 12.20 % GAS TRANSMISSION NORTHWEST LLC June 2015 Senior Unsecured Notes US 75 5.09 % 1 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 the second quarter 2017.
Schedule of Interest Expense	Interest expense in the three years ended December 31 was as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) Interest on long-term debt 1,794 1,765 1,487 Interest on junior subordinated notes 348 180 116 Interest on short-term debt 33 18 16 Capitalized interest (173 ) (176 ) (280 ) Amortization and other financial charges 1 67 211 31 2,069 1,998 1,370 1 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.

JUNIOR SUBORDINATED NOTES (Tabl

JUNIOR SUBORDINATED NOTES (Tables)	12 Months Ended
	Dec. 31, 2017
Junior Subordinated Notes [Abstract]
Schedule of Junior Subordinated Notes	2017 2016 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED U.S.$1,000 notes issued 2007 1 2067 1,252 5.0 % 3 1,343 6.4 % U.S.$750 notes issued 2015 1,2 2075 939 5.9 % 1,007 5.5 % U.S.$1,200 notes issued 2016 1,2 2076 1,502 6.6 % 1,611 6.2 % U.S.$1,500 notes issued 2017 1, 2 2077 1,878 5.6 % — — $1,500 notes issued 2017 1, 2 2077 1,500 5.1 % — — 7,071 3,961 Unamortized debt discount and issue costs (64 ) (30 ) 7,007 3,931 1 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 2 The Junior subordinated notes were issued to TransCanada Trust, 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. 3 In May 2017, Junior subordinated notes of US $1 billion converted from 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 .

NON-CONTROLLING INTERESTS (Tabl

NON-CONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017 2016 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,852 1,596 Non-controlling interest in Portland Natural Gas Transmission System — 130 1,852 1,726 The Company's Net income attributable to non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 220 215 (13 ) Non-controlling interest in Portland Natural Gas Transmission System 1 9 20 19 Non-controlling interest in Columbia Pipeline Partners LP 2 9 17 — 238 252 6 1 Non-controlling interest in 2017 for the period January 1 to May 31 when TransCanada sold its remaining interest in PNGTS to TC PipeLines, LP. Refer to Note 26, Other acquisitions and dispositions for further information. 2 Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of CPPL.

COMMON SHARES (Tables)

COMMON SHARES (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2015 708,662 12,202 Exercise of options 737 30 Repurchase of shares (6,785 ) (130 ) Outstanding at December 31, 2015 702,614 12,102 Issued under public offerings 1 156,825 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 program 1 3,462 216 Exercise of options 1,331 62 Outstanding at December 31, 2017 881,376 21,167 1 Net of underwriting commissions and deferred income taxes.
Schedule of Weighted Average Shares	Weighted Average Common Shares Outstanding (millions) 2017 2016 2015 Basic 872 759 709 Diluted 874 760 709
Schedule of Stock Options Activity	Number of (thousands) Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (years) Options outstanding at January 1, 2017 10,630 $48.28 Options granted 2,066 $62.22 Options exercised (1,331 ) $42.03 Options forfeited/expired (339 ) $56.89 Options Outstanding at December 31, 2017 11,026 $51.38 3.9 Options Exercisable at December 31, 2017 6,559 $48.59 3.0
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 2017 2016 2015 Weighted average fair value $7.22 $5.67 $6.45 Expected life (years) 5.7 5.8 5.8 Interest rate 1.2 % 0.7 % 1.1 % Volatility 1 18 % 21 % 18 % Dividend yield 3.6 % 4.9 % 3.7 % Forfeiture rate 2 — 5 % 5 % 1 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. 2 On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance. Refer to Note 3, Accounting changes, for further information.
Schedule of Additional Option Information	The following table summarizes additional stock option information: year ended December 31 2017 2016 2015 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 28 31 10 Fair value of options that have vested 140 126 91 Total options vested 2.3 million 2.1 million 2.0 million

PREFERRED SHARES (Tables)

PREFERRED SHARES (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017 2016 2015 (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 Floating 4 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 Floating 4 Floating $25.00 June 30, 2020 Series 3 134 134 134 Series 5 12,714 2.263 % $0.56575 $5 $25.00 January 30, 2021 Series 6 310 310 342 Series 6 1,286 Floating 4 Floating $25.00 January 30, 2021 Series 5 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 — Series 15 40,000 4.90 % $1.225 $25.00 May 31, 2022 Series 16 988 988 — 3,980 3,980 2,499 1 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. 2 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. 4 The floating quarterly dividend rate for the Series 2 preferred shares is 2.792 per cent and for the Series 4 preferred shares is 2.152 per cent for the period starting December 29, 2017 to, but excluding, March 29, 2018. The floating quarterly dividend rate for the Series 6 preferred shares is 2.549 per cent for the period starting October 30, 2017 to, but excluding, January 30, 2018. These rates will reset each quarter going forward.

OTHER COMPREHENSIVE (LOSS)_IN55

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Components of Other Comprehensive Income/(Loss)	Components of Other comprehensive (loss)/income, including the portion attributable to non-controlling interests and related tax effects, are as follows: year ended December 31, 2017 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation losses on net investment in foreign operations (746 ) (3 ) (749 ) Reclassification of foreign currency translation gains on net investment on disposal of foreign operations (77 ) — (77 ) Change in fair value of net investment hedges — — — 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 $) 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 ) year ended December 31, 2015 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 798 15 813 Change in fair value of net investment hedges (505 ) 133 (372 ) Change in fair value of cash flow hedges (92 ) 35 (57 ) Reclassification to net income of gains and losses on cash flow hedges 144 (56 ) 88 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 74 (23 ) 51 Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 41 (9 ) 32 Other comprehensive income on equity investments 62 (15 ) 47 Other Comprehensive Income 522 80 602
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 Total 1 AOCI balance at January 1, 2015 (518 ) (128 ) (281 ) (308 ) (1,235 ) Other comprehensive income/(loss) before reclassifications 2 135 (57 ) 51 33 162 Amounts reclassified from AOCI — 88 32 14 134 Net current period other comprehensive income 135 31 83 47 296 AOCI balance at December 31, 2015 (383 ) (97 ) (198 ) (261 ) (939 ) Other comprehensive income/(loss) before reclassifications 2 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 4 (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 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 In 2017 , other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $159 million ( 2016 – $14 million losses; 2015 – $306 million gains) and gains of $4 million ( 2016 – $3 million gains and 2015 – nil ), 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. 4 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 $19 million ( $14 million , net of tax) at December 31, 2017 . These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.
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 1 Affected Line Item year ended December 31 2017 2016 2015 (millions of Canadian $) Cash flow hedges Commodities 20 (57 ) (128 ) Revenues (Energy) Interest (17 ) (14 ) (16 ) Interest expense 3 (71 ) (144 ) Total before tax (1 ) 29 56 Income tax (recovery)/expense 2 (42 ) (88 ) Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial loss and past service cost (15 ) (22 ) (41 ) Plant operating costs and other 2 Settlement charge (2 ) — — Plant operating costs and other 2 (17 ) (22 ) (41 ) Total before tax 5 6 9 Income tax (recovery)/expense (12 ) (16 ) (32 ) Net of tax Equity investments Equity income (15 ) (19 ) (19 ) Income from equity investments 4 5 5 Income tax (recovery)/expense (11 ) (14 ) (14 ) Net of tax Currency translation adjustments Realization of foreign currency translation gains on disposal of foreign operations 77 — — Gain/(loss) on sale of assets held for sale/sold — — — Income tax (recovery)/expense 77 — — Net of tax 1 All 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.

EMPLOYEE POST-RETIREMENT BENE56

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Schedule of Payments for Defined Benefit Plans	Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) DB Plans 163 111 96 Other post-retirement benefit plans 7 8 6 Savings and DC Plans 42 52 41 212 171 143
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 Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,456 2,780 372 225 Service cost 113 107 4 3 Interest cost 135 127 14 13 Employee contributions 5 4 3 2 Benefits paid (166 ) (204 ) (19 ) (16 ) Actuarial loss/(gain) 253 111 19 (8 ) Acquisition of Columbia — 527 — 151 Curtailment (14 ) — (2 ) — Settlement (66 ) 2 — — Foreign exchange rate changes (70 ) 2 (16 ) 2 Benefit obligation – end of year 3,646 3,456 375 372 Change in Plan Assets Plan assets at fair value – beginning of year 3,208 2,591 354 45 Actual return on plan assets 358 227 45 14 Employer contributions 2 163 111 7 8 Employee contributions 5 4 3 2 Benefits paid (166 ) (204 ) (19 ) (16 ) Acquisition of Columbia — 475 — 294 Settlement (57 ) — — — Foreign exchange rate changes (60 ) 4 (25 ) 7 Plan assets at fair value – end of year 3,451 3,208 365 354 Funded Status – Plan Deficit (195 ) (248 ) (10 ) (18 ) 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 $260 million in letters of credit provided to the Canadian DB Plan for funding purposes ( 2016 – $233 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 Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Intangible and other assets (Note 12) — — 193 189 Accounts payable and other (1 ) — (8 ) (7 ) Other long-term liabilities (Note 15) (194 ) (248 ) (195 ) (200 ) (195 ) (248 ) (10 ) (18 )
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 Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Projected benefit obligation 1 (3,646 ) (3,456 ) (203 ) (207 ) Plan assets at fair value 3,451 3,208 — — Funded Status – Plan Deficit (195 ) (248 ) (203 ) (207 ) 1 The projected benefit obligation for the pension benefit plan differs 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 2017 2016 (millions of Canadian $) Accumulated benefit obligation (3,372 ) (3,202 ) Plan assets at fair value 3,451 3,208 Funded Status – Plan Surplus 79 6
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 2017 2016 (millions of Canadian $) Accumulated benefit obligation (944 ) (990 ) Plan assets at fair value 925 868 Funded Status – Plan Deficit (19 ) (122 )
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 Target Allocations at December 31 2017 2016 2017 Debt securities 30 % 31 % 25% to 40% Equity securities 64 % 63 % 45% to 75% Alternatives 6 % 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 (millions of Canadian $) 2017 2016 2017 2016 Debt securities 7 9 0.2 % 0.2 % Equity securities 3 4 0.1 % 0.1 %
Schedule of Plan Assets for DB Plans and Other Post-Retirement Benefits Measured at Fair Value	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 Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 Asset Category Cash and Cash Equivalents 44 22 17 12 — — 61 34 2 1 Equity Securities: Canadian 410 388 151 143 — — 561 531 15 15 U.S. 543 504 354 476 — — 897 980 24 27 International 45 39 322 327 — — 367 366 10 10 Global — — 301 235 — — 301 235 8 7 Emerging 8 7 147 137 — — 155 144 4 4 Fixed Income Securities: Canadian Bonds: Federal — — 193 192 — — 193 192 5 5 Provincial — — 194 179 — — 194 179 5 5 Municipal — — 8 8 — — 8 8 — — Corporate — — 122 126 — — 122 126 3 4 U.S. Bonds: Federal — — 244 82 — — 244 82 6 2 State — — 41 41 — — 41 41 1 1 Municipal — — 4 39 — — 4 39 — 1 Corporate — — 234 188 — — 234 188 6 5 International: Government — — 4 6 — — 4 6 — — Corporate — — 5 21 — — 5 21 — 1 Mortgage backed — — 73 62 — — 73 62 2 2 Other Investments: Real estate — — — — 140 133 140 133 4 4 Infrastructure — — — — 70 58 70 58 2 2 Private equity funds — — — — 6 8 6 8 — — Funds held on deposit 136 129 — — — — 136 129 3 4 1,186 1,089 2,414 2,274 216 199 3,816 3,562 100 100
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, 2015 14 Purchases and sales 183 Realized and unrealized gains 2 Balance at December 31, 2016 199 Purchases and sales 11 Realized and unrealized gains 6 Balance at December 31, 2017 216
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 2018 181 19 2019 187 20 2020 190 20 2021 196 20 2022 200 20 2023 to 2027 1,054 98
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 Other Post-Retirement at December 31 2017 2016 2017 2016 Discount rate 3.60 % 4.00 % 3.70 % 4.15 % Rate of compensation increase 3.00 % 1.20 % — —
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 Other Post-Retirement year ended December 31 2017 2016 2015 2017 2016 2015 Discount rate 3.95 % 4.20 % 4.15 % 4.15 % 4.30 % 4.20 % Expected long-term rate of return on plan assets 6.50 % 6.70 % 6.95 % 6.05 % 5.95 % 4.60 % Rate of compensation increase 1.20 % 0.80 % 3.15 % — — —
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 15 (13 )
Schedule of Net Benefit Costs	The Company's net benefit cost recognized is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2015 2017 2016 2015 Service cost 108 107 108 4 3 3 Interest cost 122 127 115 14 13 10 Expected return on plan assets (178 ) (175 ) (155 ) (21 ) (11 ) (2 ) Amortization of actuarial loss 14 20 35 1 2 3 Amortization of past service cost — — 2 — — 1 Amortization of regulatory asset 37 27 23 1 1 1 Amortization of transitional obligation related to regulated business — — — — 2 2 Settlement charge – regulatory asset 2 — — — — — Settlement charge – AOCI 2 — — — — — Net Benefit Cost Recognized 107 106 128 (1 ) 10 18
Schedule of the Pre-Tax Amounts Recognized in AOCI	Pre-tax amounts recognized in AOCI were as follows: 2017 2016 2015 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 273 11 270 21 247 28
Schedule of the Pre-Tax Amounts Recognized in OCI	Pre-tax amounts recognized in OCI were as follows: 2017 2016 2015 at December 31 Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits (millions of Canadian $) Amortization of net loss from AOCI to OCI (18 ) (1 ) (20 ) (2 ) (34 ) (4 ) Amortization of prior service costs from AOCI to OCI — — — — (2 ) (1 ) Curtailment (14 ) (2 ) — — — — Settlement (11 ) — — — — — Funded status adjustment 46 (7 ) 43 (5 ) (67 ) (7 ) 3 (10 ) 23 (7 ) (103 ) (12 )

RISK MANAGEMENT AND FINANCIAL57

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative financial instruments
Summary of Derivative Instruments	The maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows: at December 31, 2017 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 66,132 133 6 — — Sales 1 42,836 135 7 — — Millions of U.S. dollars — — — US 2,931 US 2,300 Millions of Mexican pesos — — — MXN 100 — Maturity dates 2018-2022 2018-2021 2018 2018 2018-2022 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. at December 31, 2016 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 86,887 182 6 — — Sales 1 58,561 147 6 — — Millions of U.S. dollars — — — US 2,394 US 1,550 Maturity dates 2017-2021 2017-2020 2017 2017 2017-2019 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively .
Schedule of 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: 2017 2016 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Long-term debt, including current portion 1,2 (Note 17) (34,741 ) (40,180 ) (40,150 ) (45,047 ) Junior subordinated notes (Note 18) (7,007 ) (7,233 ) (3,931 ) (3,825 ) (41,748 ) (47,413 ) (44,081 ) (48,872 ) 1 Long-term debt is recorded at amortized cost, except for US$1.1 billion ( 2016 – US$850 million ) that is attributed to hedged risk and recorded at fair value. 2 Net income in 2017 included unrealized gains of $4 million ( 2016 – gains of $2 million ) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.1 billion of long-term debt at December 31, 2017 ( 2016 – US$850 million ). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. Available for Sale Assets Summary The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets: 2017 2016 LMCI Restricted Investments Other Restricted Investments 2 LMCI Restricted Investments Other Restricted Investments 2 (millions of Canadian $) Fair value 1 Fixed income securities (maturing within 1 year) — 23 — 19 Fixed income securities (maturing within 1-5 years) — 107 — 117 Fixed income securities (maturing within 5-10 years) 14 — 9 — Fixed income securities (maturing after 10 years) 790 — 513 — 804 130 522 136 1 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. 2 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. 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 Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 1 — — 249 250 Foreign exchange — — 8 70 78 Interest rate 3 — — 1 4 4 — 8 320 332 Intangible and other assets (Note 12) Commodities 2 — — — 69 69 Interest rate 4 — — — 4 4 — — 69 73 Total Derivative Assets 8 — 8 389 405 Accounts payable and other (Note 14) Commodities 2 (6 ) — — (208 ) (214 ) Foreign exchange — — (159 ) (10 ) (169 ) Interest rate — (4 ) — — (4 ) (6 ) (4 ) (159 ) (218 ) (387 ) Other long-term liabilities (Note 15) Commodities 2 (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 balance sheet classification of the fair value of derivative instruments as at December 31, 2016 is as follows: at December 31, 2016 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 6 — — 351 357 Foreign exchange — — 6 10 16 Interest rate 1 1 — 1 3 7 1 6 362 376 Intangible and other assets (Note 12) Commodities 2 4 — — 118 122 Foreign exchange — — 10 — 10 Interest rate 1 — — — 1 5 — 10 118 133 Total Derivative Assets 12 1 16 480 509 Accounts payable and other (Note 14) Commodities 2 — — — (330 ) (330 ) Foreign exchange — — (237 ) (38 ) (275 ) Interest rate (1 ) (1 ) — — (2 ) (1 ) (1 ) (237 ) (368 ) (607 ) Other long-term liabilities (Note 15) Commodities 2 — — — (118 ) (118 ) Foreign exchange — — (211 ) — (211 ) Interest rate — (1 ) — — (1 ) — (1 ) (211 ) (118 ) (330 ) Total Derivative Liabilities (1 ) (2 ) (448 ) (486 ) (937 ) Total Derivatives 11 (1 ) (432 ) (6 ) (428 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids.
Unrealized Gain (Loss) on Investments	2017 2016 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized (losses)/gains in the year ended December 31 (3 ) 1 (28 ) (1 ) Net realized (losses)/gains in the year ended December 31 3 (1 ) — — — 1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. 2 Unrealized gains and losses on other restricted investments are included in OCI. 3 The realized gains or losses on the sale of LMCI restricted investment securities are determined using the average cost basis.
Realized Gain (Loss) on Investments	2017 2016 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized (losses)/gains in the year ended December 31 (3 ) 1 (28 ) (1 ) Net realized (losses)/gains in the year ended December 31 3 (1 ) — — — 1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. 2 Unrealized gains and losses on other restricted investments are included in OCI. 3 The realized gains or losses on the sale of LMCI restricted investment securities are determined using the average cost basis.
Summary of Unrealized and Realized Gains/(Losses) of Derivative Instruments	The following summary does not include hedges of the net investment in foreign operations. year ended December 31 2017 2016 2015 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 2 62 123 (37 ) Foreign exchange 88 25 (21 ) Interest rate (1 ) — — Amount of realized (losses)/gains in the year Commodities (107 ) (204 ) (151 ) Foreign exchange 18 62 (112 ) Interest rate 1 — — Derivative instruments in hedging relationships Amount of realized gains/(losses) in the year Commodities 23 (167 ) (179 ) Foreign exchange 5 (101 ) — Interest rate 1 4 8 1 Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively. 2 In 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 2017 2016 2015 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI (effective portion) 1 Commodities (1 ) 39 (92 ) Interest rate 4 5 — 3 44 (92 ) Reclassification of (losses)/gains on derivative instruments from AOCI to Net income (effective portion) 1 Commodities 2 (20 ) 57 128 Interest rate 3 17 14 16 (3 ) 71 144 1 No amounts have been excluded from the assessment of hedge effectiveness. In 2017 and 2016 , there were no gains or losses included in Net Income related to ineffective portions. Amounts in parentheses indicate losses recorded to OCI and AOCI. 2 Reported within Revenues on the Consolidated statement of income. 3 Reported within Interest expense on the Consolidated statement of income.
Schedule of Offsetting Assets	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 Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) 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. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2016 : at December 31, 2016 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 479 (362 ) 117 Foreign exchange 26 (26 ) — Interest rate 4 (1 ) 3 509 (389 ) 120 Derivative – Liability Commodities (448 ) 362 (86 ) Foreign exchange (486 ) 26 (460 ) Interest rate (3 ) 1 (2 ) (937 ) 389 (548 ) 1 Amounts available for offset do not include cash collateral pledged or received.
Schedule of Offsetting Liabilities	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 Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) 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. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2016 : at December 31, 2016 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 479 (362 ) 117 Foreign exchange 26 (26 ) — Interest rate 4 (1 ) 3 509 (389 ) 120 Derivative – Liability Commodities (448 ) 362 (86 ) Foreign exchange (486 ) 26 (460 ) Interest rate (3 ) 1 (2 ) (937 ) 389 (548 ) 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 2017 , are categorized as follows: at December 31, 2017 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) 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 fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2016 , are categorized as follows: at December 31, 2016 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 134 326 19 479 Foreign exchange — 26 — 26 Interest rate — 4 — 4 Derivative Instrument Liabilities: Commodities (102 ) (343 ) (3 ) (448 ) Foreign exchange — (486 ) — (486 ) Interest rate — (3 ) — (3 ) 32 (476 ) 16 (428 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016 .
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) 2017 2016 Balance at beginning of year 16 9 Transfers out of Level III (19 ) (1 ) Total (losses)/gains included in Net income (17 ) 13 Sales (5 ) (3 ) Settlements 18 (2 ) Balance at end of year 1 (7 ) 16 1 Revenues include unrealized losses attributed to derivatives in the Level III category that were still held at December 31, 2017 of $7 million ( 2016 — gains of $7 million ).
Designated as a net investment hedge
Derivative financial instruments
Summary of Derivative Instruments	The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows: 2017 2016 at December 31 Fair 1 Notional or Fair 1 Notional or (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019) 2 (199 ) US 1,200 (425 ) US 2,350 U.S. dollar foreign exchange options (maturing 2018) 5 US 500 — — U.S. dollar foreign exchange forward contracts — — (7 ) US 150 (194 ) US 1,700 (432 ) US 2,500 1 Fair value equals carrying value. 2 In 2017 , Net income includes net realized gains of $4 million ( 2016 – gains of $6 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 2017 2016 (millions of Canadian $, unless otherwise noted) Notional amount 25,400 (US 20,200) 26,600 (US 19,800) Fair value 28,900 (US 23,100) 29,400 (US 21,900)

CHANGES IN OPERATING WORKING 58

CHANGES IN OPERATING WORKING CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2017
CHANGES IN OPERATING WORKING CAPITAL
Schedule of changes in operating working capital	year ended December 31 2017 2016 2015 (millions of Canadian $) Increase in Accounts receivable (576 ) (482 ) (65 ) Increase in Inventories (38 ) (87 ) (3 ) Decrease/(increase) in Assets held for sale 14 (13 ) — Decrease/(increase) in Other current assets 189 328 (272 ) Increase/(decrease) in Accounts payable and other 151 424 (97 ) Increase in Accrued interest 12 62 91 (Decrease)/increase in Liabilities related to assets held for sale (25 ) 16 — (Increase)/decrease in Operating Working Capital (273 ) 248 (346 )

COMMITMENTS, CONTINGENCIES AN59

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)	12 Months Ended
	Dec. 31, 2017
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 Amounts Net (millions of Canadian $) 2018 75 4 71 2019 76 2 74 2020 73 2 71 2021 71 1 70 2022 63 — 63 2023 and thereafter 443 2 441 801 11 790
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: 2017 2016 year ended December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas ranging to 2020 315 2 805 53 Bruce Power ranging to 2018 88 1 88 1 Other jointly owned entities ranging to 2059 104 13 87 28 507 16 980 82 1 TransCanada's share of the potential estimated current or contingent exposure.

CORPORATE RESTRUCTURING COSTS (

CORPORATE RESTRUCTURING COSTS (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2015 60 27 87 Restructuring charges — 44 44 Cash payments (24 ) (8 ) (32 ) Restructuring liability as at December 31, 2016 36 63 99 Restructuring charges — 6 6 Cash payments (27 ) (16 ) (43 ) Restructuring Liability as at December 31, 2017 9 53 62

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2017
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 $) 2017 2016 ASSETS Current Assets Cash and cash equivalents 41 77 Accounts receivable 63 71 Inventories 23 25 Other 11 10 138 183 Plant, Property and Equipment 3,535 3,685 Equity Investments 917 606 Goodwill 490 525 Intangible and Other Assets 3 1 5,083 5,000 LIABILITIES Current Liabilities Accounts payable and other 137 80 Dividends payable 1 — Accrued interest 23 21 Current portion of long-term debt 88 76 249 177 Regulatory Liabilities 34 34 Other Long-Term Liabilities 3 4 Deferred Income Tax Liabilities 13 7 Long-Term Debt 3,244 2,827 3,543 3,049
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 $) 2017 2016 Balance sheet Equity investments 4,372 4,964 Off-balance sheet Potential exposure to guarantees 171 163 Maximum exposure to loss 4,543 5,127

DESCRIPTION OF TRANSCANADA'S 62

DESCRIPTION OF TRANSCANADA'S BUSINESS (Details)	12 Months Ended
	Dec. 31, 2017plantsegmentmikmBcf
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	40,429
Investments of regulated natural gas pipelines (in miles) | mi	25,121
U.S. Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km	49,779
Investments of regulated natural gas pipelines (in miles) | mi	30,931
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	1,680
Investments of regulated natural gas pipelines (in miles) | mi	1,044
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	11
Non-regulated natural gas storage facilities (in billion cubic feet) | Bcf	118

ACCOUNTING POLICIES (Details)

ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2017
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)	6.00%
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)

ACCOUNTING CHANGES (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Accounting Standards Update 2016-09, Excess Tax Benefit Component
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred income tax assets, net		CAD 12
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative-effect adjustment	CAD 12
Retained Earnings | Accounting Standards Update 2016-09, Excess Tax Benefit Component
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative-effect adjustment		CAD 12

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segmented information
Liquids Pipelines	CAD 2,009	CAD 1,755	CAD 1,879
Energy	3,593	4,206	4,091
Revenues	13,449	12,547	11,353
Income from equity investments	773	514	440
Plant operating costs and other	(3,906)	(3,861)	(3,303)
Commodity purchases resold	(2,382)	(2,172)	(2,237)
Property taxes	(569)	(555)	(517)
Depreciation and amortization	(2,055)	(1,939)	(1,765)
Goodwill and other asset impairment charges	(1,257)	(1,388)	(3,745)
Gain/(loss) on sale of assets held for sale/sold	631	(833)	(125)
Segmented earnings/(losses)	4,684	2,313	101
Interest expense	(2,069)	(1,998)	(1,370)
Allowance for funds used during construction	507	419	295
Interest income and other	184	103	(132)
Income/(Loss) before Income Taxes	3,306	837	(1,106)
Income tax recovery/(expense)	89	(352)	(34)
Net Income/(Loss)	3,395	485	(1,140)
Net income attributable to non-controlling interests	(238)	(252)	(6)
Net Income/(Loss) Attributable to Controlling Interests	3,157	233	(1,146)
Preferred share dividends	(160)	(109)	(94)
Net Income/(Loss) Attributable to Common Shares	2,997	124	(1,240)
Capital spending
Capital expenditures	7,383	5,007	3,918
Capital projects in development	146	295	511
Contributions to equity investments	1,681	765	493
Capital spending	9,210	6,067	4,922
Assets	86,101	88,051
GEOGRAPHIC INFORMATION
Revenues	13,449	12,547	11,353
Plant, Property and Equipment	57,277	54,475
Canada – domestic
Segmented information
Revenues	3,618	3,697	3,930
GEOGRAPHIC INFORMATION
Revenues	3,618	3,697	3,930
Canada – export
Segmented information
Revenues	1,255	1,177	1,292
GEOGRAPHIC INFORMATION
Revenues	1,255	1,177	1,292
United States
Segmented information
Revenues	8,006	7,295	5,872
GEOGRAPHIC INFORMATION
Revenues	8,006	7,295	5,872
Plant, Property and Equipment	30,693	29,414
Mexico
Segmented information
Revenues	570	378	259
GEOGRAPHIC INFORMATION
Revenues	570	378	259
Plant, Property and Equipment	4,952	4,530
Canadian
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	21,632	20,531
Intersegment Eliminations
Segmented information
Revenues	0	0	0
GEOGRAPHIC INFORMATION
Revenues	0	0	0
Corporate
Segmented information
Revenues	(51)	(56)	(47)
Income from equity investments	63	0	0
Plant operating costs and other	(51)	(64)	(105)
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 sale of assets held for sale/sold	0	0	0
Segmented earnings/(losses)	(39)	(120)	(152)
Capital spending
Capital expenditures	41	33	64
Capital projects in development	0	0	0
Contributions to equity investments	0	0	0
Capital spending	41	33	64
Assets	3,642	2,735
GEOGRAPHIC INFORMATION
Revenues	(51)	(56)	(47)
Plant, Property and Equipment	243	280
Canadian Natural Gas Pipelines
Segmented information
Natural Gas Pipelines	3,693	3,682	3,680
Canadian Natural Gas Pipelines | Operating segments
Segmented information
Natural Gas Pipelines	3,693	3,682	3,680
Income from equity investments	11	12	12
Plant operating costs and other	(1,300)	(1,245)	(1,204)
Commodity purchases resold	0	0	0
Property taxes	(260)	(267)	(272)
Depreciation and amortization	(908)	(875)	(849)
Goodwill and other asset impairment charges	0	0	0
Gain/(loss) on sale of assets held for sale/sold	0	0	0
Segmented earnings/(losses)	1,236	1,307	1,367
Capital spending
Capital expenditures	2,106	1,372	1,366
Capital projects in development	75	153	230
Contributions to equity investments	0	0	0
Capital spending	2,181	1,525	1,596
Assets	16,904	15,816
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	14,424	13,217
Canadian Natural Gas Pipelines | Intersegment Eliminations
Segmented information
Natural Gas Pipelines	0	0	0
U.S. Natural Gas Pipelines
Segmented information
Natural Gas Pipelines	3,584	2,526	1,444
U.S. Natural Gas Pipelines | Operating segments
Segmented information
Natural Gas Pipelines	3,635	2,582	1,491
Income from equity investments	240	214	162
Plant operating costs and other	(1,340)	(1,057)	(606)
Commodity purchases resold	0	0	0
Property taxes	(181)	(120)	(77)
Depreciation and amortization	(594)	(425)	(248)
Goodwill and other asset impairment charges	0	0	0
Gain/(loss) on sale of assets held for sale/sold	0	(4)	(125)
Segmented earnings/(losses)	1,760	1,190	597
Capital spending
Capital expenditures	3,712	1,517	534
Capital projects in development	0	0	3
Contributions to equity investments	118	5	0
Capital spending	3,830	1,522	537
Assets	35,898	34,422
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	20,262	18,055
U.S. Natural Gas Pipelines | Intersegment Eliminations
Segmented information
Natural Gas Pipelines	51	56	47
Mexico Natural Gas Pipelines
Segmented information
Natural Gas Pipelines	570	378	259
Mexico Natural Gas Pipelines | Operating segments
Segmented information
Natural Gas Pipelines	570	378	259
Income from equity investments	(9)	(3)	5
Plant operating costs and other	(42)	(43)	(51)
Commodity purchases resold	0	0	0
Property taxes	0	0	0
Depreciation and amortization	(93)	(45)	(44)
Goodwill and other asset impairment charges	0	0	0
Gain/(loss) on sale of assets held for sale/sold	0	0	0
Segmented earnings/(losses)	426	287	169
Capital spending
Capital expenditures	833	944	566
Capital projects in development	0	0	0
Contributions to equity investments	1,121	198	0
Capital spending	1,954	1,142	566
Assets	5,716	5,013
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	4,952	4,527
Mexico Natural Gas Pipelines | Intersegment Eliminations
Segmented information
Natural Gas Pipelines	0	0	0
Liquids Pipelines
Segmented information
Liquids Pipelines	2,009	1,755	1,879
Liquids Pipelines | Operating segments
Segmented information
Liquids Pipelines	2,009	1,755	1,879
Income from equity investments	(3)	(1)	0
Plant operating costs and other	(623)	(568)	(492)
Commodity purchases resold	0	0	0
Property taxes	(89)	(88)	(79)
Depreciation and amortization	(309)	(292)	(283)
Goodwill and other asset impairment charges	(1,236)	0	(3,686)
Gain/(loss) on sale of assets held for sale/sold	0	0	0
Segmented earnings/(losses)	(251)	806	(2,661)
Capital spending
Capital expenditures	341	668	1,012
Capital projects in development	71	142	278
Contributions to equity investments	117	327	311
Capital spending	529	1,137	1,601
Assets	15,438	16,896
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	13,419	14,147
Liquids Pipelines | Intersegment Eliminations
Segmented information
Liquids Pipelines	0	0	0
Energy
Segmented information
Energy	3,593	4,206	4,091
Energy | Operating segments
Segmented information
Energy	3,593	4,206	4,091
Income from equity investments	471	292	261
Plant operating costs and other	(550)	(884)	(845)
Commodity purchases resold	(2,382)	(2,172)	(2,237)
Property taxes	(39)	(80)	(89)
Depreciation and amortization	(151)	(302)	(341)
Goodwill and other asset impairment charges	(21)	(1,388)	(59)
Gain/(loss) on sale of assets held for sale/sold	631	(829)	0
Segmented earnings/(losses)	1,552	(1,157)	781
Capital spending
Capital expenditures	350	473	376
Capital projects in development	0	0	0
Contributions to equity investments	325	235	182
Capital spending	675	708	558
Assets	8,503	13,169
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	CAD 3,977	4,249
Energy | Intersegment Eliminations
Segmented information
Energy		CAD 0	CAD 0

ACQUISITION OF COLUMBIA (Detail

ACQUISITION OF COLUMBIA (Details) $ / shares in Units, shares in Millions, CAD in Millions, $ in Millions

Jul. 01, 2016CADmikmBcf

Jul. 01, 2016USD ($)

Jun. 30, 2017CAD

Jun. 30, 2017USD ($)

Jun. 30, 2017USD ($)

Dec. 31, 2016CAD

Dec. 31, 2017CAD

Dec. 31, 2016CAD

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Jul. 01, 2016USD ($)mikm$ / sharesBcf

Jun. 30, 2016$ / sharesshares

Apr. 30, 2016CADshares

Apr. 01, 2016shares

Dec. 31, 2015CAD

Business Acquisition [Line Items]

Common stock, value, subscriptions

CAD 4,400

Subscription receipt (in shares) | shares

96.6

Columbia adjustment (Note 5)

CAD 71

Goodwill

CAD 13,958

13,084

CAD 13,958

CAD 4,812

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

CAD 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

CAD 45

$ 35

Columbia adjustment (Note 5)

71

55

Goodwill

CAD 10,078

$ 7,802

$ 7,747

$ 7,747

Estimated increase (decrease) in fair value of acquired liabilities, long-term debt

300

$ 231

CAD 242

293

Common unit, outstanding (in shares) | shares

53.8

Share price (in USD per share) | $ / shares

$ 15

Acquisition costs

36

CAD 36

Pro revenue of acquiree since acquisition date

929

Pro forma information, earnings of acquiree since acquisition date

CAD 132

Columbian Pipeline | U.S. federal

Business Acquisition [Line Items]

Effective income tax rate percent

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

CAD (116)

$ (90)

Columbian Pipeline | Natural Gas

Business Acquisition [Line Items]

Increase (decrease) in fair value of property, plant, and equipment

CAD 840

646

Columbian Pipeline | Bridge Facility

Business Acquisition [Line Items]

Proceeds from lines of credit | $

$ 6,900

ACQUISITION OF COLUMBIA - Sched

ACQUISITION OF COLUMBIA - Schedule of Assets Acquired and Liabilities Assumed (Details) CAD in Millions, $ in Millions	Jul. 01, 2016CAD	Jul. 01, 2016USD ($)	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)	Jul. 01, 2016USD ($)	Dec. 31, 2015CAD
Fair Value
Goodwill (Note 11)			CAD 13,084		CAD 13,958			CAD 4,812
Exchange rate	1.30						1.30
Columbian Pipeline
Business Acquisition [Line Items]
Purchase Price Consideration	CAD 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 (Note 11)	CAD 10,078			$ 7,802		$ 7,747	$ 7,747

ACQUISITION OF COLUMBIA - Sch68

ACQUISITION OF COLUMBIA - Schedule of Fair Value of Debt Acquired (Details) CAD in Millions	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)	Jul. 01, 2016CAD	Jul. 01, 2016USD ($)	Dec. 31, 2015CAD
Debt Instrument [Line Items]
Goodwill (Note 11) | CAD	CAD 13,084		CAD 13,958				CAD 4,812
Senior Unsecured Notes, 2.45% Interest Rate | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face amount						$ 500,000,000
Senior Unsecured Notes, 3.30% Interest Rate | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face amount						750,000,000
Senior Unsecured Notes, 4.50% Interest Rate | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face amount						1,000,000,000
Senior Unsecured Notes, 5.80% Interest Rate | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face amount						500,000,000
Columbian Pipeline
Debt Instrument [Line Items]
Goodwill (Note 11)		$ 7,802,000,000		$ 7,747,000,000	CAD 10,078	7,747,000,000
Fair Value					CAD 3,878	2,981,000,000
Columbian Pipeline | Senior Unsecured Notes
Debt Instrument [Line Items]
Fair Value						2,981,000,000
Columbian Pipeline | Senior Unsecured Notes, 2.45% Interest Rate | Senior Unsecured Notes
Debt Instrument [Line Items]
Fair Value						$ 506,000,000
Interest Rate					2.45%	2.45%
Columbian Pipeline | Senior Unsecured Notes, 3.30% Interest Rate | Senior Unsecured Notes
Debt Instrument [Line Items]
Fair Value						$ 779,000,000
Interest Rate					3.30%	3.30%
Columbian Pipeline | Senior Unsecured Notes, 4.50% Interest Rate | Senior Unsecured Notes
Debt Instrument [Line Items]
Fair Value						$ 1,092,000,000
Interest Rate					4.50%	4.50%
Columbian Pipeline | Senior Unsecured Notes, 5.80% Interest Rate | Senior Unsecured Notes
Debt Instrument [Line Items]
Fair Value						$ 604,000,000
Interest Rate					5.80%	5.80%

ACQUISITION OF COLUMBIA - Pro F

ACQUISITION OF COLUMBIA - Pro Forma Information (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Business Combinations [Abstract]
Revenues	CAD 13,404	CAD 13,007
Net Income/(Loss)	627	(820)
Net Income/(Loss) Attributable to Common Shares	CAD 234	CAD (971)

ASSETS HELD FOR SALE - (Details

ASSETS HELD FOR SALE - (Details) CAD in Millions, $ in Millions	Jun. 02, 2017USD ($)	Apr. 19, 2017USD ($)	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD
Long Lived Assets Held-for-sale [Line Items]
Proceeds from sale of assets, net of transaction costs			CAD 5,317	CAD 6	CAD 0
Ravenswood, Ironwood, Kibby Wind and Ocean State Power
Long Lived Assets Held-for-sale [Line Items]
Proceeds from sale of assets, net of transaction costs | $	$ 2,029
Loss on disposition of property plant equipment				829
Loss on disposition of property plant equipment, net of tax				863
Disposal group, not discontinued operations | TC Hydro
Long Lived Assets Held-for-sale [Line Items]
Proceeds from sale of assets, net of transaction costs | $		$ 1,070
Disposal group, not discontinued operations | Ravenswood, Ironwood, Kibby Wind and Ocean State Power
Long Lived Assets Held-for-sale [Line Items]
Foreign currency translation gain on assets held for sale				CAD 70

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Assets [Abstract]
Fair value of derivative contracts (Note 24)	CAD 332	CAD 376
Prepaid expenses	109	131
Cash provided as collateral	99	313
Regulatory assets (Note 10)	23	33
Other	128	55
Other current assets, total	CAD 691	CAD 908

PLANT, PROPERTY AND EQUIPMENT72

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD CAD in Millions	Dec. 31, 2017	Oct. 05, 2017	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Plant, property and equipment
Cost	CAD 81,011			CAD 81,011	CAD 76,763
Accumulated Depreciation	23,734			23,734	22,288
Net Book Value	57,277			57,277	54,475
Energy East, Eastern Mainline and Upland Projects
Plant, property and equipment
Tangible asset impairment charges		CAD 83
Impairment charge, net of tax		CAD 64
Keystone XL
Plant, property and equipment
Impairment charge			CAD 3,686
Impairment charge, after tax			2,891
Canadian Natural Gas Pipelines | NGTL System | Under construction
Plant, property and equipment
Accumulated Depreciation	0			0	0
Energy | Facilities under PPAs
Plant, property and equipment
Cost	1,264			1,264	1,319
Accumulated Depreciation	354			354	335
Revenues recognized through the sale of electricity				215	212	CAD 235
Operating segments | Canadian Natural Gas Pipelines
Plant, property and equipment
Cost	31,300			31,300	29,239
Accumulated Depreciation	16,876			16,876	16,022
Net Book Value	14,424			14,424	13,217
Operating segments | Canadian Natural Gas Pipelines | NGTL System
Plant, property and equipment
Cost	15,302			15,302	13,536
Accumulated Depreciation	6,352			6,352	5,969
Net Book Value	8,950			8,950	7,567
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Pipeline
Plant, property and equipment
Cost	10,153			10,153	8,814
Accumulated Depreciation	4,190			4,190	3,951
Net Book Value	5,963			5,963	4,863
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Compression
Plant, property and equipment
Cost	3,021			3,021	2,447
Accumulated Depreciation	1,593			1,593	1,499
Net Book Value	1,428			1,428	948
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Metering and other
Plant, property and equipment
Cost	1,188			1,188	1,124
Accumulated Depreciation	569			569	519
Net Book Value	619			619	605
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	14,362			14,362	12,385
Accumulated Depreciation	6,352			6,352	5,969
Net Book Value	8,010			8,010	6,416
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Under construction
Plant, property and equipment
Cost	940			940	1,151
Net Book Value	940			940	1,151
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline
Plant, property and equipment
Cost	14,179			14,179	13,863
Accumulated Depreciation	9,161			9,161	8,780
Net Book Value	5,018			5,018	5,083
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Pipeline
Plant, property and equipment
Cost	9,763			9,763	9,502
Accumulated Depreciation	6,455			6,455	6,221
Net Book Value	3,308			3,308	3,281
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Compression
Plant, property and equipment
Cost	3,605			3,605	3,537
Accumulated Depreciation	2,499			2,499	2,361
Net Book Value	1,106			1,106	1,176
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Metering and other
Plant, property and equipment
Cost	655			655	605
Accumulated Depreciation	207			207	198
Net Book Value	448			448	407
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	14,023			14,023	13,644
Accumulated Depreciation	9,161			9,161	8,780
Net Book Value	4,862			4,862	4,864
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Under construction
Plant, property and equipment
Cost	156			156	219
Accumulated Depreciation	0			0	0
Net Book Value	156			156	219
Operating segments | Canadian Natural Gas Pipelines | Other
Plant, property and equipment
Cost	1,815			1,815	1,728
Accumulated Depreciation	1,363			1,363	1,273
Net Book Value	452			452	455
Operating segments | Canadian Natural Gas Pipelines | Other Canadian Natural Gas Pipelines
Plant, property and equipment
Cost	1,819			1,819	1,840
Accumulated Depreciation	1,363			1,363	1,273
Net Book Value	456			456	567
Operating segments | Canadian Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | Under construction
Plant, property and equipment
Cost	4			4	112
Accumulated Depreciation	0			0	0
Net Book Value	4			4	112
Operating segments | U.S. Natural Gas Pipelines
Plant, property and equipment
Cost	24,007			24,007	21,557
Accumulated Depreciation	3,745			3,745	3,502
Net Book Value	20,262			20,262	18,055
Operating segments | U.S. Natural Gas Pipelines | Under construction
Plant, property and equipment
Accumulated Depreciation	0			0	0
Operating segments | U.S. Natural Gas Pipelines | Other | Pipeline
Plant, property and equipment
Cost	1,950			1,950	2,120
Accumulated Depreciation	574			574	567
Net Book Value	1,376			1,376	1,553
Operating segments | U.S. Natural Gas Pipelines | Other Canadian Natural Gas Pipelines
Plant, property and equipment
Cost	8,944			8,944	8,745
Accumulated Depreciation	2,600			2,600	2,560
Net Book Value	6,344			6,344	6,185
Operating segments | U.S. Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	8,245			8,245	8,399
Accumulated Depreciation	2,600			2,600	2,560
Net Book Value	5,645			5,645	5,839
Operating segments | U.S. Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | Under construction
Plant, property and equipment
Cost	699			699	346
Accumulated Depreciation	0			0	0
Net Book Value	699			699	346
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas
Plant, property and equipment
Cost	10,735			10,735	8,630
Accumulated Depreciation	226			226	79
Net Book Value	10,509			10,509	8,551
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Pipeline
Plant, property and equipment
Cost	3,550			3,550	3,317
Accumulated Depreciation	125			125	42
Net Book Value	3,425			3,425	3,275
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Compression
Plant, property and equipment
Cost	1,547			1,547	1,636
Accumulated Depreciation	64			64	29
Net Book Value	1,483			1,483	1,607
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Metering and other
Plant, property and equipment
Cost	2,306			2,306	2,550
Accumulated Depreciation	37			37	8
Net Book Value	2,269			2,269	2,542
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	7,403			7,403	7,503
Accumulated Depreciation	226			226	79
Net Book Value	7,177			7,177	7,424
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Under construction
Plant, property and equipment
Cost	3,332			3,332	1,127
Accumulated Depreciation	0			0	0
Net Book Value	3,332			3,332	1,127
Operating segments | U.S. Natural Gas Pipelines | ANR
Plant, property and equipment
Cost	4,328			4,328	4,182
Accumulated Depreciation	919			919	863
Net Book Value	3,409			3,409	3,319
Operating segments | U.S. Natural Gas Pipelines | ANR | Pipeline
Plant, property and equipment
Cost	1,427			1,427	1,468
Accumulated Depreciation	365			365	349
Net Book Value	1,062			1,062	1,119
Operating segments | U.S. Natural Gas Pipelines | ANR | Compression
Plant, property and equipment
Cost	1,582			1,582	1,494
Accumulated Depreciation	286			286	260
Net Book Value	1,296			1,296	1,234
Operating segments | U.S. Natural Gas Pipelines | ANR | Metering and other
Plant, property and equipment
Cost	961			961	988
Accumulated Depreciation	268			268	254
Net Book Value	693			693	734
Operating segments | U.S. Natural Gas Pipelines | ANR | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	3,970			3,970	3,950
Accumulated Depreciation	919			919	863
Net Book Value	3,051			3,051	3,087
Operating segments | U.S. Natural Gas Pipelines | ANR | Under construction
Plant, property and equipment
Cost	358			358	232
Net Book Value	358			358	232
Operating segments | U.S. Natural Gas Pipelines | GTN | Pipeline
Plant, property and equipment
Cost	2,107			2,107	2,221
Accumulated Depreciation	822			822	810
Net Book Value	1,285			1,285	1,411
Operating segments | U.S. Natural Gas Pipelines | Great Lakes | Pipeline
Plant, property and equipment
Cost	1,988			1,988	2,106
Accumulated Depreciation	1,113			1,113	1,155
Net Book Value	875			875	951
Operating segments | U.S. Natural Gas Pipelines | Columbia Gulf | Pipeline
Plant, property and equipment
Cost	1,115			1,115	880
Accumulated Depreciation	37			37	5
Net Book Value	1,078			1,078	875
Operating segments | U.S. Natural Gas Pipelines | Midstream | Pipeline
Plant, property and equipment
Cost	1,085			1,085	1,072
Accumulated Depreciation	54			54	23
Net Book Value	1,031			1,031	1,049
Operating segments | Mexico Natural Gas Pipelines
Plant, property and equipment
Cost	5,261			5,261	4,766
Accumulated Depreciation	309			309	239
Net Book Value	4,952			4,952	4,527
Operating segments | Mexico Natural Gas Pipelines | Pipeline
Plant, property and equipment
Cost	2,486			2,486	2,734
Accumulated Depreciation	214			214	180
Net Book Value	2,272			2,272	2,554
Operating segments | Mexico Natural Gas Pipelines | Compression
Plant, property and equipment
Cost	388			388	422
Accumulated Depreciation	30			30	19
Net Book Value	358			358	403
Operating segments | Mexico Natural Gas Pipelines | Metering and other
Plant, property and equipment
Cost	522			522	502
Accumulated Depreciation	65			65	40
Net Book Value	457			457	462
Operating segments | Mexico Natural Gas Pipelines | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	3,396			3,396	3,658
Accumulated Depreciation	309			309	239
Net Book Value	3,087			3,087	3,419
Operating segments | Mexico Natural Gas Pipelines | Under construction
Plant, property and equipment
Cost	1,865			1,865	1,108
Accumulated Depreciation	0			0	0
Net Book Value	1,865			1,865	1,108
Operating segments | Liquids Pipelines
Plant, property and equipment
Cost	14,952			14,952	15,455
Accumulated Depreciation	1,533			1,533	1,308
Net Book Value	13,419			13,419	14,147
Operating segments | Liquids Pipelines | Keystone Pipeline System
Plant, property and equipment
Cost	13,794			13,794	14,500
Accumulated Depreciation	1,529			1,529	1,308
Net Book Value	12,265			12,265	13,192
Operating segments | Liquids Pipelines | Keystone Pipeline System | Pipeline
Plant, property and equipment
Cost	9,002			9,002	10,572
Accumulated Depreciation	992			992	901
Net Book Value	8,010			8,010	9,671
Operating segments | Liquids Pipelines | Keystone Pipeline System | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	13,338			13,338	14,021
Accumulated Depreciation	1,529			1,529	1,308
Net Book Value	11,809			11,809	12,713
Operating segments | Liquids Pipelines | Keystone Pipeline System | Under construction
Plant, property and equipment
Cost	456			456	479
Accumulated Depreciation	0			0	0
Net Book Value	456			456	479
Operating segments | Liquids Pipelines | Keystone Pipeline System | Pumping equipment
Plant, property and equipment
Cost	1,022			1,022	928
Accumulated Depreciation	152			152	121
Net Book Value	870			870	807
Operating segments | Liquids Pipelines | Keystone Pipeline System | Tanks and other
Plant, property and equipment
Cost	3,314			3,314	2,521
Accumulated Depreciation	385			385	286
Net Book Value	2,929			2,929	2,235
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines
Plant, property and equipment
Cost	1,158			1,158	955
Accumulated Depreciation	4			4	0
Net Book Value	1,154			1,154	955
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Pipeline
Plant, property and equipment
Cost	748			748	0
Accumulated Depreciation	3			3	0
Net Book Value	745			745	0
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	1,111			1,111	0
Accumulated Depreciation	4			4	0
Net Book Value	1,107			1,107	0
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Under construction
Plant, property and equipment
Cost	47			47	955
Accumulated Depreciation	0			0
Net Book Value	47			47	955
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Pumping equipment
Plant, property and equipment
Cost	104			104	0
Accumulated Depreciation	0			0	0
Net Book Value	104			104	0
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Tanks and other
Plant, property and equipment
Cost	259			259	0
Accumulated Depreciation	1			1	0
Net Book Value	258			258	0
Operating segments | Energy
Plant, property and equipment
Cost	5,080			5,080	5,336
Accumulated Depreciation	1,103			1,103	1,087
Net Book Value	3,977			3,977	4,249
Operating segments | Energy | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	4,052			4,052	4,607
Accumulated Depreciation	1,103			1,103	1,087
Net Book Value	2,949			2,949	3,520
Operating segments | Energy | Under construction
Plant, property and equipment
Cost	1,028			1,028	729
Accumulated Depreciation	0			0	0
Net Book Value	1,028			1,028	729
Operating segments | Energy | Natural Gas
Plant, property and equipment
Cost	2,645			2,645	2,696
Accumulated Depreciation	743			743	696
Net Book Value	1,902			1,902	2,000
Operating segments | Energy | Wind and Solar
Plant, property and equipment
Cost	673			673	1,180
Accumulated Depreciation	204			204	245
Net Book Value	469			469	935
Operating segments | Energy | Natural Gas Storage and Other
Plant, property and equipment
Cost	734			734	731
Accumulated Depreciation	156			156	146
Net Book Value	578			578	585
Corporate
Plant, property and equipment
Cost	411			411	410
Accumulated Depreciation	168			168	130
Net Book Value	243			CAD 243	CAD 280
Power generation and natural gas storage plant, equipment and structures
Plant, property and equipment
Impairment charge	21		59
Impairment charge, after tax	CAD 16		43
Significant Unobservable Inputs (Level III) | Keystone XL
Plant, property and equipment
Estimated fair value			CAD 621			CAD 621

EQUITY INVESTMENTS - Schedule a

EQUITY INVESTMENTS - Schedule and Narrative (Details) $ in Millions

May 01, 2016USD ($)

Oct. 31, 2017CAD

Aug. 31, 2017CAD

Mar. 31, 2016USD ($)

Mar. 31, 2016CAD

Dec. 31, 2017CAD

Dec. 31, 2016CAD

Dec. 31, 2015CAD

Dec. 31, 2017USD ($)

Jun. 02, 2017

Jun. 01, 2017

Dec. 31, 2016USD ($)

Equity Investments

Income/(Loss) from Equity Investments

CAD 773,000,000

CAD 514,000,000

CAD 440,000,000

Equity Investments

6,366,000,000

6,544,000,000

Distributions received from equity investments

1,332,000,000

1,571,000,000

802,000,000

Returns of capital

362,000,000

727,000,000

9,000,000

Undistributed earnings

198,000,000

Contributions to equity investments

1,681,000,000

765,000,000

CAD 493,000,000

Iroquois

Equity Investments

Ownership interest (percent)

50.00%

49.35%

49.35%

Additional ownership acquired (percent)

0.65%

4.87%

4.87%

Contributions to equity investments | $

$ 7

$ 54

Sur de Texas

Equity Investments

Contributions to equity investments

CAD 977,000,000

TransGas

Equity Investments

Ownership interest (percent)

46.50%

Asset impairment charges

CAD 12,000,000

Contract term

20 years

Grand Rapids

Equity Investments

Difference between the carrying value of the investment and the underlying equity in the net assets | $

$ 105

$ 86

Bruce Power

Equity Investments

Ownership interest (percent)

48.50%

Canadian Natural Gas Pipelines | TQM

Equity Investments

Ownership interest (percent)

50.00%

50.00%

Income/(Loss) from Equity Investments

CAD 11,000,000

12,000,000

CAD 12,000,000

Equity Investments

CAD 68,000,000

71,000,000

U.S. Natural Gas Pipelines | Northern Border

Equity Investments

Ownership interest (percent)

50.00%

50.00%

Income/(Loss) from Equity Investments

CAD 87,000,000

92,000,000

85,000,000

Equity Investments

CAD 641,000,000

597,000,000

Difference between the carrying value of the investment and the underlying equity in the net assets | $

$ 115

116

U.S. Natural Gas Pipelines | Iroquois

Equity Investments

Ownership interest (percent)

50.00%

50.00%

0.66%

50.00%

Income/(Loss) from Equity Investments

CAD 59,000,000

54,000,000

51,000,000

Equity Investments

CAD 280,000,000

309,000,000

Difference between the carrying value of the investment and the underlying equity in the net assets | $

$ 41

48

U.S. Natural Gas Pipelines | Millennium

Equity Investments

Ownership interest (percent)

47.50%

47.50%

Income/(Loss) from Equity Investments

CAD 66,000,000

33,000,000

0

Equity Investments

CAD 291,000,000

295,000,000

U.S. Natural Gas Pipelines | Pennant Midstream

Equity Investments

Ownership interest (percent)

47.00%

47.00%

Income/(Loss) from Equity Investments

CAD 11,000,000

6,000,000

0

Equity Investments

228,000,000

246,000,000

U.S. Natural Gas Pipelines | Other

Equity Investments

Income/(Loss) from Equity Investments

17,000,000

29,000,000

26,000,000

Equity Investments

CAD 92,000,000

93,000,000

Mexico Natural Gas Pipelines | Sur de Texas

Equity Investments

Ownership interest (percent)

60.00%

60.00%

Income/(Loss) from Equity Investments

CAD 66,000,000

(3,000,000)

0

Equity Investments

399,000,000

255,000,000

Mexico Natural Gas Pipelines | TransGas

Equity Investments

Income/(Loss) from Equity Investments

(12,000,000)

0

5,000,000

Equity Investments

0

28,000,000

Liquids Pipelines | Other

Equity Investments

Income/(Loss) from Equity Investments

(20,000,000)

0

0

Equity Investments

CAD 20,000,000

39,000,000

Liquids Pipelines | Grand Rapids

Equity Investments

Ownership interest (percent)

50.00%

50.00%

Income/(Loss) from Equity Investments

CAD 17,000,000

(1,000,000)

0

Equity Investments

996,000,000

876,000,000

Liquids Pipelines | Canaport Energy East Marine Terminal Limited Partnership

Equity Investments

Equity Investments

0

Energy | Other

Equity Investments

Income/(Loss) from Equity Investments

6,000,000

3,000,000

5,000,000

Equity Investments

CAD 63,000,000

66,000,000

Energy | Bruce Power

Equity Investments

Ownership interest (percent)

48.40%

48.40%

Income/(Loss) from Equity Investments

CAD 434,000,000

293,000,000

249,000,000

Equity Investments

2,987,000,000

3,356,000,000

Difference between the carrying value of the investment and the underlying equity in the net assets

CAD 902,000,000

942,000,000

Energy | Portlands Energy

Equity Investments

Ownership interest (percent)

50.00%

50.00%

Income/(Loss) from Equity Investments

CAD 31,000,000

33,000,000

30,000,000

Equity Investments

CAD 301,000,000

313,000,000

Difference between the carrying value of the investment and the underlying equity in the net assets | $

$ 73

$ 70

Energy | ASTC Power Partnership

Equity Investments

Ownership interest (percent)

50.00%

50.00%

Income/(Loss) from Equity Investments

CAD 0

(37,000,000)

CAD (23,000,000)

Equity Investments

CAD 0

CAD 0

Energy | Sundance B PPA

Equity Investments

Asset impairment charges

CAD 29,000,000

Asset impairment charge, after tax

CAD 21,000,000

Energy East, Eastern Mainline and Upland Projects | Liquids Pipelines

Equity Investments

Asset impairment charges

CAD 20,000,000

EQUITY INVESTMENTS - Summarized

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income
Revenues	CAD 4,913	CAD 4,336	CAD 4,337
Operating and other expenses	(2,993)	(3,068)	(3,142)
Net income	1,636	1,080	1,046
Income/(Loss) from Equity Investments	773	514	CAD 440
Balance Sheet
Current assets	2,176	1,669
Non-current assets	17,869	15,853
Current liabilities	(1,577)	(1,120)
Non-current liabilities	CAD (8,217)	CAD (5,867)

EQUITY INVESTMENTS - Loan Recei

EQUITY INVESTMENTS - Loan Receivable From Affiliate (Details) - Joint Venture CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 06, 2017MXN	Apr. 21, 2017MXN
Sur de Texas
Equity Investments
Ownership interest (percent)	60.00%
Loans receivable from affiliates	CAD 919
Interest income, related party	CAD 34
Unsecured Loan Facility | Revolving credit facility
Equity Investments
Credit facility, amount | MXN		MXN 21,300,000,000	MXN 13,600,000,000

RATE-REGULATED BUSINESSES - Nar

RATE-REGULATED BUSINESSES - Narrative (Details) CAD in Millions	1 Months Ended		12 Months Ended
	Apr. 30, 2016	Mar. 31, 2016USD ($)	Dec. 31, 2017	Dec. 31, 2015	Dec. 31, 2014CAD	Dec. 31, 2013USD ($)
Public Utilities, General Disclosures [Line Items]
After-tax annual contribution to reduce revenue requirement | CAD					CAD 20
Fixed toll term (in years)			6 years
Columbia Gas Transmission
Public Utilities, General Disclosures [Line Items]
Maximum cost recovery and return on investment | $		$ 1,100,000,000				$ 1,500,000,000
Cost recovery and return on investment, recognition period (in years)						5 years
Cost recovery and return on investment, additional period (in years)		3 years
Canadian Regulated Operations | Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity (percent)					10.10%
Deemed common equity (percent)					40.00%
National Energy Board | 2015 Revenue Requirement Settlement | NGTL System
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	3.16%			3.10%
Period of settlement (in years)				1 year
National Energy Board | 2015 Revenue Requirement Settlement | NGTL System | Canadian Regulated Operations
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity (percent)				10.10%
Deemed common equity (percent)				40.00%

RATE-REGULATED BUSINESSES - Ass

RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) CAD in Millions, $ in Millions	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2017CAD	Dec. 31, 2006CAD	Dec. 31, 2006USD ($)	Jul. 31, 2016USD ($)
Regulatory Assets
Regulatory Assets	CAD 1,399		CAD 1,355	CAD 1,399
Less: Current portion included in Other current assets (Note 7)	23		33	23
Total Regulatory Assets	1,376		1,322	1,376
Regulatory Liabilities
Regulatory Liabilities	4,584		2,299	4,584
Less: Current portion included in Accounts payable and other (Note 14)	263		178	263
Total Regulatory Liabilities	4,321		2,121	4,321
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Regulatory Liabilities	188		47	CAD 188
Remaining Recovery/ Settlement Period (years)				1 year
Pensions and other post retirement benefits | ANR PIPELINE COMPANY
Regulatory Liabilities
Regulatory Liabilities	66		141	CAD 66
Long term adjustment account
Regulatory Liabilities
Regulatory Liabilities	1,142		659	CAD 1,142
Remaining Recovery/ Settlement Period (years)				46 years
Pipeline abandonment trust balance
Regulatory Liabilities
Regulatory Liabilities	825		541	CAD 825
Bridging amortization account
Regulatory Liabilities
Regulatory Liabilities	202		451	CAD 202
Remaining Recovery/ Settlement Period (years)				13 years
Cost of removal
Regulatory Liabilities
Regulatory Liabilities	216		226	CAD 216
Deferred income taxes
Regulatory Liabilities
Regulatory Liabilities	75		0	75
Deferred income taxes - U.S. Tax Reform
Regulatory Liabilities
Regulatory Liabilities	1,659		0	1,659
Other
Regulatory Liabilities
Regulatory Liabilities	47		54	47
Postretirement benefit costs | ANR PIPELINE COMPANY
Other disclosures pertaining to regulated assets and liabilities
Regulatory liability settlement	26	$ 21	46				$ 34
Amount to be addressed In next settlement					CAD 40	$ 32
Deferred income taxes
Regulatory Assets
Regulatory Assets	967		861	967
Deferred income taxes - U.S. Tax Reform
Regulatory Assets
Regulatory Assets	(27)		0	(27)
Operating and debt-service regulatory assets
Regulatory Assets
Regulatory Assets	0		1	CAD 0
Remaining Recovery/ Settlement Period (years)				1 year
Pensions and other post retirement benefits
Regulatory Assets
Regulatory Assets	388		382	CAD 388
Regulatory Liabilities
Regulatory Liabilities	164		180	164
Foreign exchange on long-term debt
Regulatory Assets
Regulatory Assets	0		37	CAD 0
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)				12 years
Other
Regulatory Assets
Regulatory Assets	CAD 71		CAD 74	CAD 71

GOODWILL (Details)

GOODWILL (Details) CAD in Millions, $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2017CAD	Jun. 30, 2017USD ($)	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD
Goodwill
Balance at the beginning of the period			CAD 13,958		CAD 4,812
Impairment charge					(1,085)
Foreign exchange rate changes			(945)		153
Columbia adjustment (Note 5)			71
Balance at the end of the period			13,084		13,958
U.S. Natural Gas Pipelines
Goodwill
Balance at the beginning of the period			13,958		3,667
Impairment charge					0
Foreign exchange rate changes			(945)		213
Columbia adjustment (Note 5)			71
Balance at the end of the period			13,084		13,958
Energy
Goodwill
Balance at the beginning of the period			0		1,145
Impairment charge					(1,085)
Foreign exchange rate changes			0		(60)
Columbia adjustment (Note 5)			0
Balance at the end of the period			CAD 0		0
Columbian Pipeline
Goodwill
Balance at the beginning of the period | $				$ 7,747
Acquisition of Columbia (Note 5)					10,078
Columbia adjustment (Note 5)	CAD 71	$ 55
Balance at the end of the period | $				$ 7,802
Columbian Pipeline | U.S. Natural Gas Pipelines
Goodwill
Acquisition of Columbia (Note 5)					10,078
Columbian Pipeline | Energy
Goodwill
Acquisition of Columbia (Note 5)					CAD 0

GOODWILL - Narrative (Details)

GOODWILL - Narrative (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	CAD 13,084	CAD 13,958	CAD 4,812
Asset impairment charges	1,257	1,388	3,745
Energy
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	CAD 0	0	CAD 1,145
Natural Gas – Ravenswood | Energy
Goodwill recorded on Company's acquisitions in the U.S.
Asset impairment charges		1,085
Asset impairment charge, after tax		CAD 656
Great Lakes
Goodwill recorded on Company's acquisitions in the U.S.
Percentage of fair value in excess of carrying amount (less than)	10.00%			10.00%
Goodwill | $				$ 573	$ 573

INTANGIBLE AND OTHER ASSETS (De

INTANGIBLE AND OTHER ASSETS (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Capital projects in development	CAD 596	CAD 2,094
Deferred income tax assets (Note 16)	316	392
Employee post-retirement benefits (Note 23)	193	189
Fair value of derivative contracts (Note 24)	73	133
Other	306	218
Intangible and other assets	CAD 1,484	CAD 3,026

INTANGIBLE AND OTHER ASSETS - N

INTANGIBLE AND OTHER ASSETS - Narrative (Details) - CAD CAD in Millions	Oct. 05, 2017	Oct. 31, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets [Line Items]
Gain on contract termination		CAD 634
Asset impairment charges				CAD 1,257	CAD 1,388	CAD 3,745
Amortization expense					9	CAD 52
Sundance A (expires 2017) | Energy
Finite-Lived Intangible Assets [Line Items]
Asset impairment charges			CAD 92		211
Asset impairment charge, after tax			CAD 68		CAD 155
Energy East, Eastern Mainline and Upland Projects
Finite-Lived Intangible Assets [Line Items]
Asset impairment charges	CAD 1,153
Asset impairment charge, after tax	CAD 870

NOTES PAYABLE (Details)

NOTES PAYABLE (Details)	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Dec. 31, 2017MXN	Dec. 31, 2017USD ($)	Dec. 31, 2016MXN	Dec. 31, 2016USD ($)
Notes payable
Outstanding at December 31	CAD 1,763,000,000	CAD 774,000,000
Operated affiliates
Notes payable
Unused Capacity	400,000,000	500,000,000
Revolving credit facility
Notes payable
Cost to maintain	7,000,000	10,000,000	CAD 11,000,000
Revolving and demand credit facilities
Notes payable
Total Facilities	11,000,000,000	11,100,000,000
Mexican subsidiary | Revolving credit facility
Notes payable
Total Facilities | MXN				MXN 5,000,000		MXN 0
Unused Capacity | MXN				4,700,000
Mexican subsidiary | Notes payable
Notes payable
Outstanding at December 31	CAD 17,000,000	CAD 0		MXN 275,000,000
Weighted Average Interest Rate per Annum at December 31	8.00%	0.00%		8.00%	8.00%	0.00%	0.00%
TCPL | Revolving credit facility | Maturing December 2022
Notes payable
Total Facilities	CAD 3,000,000,000	CAD 3,000,000,000
Unused Capacity	3,000,000,000
TCPL | Revolving credit facility | Maturing December 2018
Notes payable
Total Facilities | $					$ 2,000,000,000		$ 2,000,000,000
Unused Capacity | $					$ 2,000,000,000
TCPL | Notes payable
Notes payable
Outstanding at December 31	CAD 884,000,000	CAD 509,000,000
Weighted Average Interest Rate per Annum at December 31	1.60%	0.90%		1.60%	1.60%	0.90%	0.90%
TCPL USA | Revolving credit facility | Maturing December 2018
Notes payable
Total Facilities	CAD 1,000,000,000						$ 1,000,000,000
Unused Capacity | $					$ 600,000,000
Columbia | Revolving credit facility | Maturing December 2018
Notes payable
Total Facilities | $					1,000,000,000		1,000,000,000
Unused Capacity | $					1,000,000,000
TAIL | Revolving credit facility | Maturing December 2018
Notes payable
Total Facilities | $					500,000,000		500,000,000
Unused Capacity | $					500,000,000
TAIL | Notes payable
Notes payable
Outstanding at December 31	CAD 862,000,000	CAD 265,000,000			$ 688,000,000		$ 197,000,000
Weighted Average Interest Rate per Annum at December 31	2.20%	0.50%		2.20%	2.20%	0.50%	0.50%
TCPL/TCPL USA | Revolving credit facility
Notes payable
Total Facilities	CAD 1,900,000,000	CAD 1,900,000,000
Unused Capacity	CAD 500,000,000

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Payables and Accruals [Abstract]
Trade payables	CAD 2,847	CAD 2,443
Fair value of derivative contracts (Note 24)	387	607
Unredeemed shares of Columbia	312	317
Regulatory liabilities (Note 10)	263	178
Other	248	316
Accounts payable and other	CAD 4,057	CAD 3,861

OTHER LONG-TERM LIABILITIES (De

OTHER LONG-TERM LIABILITIES (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred Costs, Noncurrent [Abstract]
Employee post-retirement benefits (Note 23)	CAD 389	CAD 448
Fair value of derivative contracts (Note 24)	72	330
Asset retirement obligations	98	108
Guarantees (Note 27)	16	82
Other	152	215
Other Long-Term Liabilities	CAD 727	CAD 1,183

INCOME TAXES - U.S. Tax Reform

INCOME TAXES - U.S. Tax Reform (Details) - CAD CAD in Millions	Dec. 22, 2017	Dec. 31, 2017
Income Tax Contingency [Line Items]
Effect of income tax act on deferred income tax expense, increase (decrease)		CAD (816)
Provisional income tax expense (benefit)	CAD 816
Other Post-Retirement Benefit Plans
Income Tax Contingency [Line Items]
Effect of income tax act on deferred income tax expense, increase (decrease)		12
Deferred income taxes - U.S. Tax Reform
Income Tax Contingency [Line Items]
Regulatory Liabilities		CAD 1,686

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current
Canada	CAD 113	CAD 116	CAD 44
Foreign	36	40	92
Total	149	156	136
Deferred
Canada	(185)	101	33
Foreign	751	95	(135)
Deferred – U.S. Tax Reform	(804)	0	0
Total	(238)	196	(102)
Income Tax (Recovery)/Expense	CAD (89)	CAD 352	CAD 34

INCOME TAXES - Geographic Compo

INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Canada	CAD (339)	CAD 219	CAD (624)
Foreign	3,645	618	(482)
Income/(Loss) before Income Taxes	CAD 3,306	CAD 837	CAD (1,106)

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Income Tax (Recovery)/Expense (Details) - CAD	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income/(loss) before income taxes	CAD 3,306,000,000	CAD 837,000,000	CAD (1,106,000,000)
Federal and provincial statutory tax rate (percent)	27.00%	27.00%	26.00%
Expected income tax expense/(recovery)	CAD 893,000,000	CAD 226,000,000	CAD (288,000,000)
U.S. Tax Reform	(804,000,000)	0	0
Foreign income tax rate differentials	(81,000,000)	(196,000,000)	14,000,000
Income from equity investments and non-controlling interests	(64,000,000)	(68,000,000)	(56,000,000)
Income tax differential related to regulated operations	(42,000,000)	81,000,000	159,000,000
Non-taxable portion of capital gains	(42,000,000)	0	0
Asset impairment charges	34,000,000	242,000,000	170,000,000
Non-deductible amounts	4,000,000	46,000,000	0
Tax rate and legislative changes	0	0	34,000,000
Other	13,000,000	21,000,000	1,000,000
Income Tax (Recovery)/Expense	(89,000,000)	352,000,000	34,000,000
Foreign tax rate differential related to asset impairments, amount	CAD 0	CAD 112,000,000	CAD 311,000,000

INCOME TAXES - Deferred Assets

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred Income Tax Assets
Tax loss and credit carryforwards	CAD 1,379	CAD 2,063
Difference in accounting and tax bases of impaired assets and assets held for sale	651	1,168
Regulatory and other deferred amounts	512	277
Unrealized foreign exchange losses on long-term debt	216	446
Financial instruments	10	34
Other	227	352
Deferred tax assets, gross	2,995	4,340
Less: Valuation allowance	832	1,336
Deferred tax assets, net of Valuation allowance	2,163	3,004
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,240	9,015
Equity investments	632	905
Taxes on future revenue requirement	238	198
Other	140	156
Deferred tax liabilities, gross	7,250	10,274
Net Deferred Income Tax Liabilities	5,087	7,270
Deferred Income Tax Assets
Intangible and other assets (Note 12)	316	392
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,403	7,662
Net Deferred Income Tax Liabilities	CAD 5,087	CAD 7,270

INCOME TAXES - Reconciliation90

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefit at beginning of year	CAD 18	CAD 17	CAD 18
Gross increases – tax positions in prior years	0	3	2
Gross decreases – tax positions in prior years	(1)	0	(2)
Gross increases – tax positions in current year	2	2	1
Settlement	0	(1)	0
Lapse of statutes of limitations	(4)	(3)	(2)
Unrecognized Tax Benefit at End of Year	CAD 15	CAD 18	CAD 17

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Net operating loss carryforwards
Tax loss and credit carryforwards	CAD 1,379,000,000	CAD 2,063,000,000
Deferred income tax liabilities on the unremitted earnings of foreign investments	569,000,000	481,000,000
Income tax payments, net of refunds	247,000,000	105,000,000	CAD 162,000,000
Interest expense (reversal) reflected within net tax expense	0	0	1,000,000
Income tax penalties expense	0	0	CAD 0
Accrued interest expense	4,000,000	4,000,000
Income tax penalties accrued	0	0
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards	1,280,000,000	1,786,000,000
Capital loss carryforwards	0
Capital loss carryforwards unrecognized	668,000,000	654,000,000
Canada federal and provincial | Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits	82,000,000	68,000,000
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards | $				$ 1,800	$ 2,545
Tax loss and credit carryforwards	CAD 0	CAD 0
Operating loss carryforward unrecognized | $				710	58
U.S. federal | Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits | $				56	37
Mexican Tax Authority
Net operating loss carryforwards
Tax loss and credit carryforwards | $				$ 7	$ 54

LONG-TERM DEBT - Schedule of Ac

LONG-TERM DEBT - Schedule of Activity and Summary of Principal Repayments (Details)	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2017CAD	Jun. 30, 2017USD ($)	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Outstanding at December 31			CAD 34,677,000,000	CAD 40,048,000,000
Current portion of long-term debt			(2,866,000,000)	(1,838,000,000)
Unamortized debt discount and issue costs			(174,000,000)	(191,000,000)
Fair value adjustments			238,000,000	293,000,000
Long-term debt, excluding current maturities			31,875,000,000	38,312,000,000
Decrease in fair value of interest rate hedge			4,000,000	0
Repayments of Long-term Debt [Abstract]
2,018			2,866,000,000
2,019			3,189,000,000
2,020			2,834,000,000
2,021			2,085,000,000
2,022			1,929,000,000
Columbian Pipeline
Debt Instrument [Line Items]
Estimated increase (decrease) in fair value of acquired liabilities, long-term debt	CAD 300,000,000	$ 231,000,000	242,000,000	293,000,000
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding at December 31			26,149,000,000	29,303,000,000
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Dates Between 2018 and 2020
Debt Instrument [Line Items]
Outstanding at December 31			CAD 500,000,000	CAD 600,000,000
Interest Rate			10.80%	10.70%	10.80%		10.70%
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Date of 2021
Debt Instrument [Line Items]
Outstanding at December 31			CAD 501,000,000	CAD 537,000,000	$ 400,000,000		$ 400,000,000
Interest Rate			9.90%	9.90%	9.90%		9.90%
TRANSCANADA PIPELINES LIMITED | Medium Term Notes
Debt Instrument [Line Items]
Outstanding at December 31			CAD 6,504,000,000	CAD 5,804,000,000
Interest Rate			4.90%	4.60%	4.90%		4.60%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding at December 31			CAD 18,644,000,000	CAD 19,660,000,000	$ 14,892,000,000		$ 14,642,000,000
Interest Rate			5.10%	5.10%	5.10%		5.10%
TRANSCANADA PIPELINES LIMITED | Acquisition Bridge Facility
Debt Instrument [Line Items]
Outstanding at December 31			CAD 0	CAD 2,702,000,000	$ 0		$ 2,013,000,000
Interest Rate			0.00%	1.90%	0.00%		1.90%
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding at December 31			CAD 895,000,000	CAD 917,000,000
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Dates of 2024
Debt Instrument [Line Items]
Outstanding at December 31			CAD 100,000,000	CAD 100,000,000
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 at December 31			CAD 250,000,000	CAD 269,000,000	$ 200,000,000		$ 200,000,000
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 at December 31			CAD 504,000,000	CAD 504,000,000
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 at December 31			CAD 41,000,000	CAD 44,000,000	$ 33,000,000		$ 33,000,000
Interest Rate			7.50%	7.50%	7.50%		7.50%
TRANSCANADA PIPELINE USA LTD. | Acquisition Bridge Facility
Debt Instrument [Line Items]
Outstanding at December 31			CAD 0	CAD 2,283,000,000	$ 0		$ 1,700,000,000
Interest Rate			0.00%	1.90%	0.00%		1.90%
Columbian Pipeline | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding at December 31			CAD 3,443,000,000	CAD 3,692,000,000	$ 2,750,000,000		$ 2,750,000,000
Interest Rate			4.00%	4.00%	4.00%		4.00%
TC PIPELINES, LP
Debt Instrument [Line Items]
Outstanding at December 31			CAD 2,573,000,000	CAD 2,054,000,000
TC PIPELINES, LP | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding at December 31			CAD 1,502,000,000	CAD 940,000,000	$ 1,200,000,000		$ 700,000,000
Interest Rate			4.40%	4.70%	4.40%		4.70%
TC PIPELINES, LP | Unsecured Loan Facility
Debt Instrument [Line Items]
Outstanding at December 31			CAD 232,000,000	CAD 215,000,000	$ 185,000,000		$ 160,000,000
Interest Rate			2.70%	1.90%	2.70%		1.90%
TC PIPELINES, LP | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding at December 31			CAD 839,000,000	CAD 899,000,000	$ 670,000,000		$ 670,000,000
Interest Rate			2.70%	1.90%	2.70%		1.90%
TC PIPELINES, LP | Unsecured Term Loan Maturing October 2020
Debt Instrument [Line Items]
Outstanding at December 31 | $						$ 170,000,000
TC PIPELINES, LP | Unsecured Term Loan Maturing October 2022
Debt Instrument [Line Items]
Outstanding at December 31 | $						$ 500,000,000
ANR PIPELINE COMPANY | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding at December 31			CAD 842,000,000	CAD 903,000,000	$ 672,000,000		$ 672,000,000
Interest Rate			7.20%	7.20%	7.20%		7.20%
GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Outstanding at December 31			CAD 382,000,000	CAD 423,000,000
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding at December 31			CAD 313,000,000	CAD 336,000,000	$ 250,000,000		$ 250,000,000
Interest Rate			5.60%	5.60%	5.60%		5.60%
GAS TRANSMISSION NORTHWEST LLC | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding at December 31			CAD 69,000,000	CAD 87,000,000	$ 55,000,000		$ 65,000,000
Interest Rate			1.10%	1.60%	1.10%		1.60%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding at December 31			CAD 324,000,000	CAD 373,000,000	$ 259,000,000		$ 278,000,000
Interest Rate			7.70%	7.70%	7.70%		7.70%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Senior Secured Notes
Debt Instrument [Line Items]
Outstanding at December 31			CAD 38,000,000	CAD 71,000,000	$ 30,000,000		$ 53,000,000
Interest Rate			6.00%	6.00%	6.00%		6.00%
TUSCARORA GAS TRANSMISSION COMPANY
Debt Instrument [Line Items]
Outstanding at December 31			CAD 31,000,000	CAD 29,000,000
TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding at December 31			CAD 31,000,000	CAD 13,000,000	$ 25,000,000		$ 10,000,000
Interest Rate			1.10%	1.90%	1.10%		1.90%
TUSCARORA GAS TRANSMISSION COMPANY | Senior Secured Notes
Debt Instrument [Line Items]
Outstanding at December 31			CAD 0	CAD 16,000,000	$ 0		$ 12,000,000
Interest Rate			0.00%	4.00%	0.00%		4.00%

LONG-TERM DEBT - Long-Term Debt

LONG-TERM DEBT - Long-Term Debt Issued (Details) CAD in Millions, $ in Millions

1 Months Ended

Nov. 30, 2017USD ($)

Sep. 30, 2017CAD

Aug. 31, 2017USD ($)

May 31, 2017USD ($)

Nov. 30, 2016USD ($)

Jun. 30, 2016CAD

Jun. 30, 2016USD ($)

Apr. 30, 2016USD ($)

Jan. 31, 2016USD ($)

Nov. 30, 2015USD ($)

Oct. 31, 2015CAD

Sep. 30, 2015USD ($)

Jul. 31, 2015CAD

Jun. 30, 2015USD ($)

Mar. 31, 2015USD ($)

Jan. 31, 2015USD ($)

Acquisition Bridge Facility

Debt Instrument [Line Items]

Amount

$ 6,900

TRANSCANADA PIPELINES LIMITED | Senior unsecured notes, floating interest rate

Debt Instrument [Line Items]

Amount

$ 550

TRANSCANADA PIPELINES LIMITED | 2.125% senior unsecured note, due November 2019

Debt Instrument [Line Items]

Amount

$ 700

Interest Rate

2.125%

TRANSCANADA PIPELINES LIMITED | 3.39% medium term notes, due March 2028

Debt Instrument [Line Items]

Amount | CAD

CAD 300

Interest Rate

3.39%

TRANSCANADA PIPELINES LIMITED | 4.33% medium term notes, due September 2047

Debt Instrument [Line Items]

Amount | CAD

CAD 700

Interest Rate

4.33%

TRANSCANADA PIPELINES LIMITED | Acquisition Bridge Facility

Debt Instrument [Line Items]

Amount

$ 5,213

TRANSCANADA PIPELINES LIMITED | 3.69% medium term notes, due July 2023

Debt Instrument [Line Items]

Amount | CAD

CAD 300

Interest Rate

3.69%

3.69%

Long-term debt, re-issuance yield, percent

2.69%

2.69%

TRANSCANADA PIPELINES LIMITED | 4.35% medium term notes, due June 2046

Debt Instrument [Line Items]

Amount | CAD

CAD 700

Interest Rate

4.35%

4.35%

TRANSCANADA PIPELINES LIMITED | 4.875% senior unsecured notes, due January 2026

Debt Instrument [Line Items]

Amount

$ 850

Interest Rate

4.875%

4.875%

TRANSCANADA PIPELINES LIMITED | 3.125% senior unsecured notes, due January 2019

Debt Instrument [Line Items]

Amount

$ 400

Interest Rate

3.125%

TRANSCANADA PIPELINES LIMITED | 1.625% senior unsecured notes, due November 2017

Debt Instrument [Line Items]

Amount

$ 1,000

Interest Rate

1.625%

1.625%

TRANSCANADA PIPELINES LIMITED | 4.55% medium-term notes, due November 2041

Debt Instrument [Line Items]

Amount | CAD

CAD 400

Interest Rate

4.55%

TRANSCANADA PIPELINES LIMITED | 3.30% medium-term notes, due July 2025

Debt Instrument [Line Items]

Amount | CAD

CAD 750

Interest Rate

3.30%

TRANSCANADA PIPELINES LIMITED | 4.60% senior unsecured notes, due March 2045

Debt Instrument [Line Items]

Amount

$ 750

Interest Rate

4.60%

TRANSCANADA PIPELINES LIMITED | 1.875% senior unsecured notes, due January 2018

Debt Instrument [Line Items]

Amount

$ 500

Interest Rate

1.875%

TRANSCANADA PIPELINES LIMITED | Senior unsecured notes, floating rates, due in January 2018

Debt Instrument [Line Items]

Amount

$ 250

TUSCARORA GAS TRANSMISSION COMPANY | Term loan, floating interest rate

Debt Instrument [Line Items]

Amount

$ 25

$ 10

TC PIPELINES, LP | 3.90% Senior Unsecured Notes

Debt Instrument [Line Items]

Amount

$ 500

Interest Rate

3.90%

TC PIPELINES, LP | Unsecured term loan, floating rate, due October 2018

Debt Instrument [Line Items]

Amount

$ 170

TC PIPELINES, LP | 4.375% senior unsecured notes, due March 2025

Debt Instrument [Line Items]

Amount

$ 350

Interest Rate

4.375%

TRANSCANADA PIPELINE USA LTD. | Acquisition Bridge Facility

Debt Instrument [Line Items]

Amount

$ 1,700

ANR PIPELINE COMPANY | 4.14% senior unsecured notes, due June 2026

Debt Instrument [Line Items]

Amount

$ 240

Interest Rate

4.14%

4.14%

GAS TRANSMISSION NORTHWEST LLC | Unsecured term loan, floating interest rate, due June 2019

Debt Instrument [Line Items]

Amount

$ 75

LONG-TERM DEBT - Retired (Detai

LONG-TERM DEBT - Retired (Details) CAD in Millions, $ in Millions

1 Months Ended

Dec. 31, 2017CAD

Nov. 30, 2017USD ($)

Aug. 31, 2017USD ($)

Jun. 30, 2017USD ($)

Apr. 30, 2017USD ($)

Feb. 28, 2017USD ($)

Jan. 31, 2017CAD

Nov. 30, 2016USD ($)

Oct. 31, 2016CAD

Jun. 30, 2016USD ($)

Feb. 29, 2016CAD

Jan. 31, 2016USD ($)

Aug. 31, 2015CAD

Jun. 30, 2015USD ($)

Mar. 31, 2015USD ($)

Jan. 31, 2015USD ($)

Nov. 30, 2015

TRANSCANADA PIPELINES LIMITED | Debentures, 9.80%

Debt Instrument [Line Items]

Amount | CAD

CAD 100

Interest Rate

9.80%

TRANSCANADA PIPELINES LIMITED | 1.625% senior unsecured notes, due November 2017

Debt Instrument [Line Items]

Amount

$ 1,000

Interest Rate

1.625%

1.625%

TRANSCANADA PIPELINES LIMITED | Bridge facility, floating rates

Debt Instrument [Line Items]

Amount

$ 1,513

$ 500

$ 3,200

TRANSCANADA PIPELINES LIMITED | Medium-Term Notes 5.10%

Debt Instrument [Line Items]

Amount | CAD

CAD 300

Interest Rate

5.10%

TRANSCANADA PIPELINES LIMITED | Medium-Term Notes at 4.65%

Debt Instrument [Line Items]

Amount | CAD

CAD 400

Interest Rate

4.65%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 7.69%

Debt Instrument [Line Items]

Amount

$ 84

Interest Rate

7.69%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, Floating Rate

Debt Instrument [Line Items]

Amount

$ 500

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes 0.75%

Debt Instrument [Line Items]

Amount

$ 750

Interest Rate

0.75%

TRANSCANADA PIPELINES LIMITED | Debentures, 11.90%

Debt Instrument [Line Items]

Amount | CAD

CAD 150

Interest Rate

11.90%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 3.40%

Debt Instrument [Line Items]

Amount

$ 500

Interest Rate

3.40%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 0.875%

Debt Instrument [Line Items]

Amount

$ 500

Interest Rate

0.875%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 4.875%

Debt Instrument [Line Items]

Amount

$ 300

Interest Rate

4.875%

4.875%

TUSCARORA GAS TRANSMISSION COMPANY | Senior Secured Notes, 3.82%

Debt Instrument [Line Items]

Amount

$ 12

Interest Rate

3.82%

TRANSCANADA PIPELINE USA LTD. | Bridge facility, floating rates

Debt Instrument [Line Items]

Amount

$ 1,070

$ 630

NOVA GAS TRANSMISSION LTD. | Debentures, 12.20%

Debt Instrument [Line Items]

Amount | CAD

CAD 225

Interest Rate

12.20%

GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes, 5.09%

Debt Instrument [Line Items]

Amount

$ 75

Interest Rate

5.09%

LONG-TERM DEBT - Interest Expen

LONG-TERM DEBT - Interest Expense and Payments (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Interest Expense [Abstract]
Capitalized interest	CAD (173)	CAD (176)	CAD (280)
Amortization and other financial charges	67	211	31
Interest expense	2,069	1,998	1,370
Interest payments on long-term debt and junior subordinated notes, net of interest capitalized on construction projects	1,987	1,721	1,266
Interest Expense
Interest Expense [Abstract]
Dividend equivalent payments recorded as interest expense		109
Short-term debt
Interest Expense [Abstract]
Interest on debt	33	18	16
Total long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest on debt	1,794	1,765	1,487
Junior subordinated notes
Interest Expense [Abstract]
Interest on debt	CAD 348	CAD 180	CAD 116

JUNIOR SUBORDINATED NOTES (Deta

JUNIOR SUBORDINATED NOTES (Details)	1 Months Ended			3 Months Ended
	May 31, 2017USD ($)	Mar. 31, 2017USD ($)	Aug. 31, 2016USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	May 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2007USD ($)
Debt Instrument [Line Items]
Outstanding at December 31					CAD 34,677,000,000			CAD 40,048,000,000
Unamortized debt discount and issue costs					(174,000,000)			(191,000,000)
Long-term Debt | $						$ 1,100,000,000			$ 850,000,000
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding at December 31					26,149,000,000			29,303,000,000
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding at December 31					7,071,000,000			3,961,000,000
Unamortized debt discount and issue costs					(64,000,000)			(30,000,000)
Long-term Debt					7,007,000,000			3,931,000,000
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount | $											$ 1,000,000,000
Outstanding at December 31					CAD 1,252,000,000			CAD 1,343,000,000
Effective Interest Rate					5.00%	5.00%		6.40%	6.40%
Debt converted | $	$ 1,000,000,000
Stated interest rate							6.35%
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]
Debt instrument, face amount | $										$ 750,000,000
Outstanding at December 31					CAD 939,000,000			CAD 1,007,000,000
Effective Interest Rate					5.90%	5.90%		5.50%	5.50%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2076 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount | $									$ 1,200,000,000
Outstanding at December 31					CAD 1,502,000,000			CAD 1,611,000,000
Effective Interest Rate					6.60%	6.60%		6.20%	6.20%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2077 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount | $						$ 1,500,000,000
Outstanding at December 31					CAD 1,878,000,000			CAD 0
Effective Interest Rate					5.60%	5.60%		0.00%	0.00%
TRANSCANADA PIPELINES LIMITED | Canadian junior subordinated debt, due 2077 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount | $						$ 1,500,000,000
Outstanding at December 31					CAD 1,500,000,000			CAD 0
Effective Interest Rate					5.10%	5.10%		0.00%	0.00%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-A | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount | $		$ 1,500,000,000		$ 1,500,000,000
Stated interest rate		5.55%		5.55%
Administrative charge (percent)		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							CAD 1,500,000,000
Stated interest rate							4.90%
Administrative charge (percent)							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
Stated interest rate			6.125%
Administrative charge (percent)			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		$ 1,500,000,000
Stated interest rate, period of time (in years)				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							CAD 1,500,000,000
Stated interest rate, period of time (in years)	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
Stated interest rate, period of time (in years)			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 (Deta

NON-CONTROLLING INTERESTS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	CAD 1,852	CAD 1,726
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	238	252	CAD 6
Noncontrolling Interest
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	(238)	(252)	(6)
Noncontrolling Interest | TC PipeLines, LP
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	1,852	1,596
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	220	215	(13)
Noncontrolling Interest | Portland Natural Gas Transmission System
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	0	130
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	9	20	19
Noncontrolling Interest | Columbia Pipeline Partners LP
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	CAD 9	CAD 17	CAD 0

NON-CONTROLLING INTERESTS - Nar

NON-CONTROLLING INTERESTS - Narrative (Details) $ / shares in Units, shares in Millions, CAD in Millions, $ in Millions	Jun. 01, 2017	Feb. 17, 2017USD ($)$ / shares	Jan. 01, 2016	May 19, 2016shares	May 31, 2017CAD	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Dec. 31, 2015USD ($)	Dec. 31, 2016USD ($)	Jul. 01, 2016
Non-controlling interests
Asset impairment charges						CAD 1,257	CAD 1,388	CAD 3,745
Common units outstanding, subject to rescission, amount						0	1,179
Noncontrolling Interest
Non-controlling interests
Share price (in dollars per share) | $ / shares		$ 17
Stub period distribution payments acquired (in dollars per share) | $ / shares		$ 0.10
Aggregate transaction value		$ 921				41	40	11
Columbian Pipeline | Noncontrolling Interest
Non-controlling interests
Percentage of non-controlling interests											53.50%
Columbia Pipeline Partners LP
Non-controlling interests
Common units outstanding, subject to rescission, amount							1,073			$ 799
TC PipeLines, LP
Non-controlling interests
Asset impairment charges | $									$ 199
Fees received for services provided						CAD 5	5	CAD 4
Common units outstanding, subject to rescission, amount							CAD 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 PipeLines, LP | Noncontrolling Interest
Non-controlling interests
Percentage of non-controlling interests						74.30%	73.20%			73.20%
Asset impairment charges | $									$ 143
TC PipeLines, LP | Noncontrolling Interest | Minimum
Non-controlling interests
Percentage of non-controlling interests							72.00%	71.70%	71.70%	72.00%
TC PipeLines, LP | Noncontrolling Interest | Maximum
Non-controlling interests
Percentage of non-controlling interests							73.20%	72.00%	72.00%	73.20%
Portland Natural Gas Transmission System
Non-controlling interests
Fees received for services provided					CAD 4		CAD 10	CAD 11
Portland Natural Gas Transmission System | Noncontrolling Interest
Non-controlling interests
Percentage of non-controlling interests						0.00%	38.30%			38.30%
Ownership interest before transaction, percent	11.81%		49.90%

COMMON SHARES - Reconciliation

COMMON SHARES - Reconciliation (Details) - CAD CAD in Millions	1 Months Ended			12 Months Ended
	Nov. 30, 2016	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)				864,000,000
Outstanding at the beginning of the period				CAD 20,099
Exercise of options (in shares)				1,331,000
Repurchase of shares (in shares)		(305,407)	(6,784,738)
Repurchase of shares		CAD (14)	CAD (294)
Issued under public offerings (in shares)	60,200,000
Outstanding at the end of the period (in shares)				881,000,000	864,000,000
Outstanding at the end of the period				CAD 21,167	CAD 20,099
Weighted Average Common Shares Outstanding
Basic (in shares)				872,000,000	759,000,000	709,000,000
Diluted (in shares)				874,000,000	760,000,000	709,000,000
Common Shares
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)		702,614,000		863,759,000	702,614,000	708,662,000
Outstanding at the beginning of the period		CAD 12,102		CAD 20,099	CAD 12,102	CAD 12,202
Exercise of options (in shares)				1,331,000	1,683,000	737,000
Exercise of options				CAD 62	CAD 74	CAD 30
Repurchase of shares (in shares)					(305,000)	(6,785,000)
Repurchase of shares		CAD (6)	CAD (130)		CAD (6)	CAD (130)
Issued under public offerings (in shares)					156,825,000
Issued under public offerings					CAD 7,752
Dividend reinvestment and share purchase plan (in shares)				12,824,000	2,942,000
Dividend reinvestment and share purchase plan				CAD 790	CAD 177
At-the-market equity issuance program (in shares)				3,462,000
At-the-market equity issuance program				CAD 216
Outstanding at the end of the period (in shares)			702,614,000	881,376,000	863,759,000	702,614,000
Outstanding at the end of the period			CAD 12,102	CAD 21,167	CAD 20,099	CAD 12,102
Weighted Average Common Shares Outstanding
Basic (in shares)				872,000,000	759,000,000	709,000,000
Diluted (in shares)				874,000,000	760,000,000	709,000,000

COMMON SHARES - Dividend Reinve

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 Cor

COMMON SHARES - TransCanada Corporation At-the-Market Equity Issuance Program (Details) - CAD CAD / shares in Units, shares in Millions	Dec. 31, 2017	Jun. 30, 2017	Nov. 30, 2016
Subsidiary, Sale of Stock [Line Items]
Price per share (in Canadian dollars per share)			CAD 58.50
At-the-Market Equity Issuance Program
Subsidiary, Sale of Stock [Line Items]
Stock issuance program, period in effect (in months)		25 months
Common stock, shares authorized (in shares)		CAD 1,000,000,000
Treasury stock reissued during period (in shares)	3.5
Price per share (in Canadian dollars per share)	CAD 63.03
Shares issued At-the-market equity issuance program	CAD 218,000,000
Payments of stock issuance costs	2,000,000
Consideration received on transaction	CAD 216,000,000

COMMON SHARES - Public Offering

COMMON SHARES - Public Offering and Subscription Receipts (Details) CAD / shares in Units, CAD in Millions, $ in Billions	1 Months Ended			12 Months Ended
	Nov. 30, 2016CADCAD / sharesshares	Nov. 30, 2016USD ($)shares	Apr. 30, 2016CADCAD / sharesshares	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD
Class of Stock [Line Items]
Subscription receipt (in shares) | shares			96,600,000
Share price (in CAD per share) | CAD / shares			CAD 45.75
Common stock, value, subscriptions | CAD			CAD 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) | CAD / shares	CAD 58.50
Common shares issued, net of issue costs | CAD	CAD 3,500			CAD 274	CAD 7,747	CAD 27
Bridge facility, floating rates
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 | CAD					CAD 109

COMMON SHARES - Common Shares R

COMMON SHARES - Common Shares Repurchased (Details) - CAD CAD / shares in Units, CAD in Millions	1 Months Ended			12 Months Ended
	Jan. 31, 2016	Dec. 31, 2015	Nov. 30, 2015	Dec. 31, 2016	Dec. 31, 2015
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	6,784,738
Average price per share of common shares repurchased (in Canadian dollars per share)	CAD 44.90	CAD 43.29
Value recorded for common stock repurchased	CAD 14	CAD 294
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	6,785,000
Value recorded for common stock repurchased	6	130		CAD 6	CAD 130
Additional Paid-In Capital
Class of Stock [Line Items]
Value recorded for common stock repurchased	CAD 8	CAD 164		CAD 8	CAD 164

COMMON SHARES - Options (Detail

COMMON SHARES - Options (Details)	12 Months Ended
	Dec. 31, 2017CAD / sharesshares
Number of Options (thousands)
Outstanding at the beginning of the period (in shares)	10,630,000
Granted (in shares)	2,066,000
Exercised (in shares)	(1,331,000)
Options forfeited/expired (in shares)	(339,000)
Outstanding at the end of the period (in shares)	11,026,000
Options Exercisable (in shares)	6,559,000
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share) | CAD / shares	CAD 48.28
Granted (in Canadian dollars per share) | CAD / shares	62.22
Exercised (in Canadian dollars per share) | CAD / shares	42.03
Options forfeited/expired (in Canadian dollars per share) | CAD / shares	56.89
Outstanding at the end of the period (in Canadian dollars per share) | CAD / shares	51.38
Options Exercisable at December 31, 2017 (in Canadian dollars per share) | CAD / shares	CAD 48.59
Weighted Average Remaining Contractual Life (years)
Options Outstanding (in years)	3 years 10 months 24 days
Options Exercisable (in years)	3 years
Number of shares available for grant (in shares)	11,902,759
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 A

COMMON SHARES - Stock Options Assumptions Used (Details) - CAD CAD / shares in Units, CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Weighted average fair value (in dollars per share)	CAD 7.22	CAD 5.67	CAD 6.45
Expected life (years)	5 years 8 months 12 days	5 years 9 months 18 days	5 years 9 months 18 days
Interest rate	1.20%	0.70%	1.10%
Volatility	18.00%	21.00%	18.00%
Dividend yield	3.60%	4.90%	3.70%
Forfeiture rate	0.00%	5.00%	5.00%
Expense for stock options	CAD 12	CAD 15	CAD 13
Unrecognized compensation costs related to non-vested stock options	CAD 15
Employee Stock Option
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Expense recognition period (in years)	3 years

COMMON SHARES - Summary of Addi

COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD shares in Millions, CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Total intrinsic value of options exercised	CAD 28	CAD 31	CAD 10
Fair value of options that have vested	CAD 140	CAD 126	CAD 91
Total options vested (in shares)	2.3	2.1	2
Options, exercisable, intrinsic value	CAD 83
Options, outstanding, intrinsic value	CAD 110

COMMON SHARES - Shareholder Rig

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2017shares
Shareholder Rights Plan
Number of rights entitled to each common share (in shares)	1

PREFERRED SHARES (Details)

PREFERRED SHARES (Details) - CAD CAD / shares in Units, CAD in Millions	Dec. 31, 2015	Nov. 30, 2016	Apr. 30, 2016	Feb. 29, 2016	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016
Preferred Shares [Line Items]
Preferred Shares	CAD 2,499						CAD 3,980	CAD 3,980
Number of shares issued (in shares)		60,200,000
Series 1
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)							9,498,000
Preferred shares, outstanding (in shares)							9,498,000
Current Yield							3.266%
Annual Dividend Rate per Share (in Canadian dollars per share)							CAD 0.8165
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	233						CAD 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, authorized (in shares)							12,502,000
Preferred shares, outstanding (in shares)							12,502,000
Current Yield							2.792%
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	306						CAD 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, authorized (in shares)							8,533,000
Preferred shares, outstanding (in shares)							8,533,000
Current Yield							2.152%
Annual Dividend Rate per Share (in Canadian dollars per share)							CAD 0.538
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	CAD 209						CAD 209	209
Number of shares converted (in shares)					5,466,595
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, authorized (in shares)							5,467,000
Preferred shares, outstanding (in shares)							5,467,000
Current Yield	2.152%
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	CAD 134						CAD 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, authorized (in shares)							12,714,000
Preferred shares, outstanding (in shares)							12,714,000
Current Yield							2.263%
Annual Dividend Rate per Share (in Canadian dollars per share)							CAD 0.56575
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	342						CAD 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, authorized (in shares)							1,286,000
Preferred shares, outstanding (in shares)							1,286,000
Current Yield							2.549%
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	0						CAD 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, authorized (in shares)							24,000,000
Preferred shares, outstanding (in shares)							24,000,000
Current Yield							4.00%
Annual Dividend Rate per Share (in Canadian dollars per share)							CAD 1
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	589						CAD 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, authorized (in shares)							18,000,000
Preferred shares, outstanding (in shares)							18,000,000
Current Yield							4.25%
Annual Dividend Rate per Share (in Canadian dollars per share)							CAD 1.0625
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	442						CAD 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, authorized (in shares)							10,000,000
Preferred shares, outstanding (in shares)							10,000,000
Current Yield							3.80%
Annual Dividend Rate per Share (in Canadian dollars per share)							CAD 0.95
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	244						CAD 244	244
Number of shares issued (in shares)						10,000,000
Price per share (in Canadian dollars per share)						CAD 25
Gross proceeds from public offering of preferred shares						CAD 250
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, authorized (in shares)							20,000,000
Preferred shares, outstanding (in shares)							20,000,000
Current Yield							5.50%
Annual Dividend Rate per Share (in Canadian dollars per share)							CAD 1.375
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	0						CAD 493	493
Number of shares issued (in shares)			20,000,000
Price per share (in Canadian dollars per share)			CAD 25
Gross proceeds from public offering of preferred shares			CAD 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							550.00%
Series 15
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)							40,000,000
Preferred shares, outstanding (in shares)							40,000,000
Current Yield							4.90%
Annual Dividend Rate per Share (in Canadian dollars per share)							CAD 1.225
Redemption Price Per Share (in Canadian dollars per share)							CAD 25
Preferred Shares	CAD 0						CAD 988	CAD 988
Number of shares issued (in shares)		40,000,000
Price per share (in Canadian dollars per share)		CAD 25
Gross proceeds from public offering of preferred shares		CAD 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							490.00%
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)							CAD 25.50

OTHER COMPREHENSIVE (LOSS)_I109

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Before Tax Amount
Other Comprehensive Income (Loss)	CAD (957)	CAD (29)	CAD 522
Income Tax Recovery/(Expense)
Other Comprehensive Income (Loss)	31	(3)	80
Net of Tax Amount
Other comprehensive (loss)/income (Note 22)	(926)	(32)	602
Foreign currency translation losses on net investment in foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(746)	3	798
Reclassification from accumulated other comprehensive Income	(77)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	(3)	0	15
Reclassification from AOCI	0
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(749)	3	813
Reclassification from accumulated other comprehensive income	(77)
Change in fair value of net investment hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	0	(14)	(505)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	0	4	133
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	0	(10)	(372)
Cash flow hedge
Before Tax Amount
Other comprehensive income (loss), before reclassifications	3	44	(92)
Reclassification from accumulated other comprehensive Income	(3)	71	144
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	0	(14)	35
Reclassification from AOCI	1	(29)	(56)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	3	30	(57)
Reclassification from accumulated other comprehensive income	(2)	42	88
Pension and other post-retirement benefits
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(14)	(38)	74
Reclassification from accumulated other comprehensive Income	21	22	41
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	3	12	(23)
Reclassification from AOCI	(5)	(6)	(9)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(11)	(26)	51
Reclassification from accumulated other comprehensive income	16	16	32
Other comprehensive loss on equity investments
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(141)	(117)	62
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	35	30	(15)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	CAD (106)	CAD (87)	CAD 47

OTHER COMPREHENSIVE (LOSS)_I110

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	CAD 25,983,000,000	CAD 18,155,000,000
Other comprehensive (loss)/income (Note 22)	(926,000,000)	(32,000,000)	CAD 602,000,000
Balance at end of year	26,891,000,000	25,983,000,000	18,155,000,000
Accumulated benefit obligation, (increase) decrease for settlement and curtailment	27,000,000
Cash flow hedge loss reported in AOCI and expected to be reclassified to net income in the next 12 months, net of tax	19,000,000
Cash flow hedge gain (loss) to be reclassified within twelve months, net of tax	(14,000,000)
Currency Translation Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(376,000,000)	(383,000,000)	(518,000,000)
Other comprehensive income/(loss), before reclassifications	(590,000,000)	7,000,000	135,000,000
Amounts reclassified from AOCI	(77,000,000)	0	0
Other comprehensive (loss)/income (Note 22)	(667,000,000)	7,000,000	135,000,000
Balance at end of year	(1,043,000,000)	(376,000,000)	(383,000,000)
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(28,000,000)	(97,000,000)	(128,000,000)
Other comprehensive income/(loss), before reclassifications	(1,000,000)	27,000,000	(57,000,000)
Amounts reclassified from AOCI	(2,000,000)	42,000,000	88,000,000
Other comprehensive (loss)/income (Note 22)	(3,000,000)	69,000,000	31,000,000
Balance at end of year	(31,000,000)	(28,000,000)	(97,000,000)
Pension and Other Post-Retirement Benefit Plan Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(208,000,000)	(198,000,000)	(281,000,000)
Other comprehensive income/(loss), before reclassifications	(11,000,000)	(26,000,000)	51,000,000
Amounts reclassified from AOCI	16,000,000	16,000,000	32,000,000
Other comprehensive (loss)/income (Note 22)	5,000,000	(10,000,000)	83,000,000
Balance at end of year	(203,000,000)	(208,000,000)	(198,000,000)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(348,000,000)	(261,000,000)	(308,000,000)
Other comprehensive income/(loss), before reclassifications	(117,000,000)	(101,000,000)	33,000,000
Amounts reclassified from AOCI	11,000,000	14,000,000	14,000,000
Other comprehensive (loss)/income (Note 22)	(106,000,000)	(87,000,000)	47,000,000
Balance at end of year	(454,000,000)	(348,000,000)	(261,000,000)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(960,000,000)	(939,000,000)	(1,235,000,000)
Other comprehensive income/(loss), before reclassifications	(719,000,000)	(93,000,000)	162,000,000
Amounts reclassified from AOCI	(52,000,000)	72,000,000	134,000,000
Other comprehensive (loss)/income (Note 22)	(771,000,000)	(21,000,000)	296,000,000
Balance at end of year	(1,731,000,000)	(960,000,000)	(939,000,000)
Accumulated foreign currency adjustment attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive income/(loss), before reclassifications	(159,000,000)	(14,000,000)	306,000,000
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	CAD 4,000,000	CAD 3,000,000	CAD 0

OTHER COMPREHENSIVE (LOSS)_I111

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	CAD 1,378	CAD 1,476	CAD 1,207
Income tax (recovery)/expense	89	(352)	(34)
Net Income/(Loss) Attributable to Common Shares	2,997	124	(1,240)
Gain/(loss) on sale of assets held for sale/sold	631	(833)	(125)
Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net of tax	2	(42)	(88)
Pension and other post-retirement benefit plan adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net of tax	(16)	(16)	(32)
Currency translation adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net of tax	77	0	0
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	3	(71)	(144)
Income tax (recovery)/expense	(1)	29	56
Net Income/(Loss) Attributable to Common Shares	2	(42)	(88)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash Flow Hedges | Commodities
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Energy)	20	(57)	(128)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash Flow Hedges | Interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(17)	(14)	(16)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Amortization of actuarial loss and past service cost
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	(15)	(22)	(41)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Settlement charge
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	(2)	0	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	(17)	(22)	(41)
Income tax (recovery)/expense	5	6	9
Net of tax	(12)	(16)	(32)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Other comprehensive income on equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (recovery)/expense	4	5	5
Net Income/(Loss) Attributable to Common Shares	(11)	(14)	(14)
Income from equity investments	(15)	(19)	(19)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Currency translation adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (recovery)/expense		0	0
Net Income/(Loss) Attributable to Common Shares	77	0	0
Gain/(loss) on sale of assets held for sale/sold	CAD 77	CAD 0	CAD 0

EMPLOYEE POST-RETIREMENT BEN112

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments and Changes (Details) CAD in Millions	Sep. 30, 2017CAD	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Apr. 01, 2017election
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		CAD 42	CAD 52	CAD 41
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Savings and DC Plans		42	52	41
Total cash contributions		212	171	CAD 143
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		3,562
Plan assets at fair value – end of year		3,816	3,562
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 12)		193	189
Other long-term liabilities (Note 15)		CAD (389)	CAD (448)
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	12 years
Number of final elections | election					1
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans		CAD 163	CAD 111	CAD 96
Total amount outstanding under letters of credit		CAD 260	CAD 233
Discount rate		3.60%	4.00%
Remeasurements impact on unrealized actuarial gain (loss), recorded in regulated assets		CAD (2)	CAD 0	0
Change in Benefit Obligation
Benefit obligation – beginning of year		3,456	2,780
Service cost		113	107
Interest cost		135	127
Employee contributions		5	4
Benefits paid		(166)	(204)
Actuarial loss/(gain)		253	111
Acquisition of Columbia		0	527
Curtailment		(14)	0
Settlement		(66)	2
Foreign exchange rate changes		(70)	2
Benefit obligation – end of year		3,646	3,456	2,780
Change in Plan Assets
Plan assets at fair value – beginning of year		3,208	2,591
Actual return on plan assets		358	227
Employer contributions		163	111	96
Employee contributions		5	4
Benefits paid		(166)	(204)
Acquisition of Columbia		0	475
Settlement		(57)	0
Foreign exchange rate changes		(60)	4
Plan assets at fair value – end of year		3,451	3,208	2,591
Funded Status – Plan Deficit		(195)	(248)
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 12)		0	0
Accounts payable and other		(1)	0
Other long-term liabilities (Note 15)		(194)	(248)
Net		(195)	(248)
Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans		CAD 7	CAD 8	6
Discount rate		3.70%	4.15%
Remeasurements impact on unrealized actuarial gain (loss), recorded in regulated assets		CAD 0	CAD 0	0
Change in Benefit Obligation
Benefit obligation – beginning of year		372	225
Service cost		4	3
Interest cost		14	13
Employee contributions		3	2
Benefits paid		(19)	(16)
Actuarial loss/(gain)		19	(8)
Acquisition of Columbia		0	151
Curtailment		(2)	0
Settlement		0	0
Foreign exchange rate changes		(16)	2
Benefit obligation – end of year		375	372	225
Change in Plan Assets
Plan assets at fair value – beginning of year		354	45
Actual return on plan assets		45	14
Employer contributions		7	8	6
Employee contributions		3	2
Benefits paid		(19)	(16)
Acquisition of Columbia		0	294
Settlement		0	0
Foreign exchange rate changes		(25)	7
Plan assets at fair value – end of year		365	354	45
Funded Status – Plan Deficit		(10)	(18)
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 12)		193	189
Accounts payable and other		(8)	(7)
Other long-term liabilities (Note 15)		(195)	(200)
Net		(10)	(18)
Canadian | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Letter of credit to the DB Plan		27	CAD 20	CAD 33
Total amount outstanding under letters of credit		CAD 260
U.S. | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Discount rate		4.10%
Other comprehensive income (loss), defined benefit plan, settlement and curtailment gain (loss)		CAD 3
Net periodic benefit cost (credit), gain (loss) due to settlement		CAD 2
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	CAD 16
Remeasurements impact on unrealized actuarial gain (loss), recorded in regulated assets	14
Remeasurement impact recorded in OCI	CAD 2

EMPLOYEE POST-RETIREMENT BEN113

EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Funded status based on accumulated benefit obligation
Plan assets at fair value	CAD 3,816	CAD 3,562
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	CAD (3,646)	CAD (3,456)
Plan assets at fair value	3,451	3,208
Funded Status – Plan Deficit	(195)	(248)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(3,372)	(3,202)
Plan assets at fair value	3,451	3,208	CAD 2,591
Funded Status – Plan Surplus	79	6
Accumulated benefit obligation and fair value of plan assets for plans that are not fully funded
Accumulated benefit obligation	(944)	(990)
Plan assets at fair value	925	868
Funded Status – Plan Deficit	CAD (19)	CAD (122)
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	30.00%	31.00%
Amount of debt or common shares included in plan assets	CAD 7	CAD 9
Percentage of Plan Assets	0.20%	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	40.00%
Pension Benefit Plans | Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	64.00%	63.00%
Amount of debt or common shares included in plan assets	CAD 3	CAD 4
Percentage of Plan Assets	0.10%	0.10%
Pension Benefit Plans | Equity securities | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	45.00%
Pension Benefit Plans | Equity securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	75.00%
Pension Benefit Plans | Alternatives
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	6.00%	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%
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	CAD (203)	CAD (207)
Plan assets at fair value	0	0
Funded Status – Plan Deficit	(203)	(207)
Funded status based on accumulated benefit obligation
Plan assets at fair value	CAD 365	CAD 354	CAD 45

EMPLOYEE POST-RETIREMENT BEN114

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Employee post-retirement benefits
Fair value of plan assets	CAD 3,816	CAD 3,562
Percentage of Total Portfolio	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	CAD 1,186	CAD 1,089
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	2,414	2,274
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	216	199	CAD 14
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	CAD 61	CAD 34
Percentage of Total Portfolio	2.00%	1.00%
Cash and Cash Equivalents | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	CAD 44	CAD 22
Cash and Cash Equivalents | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	17	12
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	CAD 561	CAD 531
Percentage of Total Portfolio	15.00%	15.00%
Equity securities | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 897	CAD 980
Percentage of Total Portfolio	24.00%	27.00%
Equity securities | International
Employee post-retirement benefits
Fair value of plan assets	CAD 367	CAD 366
Percentage of Total Portfolio	10.00%	10.00%
Equity securities | Global
Employee post-retirement benefits
Fair value of plan assets	CAD 301	CAD 235
Percentage of Total Portfolio	8.00%	7.00%
Equity securities | Emerging
Employee post-retirement benefits
Fair value of plan assets	CAD 155	CAD 144
Percentage of Total Portfolio	4.00%	4.00%
Equity securities | Quoted Prices in Active Markets (Level I) | Canadian
Employee post-retirement benefits
Fair value of plan assets	CAD 410	CAD 388
Equity securities | Quoted Prices in Active Markets (Level I) | U.S.
Employee post-retirement benefits
Fair value of plan assets	543	504
Equity securities | Quoted Prices in Active Markets (Level I) | International
Employee post-retirement benefits
Fair value of plan assets	45	39
Equity securities | Quoted Prices in Active Markets (Level I) | Global
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities | Quoted Prices in Active Markets (Level I) | Emerging
Employee post-retirement benefits
Fair value of plan assets	8	7
Equity securities | Significant Other Observable Inputs (Level II) | Canadian
Employee post-retirement benefits
Fair value of plan assets	151	143
Equity securities | Significant Other Observable Inputs (Level II) | U.S.
Employee post-retirement benefits
Fair value of plan assets	354	476
Equity securities | Significant Other Observable Inputs (Level II) | International
Employee post-retirement benefits
Fair value of plan assets	322	327
Equity securities | Significant Other Observable Inputs (Level II) | Global
Employee post-retirement benefits
Fair value of plan assets	301	235
Equity securities | Significant Other Observable Inputs (Level II) | Emerging
Employee post-retirement benefits
Fair value of plan assets	147	137
Equity securities | Significant Unobservable Inputs (Level III) | Canadian
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities | Significant Unobservable Inputs (Level III) | U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities | Significant Unobservable Inputs (Level III) | International
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities | Significant Unobservable Inputs (Level III) | Global
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities | Significant Unobservable Inputs (Level III) | Emerging
Employee post-retirement benefits
Fair value of plan assets	0	0
Federal | Canadian
Employee post-retirement benefits
Fair value of plan assets	CAD 193	CAD 192
Percentage of Total Portfolio	5.00%	5.00%
Federal | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 244	CAD 82
Percentage of Total Portfolio	6.00%	2.00%
Federal | Quoted Prices in Active Markets (Level I) | Canadian
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 0
Federal | Quoted Prices in Active Markets (Level I) | U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Federal | Significant Other Observable Inputs (Level II) | Canadian
Employee post-retirement benefits
Fair value of plan assets	193	192
Federal | Significant Other Observable Inputs (Level II) | U.S.
Employee post-retirement benefits
Fair value of plan assets	244	82
Federal | Significant Unobservable Inputs (Level III) | Canadian
Employee post-retirement benefits
Fair value of plan assets	0	0
Federal | Significant Unobservable Inputs (Level III) | U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Provincial | Canadian
Employee post-retirement benefits
Fair value of plan assets	CAD 194	CAD 179
Percentage of Total Portfolio	5.00%	5.00%
Provincial | Quoted Prices in Active Markets (Level I) | Canadian
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 0
Provincial | Significant Other Observable Inputs (Level II) | Canadian
Employee post-retirement benefits
Fair value of plan assets	194	179
Provincial | Significant Unobservable Inputs (Level III) | Canadian
Employee post-retirement benefits
Fair value of plan assets	0	0
Municipal | Canadian
Employee post-retirement benefits
Fair value of plan assets	CAD 8	CAD 8
Percentage of Total Portfolio	0.00%	0.00%
Municipal | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 4	CAD 39
Percentage of Total Portfolio	0.00%	1.00%
Municipal | Quoted Prices in Active Markets (Level I) | Canadian
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 0
Municipal | Quoted Prices in Active Markets (Level I) | U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Municipal | Significant Other Observable Inputs (Level II) | Canadian
Employee post-retirement benefits
Fair value of plan assets	8	8
Municipal | Significant Other Observable Inputs (Level II) | U.S.
Employee post-retirement benefits
Fair value of plan assets	4	39
Municipal | Significant Unobservable Inputs (Level III) | Canadian
Employee post-retirement benefits
Fair value of plan assets	0	0
Municipal | Significant Unobservable Inputs (Level III) | U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate | Canadian
Employee post-retirement benefits
Fair value of plan assets	CAD 122	CAD 126
Percentage of Total Portfolio	3.00%	4.00%
Corporate | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 234	CAD 188
Percentage of Total Portfolio	6.00%	5.00%
Corporate | International
Employee post-retirement benefits
Fair value of plan assets	CAD 5	CAD 21
Percentage of Total Portfolio	0.00%	1.00%
Corporate | Quoted Prices in Active Markets (Level I) | Canadian
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 0
Corporate | Quoted Prices in Active Markets (Level I) | U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate | Quoted Prices in Active Markets (Level I) | International
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate | Significant Other Observable Inputs (Level II) | Canadian
Employee post-retirement benefits
Fair value of plan assets	122	126
Corporate | Significant Other Observable Inputs (Level II) | U.S.
Employee post-retirement benefits
Fair value of plan assets	234	188
Corporate | Significant Other Observable Inputs (Level II) | International
Employee post-retirement benefits
Fair value of plan assets	5	21
Corporate | Significant Unobservable Inputs (Level III) | Canadian
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate | Significant Unobservable Inputs (Level III) | U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate | Significant Unobservable Inputs (Level III) | International
Employee post-retirement benefits
Fair value of plan assets	0	0
State | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 41	CAD 41
Percentage of Total Portfolio	1.00%	1.00%
State | Quoted Prices in Active Markets (Level I) | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 0
State | Significant Other Observable Inputs (Level II) | U.S.
Employee post-retirement benefits
Fair value of plan assets	41	41
State | Significant Unobservable Inputs (Level III) | U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Government | International
Employee post-retirement benefits
Fair value of plan assets	CAD 4	CAD 6
Percentage of Total Portfolio	0.00%	0.00%
Government | Quoted Prices in Active Markets (Level I) | International
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 0
Government | Significant Other Observable Inputs (Level II) | International
Employee post-retirement benefits
Fair value of plan assets	4	6
Government | Significant Unobservable Inputs (Level III) | International
Employee post-retirement benefits
Fair value of plan assets	0	0
Mortgage backed | International
Employee post-retirement benefits
Fair value of plan assets	CAD 73	CAD 62
Percentage of Total Portfolio	2.00%	2.00%
Mortgage backed | Quoted Prices in Active Markets (Level I) | International
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 0
Mortgage backed | Significant Other Observable Inputs (Level II) | International
Employee post-retirement benefits
Fair value of plan assets	73	62
Mortgage backed | Significant Unobservable Inputs (Level III) | International
Employee post-retirement benefits
Fair value of plan assets	0	0
Real estate
Employee post-retirement benefits
Fair value of plan assets	CAD 140	CAD 133
Percentage of Total Portfolio	4.00%	4.00%
Real estate | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 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	140	133
Infrastructure
Employee post-retirement benefits
Fair value of plan assets	CAD 70	CAD 58
Percentage of Total Portfolio	2.00%	2.00%
Infrastructure | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 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	70	58
Private equity funds
Employee post-retirement benefits
Fair value of plan assets	CAD 6	CAD 8
Percentage of Total Portfolio	0.00%	0.00%
Private equity funds | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	CAD 0	CAD 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	6	8
Funds held on deposit
Employee post-retirement benefits
Fair value of plan assets	CAD 136	CAD 129
Percentage of Total Portfolio	3.00%	4.00%
Funds held on deposit | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	CAD 136	CAD 129
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	CAD 0	CAD 0

EMPLOYEE POST-RETIREMENT BEN115

EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	CAD 3,562
Plan assets at fair value – end of year	3,816	CAD 3,562
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	199	14
Purchases and sales	11	183
Realized and unrealized gains	6	2
Plan assets at fair value – end of year	CAD 216	CAD 199

EMPLOYEE POST-RETIREMENT BEN116

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	CAD 45
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits	7.00%
Percentage level to which average annual rate was assumed to decrease	5.00%
Effects of a one per cent change in assumed health care cost trend rates
Effect on total of service and interest cost components, Increase	CAD 1
Effect on total of service and interest cost components, Decrease	(1)
Effect on post-retirement benefit obligation, Increase	15
Effect on post-retirement benefit obligation, Decrease	(13)
Pension Benefit Plans
DB Plans
Company's expected funding contributions	98
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	27
Estimated future benefit payments, which reflect expected future service
2,018	181
2,019	187
2,020	190
2,021	196
2,022	200
2023 to 2027	CAD 1,054
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	3.60%	4.00%
Rate of compensation increase	3.00%	1.20%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	3.95%	4.20%	4.15%
Expected long-term rate of return on plan assets	6.50%	6.70%	6.95%
Rate of compensation increase	1.20%	0.80%	3.15%
Net benefit cost
Service cost	CAD 108	CAD 107	CAD 108
Interest cost	122	127	115
Expected return on plan assets	(178)	(175)	(155)
Amortization of actuarial loss	14	20	35
Amortization of past service cost	0	0	2
Amortization of regulatory asset	37	27	23
Amortization of transitional obligation related to regulated business	0	0	0
Settlement charge – regulatory asset	2	0	0
Settlement charge – AOCI	2	0	0
Net Benefit Cost Recognized	107	106	128
Pre-tax amounts recognized in AOCI
Net loss	273	270	247
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	19
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to OCI	(18)	(20)	(34)
Amortization of prior service costs from AOCI to OCI	0	0	(2)
Curtailment	(14)	0	0
Settlement	(11)	0	0
Funded status adjustment	46	43	(67)
Total pre-tax amounts recognized in OCI	3	CAD 23	CAD (103)
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	7
Estimated future benefit payments, which reflect expected future service
2,018	19
2,019	20
2,020	20
2,021	20
2,022	20
2023 to 2027	CAD 98
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	3.70%	4.15%
Rate of compensation increase	0.00%	0.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	4.15%	4.30%	4.20%
Expected long-term rate of return on plan assets	6.05%	5.95%	4.60%
Rate of compensation increase	0.00%	0.00%	0.00%
Net benefit cost
Service cost	CAD 4	CAD 3	CAD 3
Interest cost	14	13	10
Expected return on plan assets	(21)	(11)	(2)
Amortization of actuarial loss	1	2	3
Amortization of past service cost	0	0	1
Amortization of regulatory asset	1	1	1
Amortization of transitional obligation related to regulated business	0	2	2
Settlement charge – regulatory asset	0	0	0
Settlement charge – AOCI	0	0	0
Net Benefit Cost Recognized	(1)	10	18
Pre-tax amounts recognized in AOCI
Net loss	11	21	28
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	1
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to OCI	(1)	(2)	(4)
Amortization of prior service costs from AOCI to OCI	0	0	(1)
Curtailment	(2)	0	0
Settlement	0	0	0
Funded status adjustment	(7)	(5)	(7)
Total pre-tax amounts recognized in OCI	CAD (10)	CAD (7)	CAD (12)

RISK MANAGEMENT AND FINANCIA117

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Derivative [Line Items]
Fair Value	CAD (54)	CAD (428)
Designated as a net investment hedge
Derivative [Line Items]
Fair Value	(194)	(432)
Designated as a net investment hedge | US$ denominated
Derivative [Line Items]
Notional or Principal Amount | $			$ 1,700	$ 2,500
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019)
Derivative [Line Items]
Fair Value	(199)	(425)
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019) | US$ denominated
Derivative [Line Items]
Notional or Principal Amount | $			1,200	2,350
Net realized gains related to the interest component	4	6
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2018)
Derivative [Line Items]
Fair Value	5	0
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2018) | US$ denominated
Derivative [Line Items]
Notional or Principal Amount | $			500	0
Designated as a net investment hedge | U.S. dollar foreign exchange forward contracts
Derivative [Line Items]
Fair Value	CAD 0	CAD (7)
Designated as a net investment hedge | U.S. dollar foreign exchange forward contracts | US$ denominated
Derivative [Line Items]
Notional or Principal Amount | $			$ 0	$ 150

RISK MANAGEMENT AND FINANCIA118

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge CAD in Millions, $ in Millions	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)
Derivative [Line Items]
Notional amount | CAD	CAD 25,400		CAD 26,600
Fair value | CAD	CAD 28,900		CAD 29,400
US$ denominated
Derivative [Line Items]
Notional amount | $		$ 20,200		$ 19,800
Fair value | $		$ 23,100		$ 21,900

RISK MANAGEMENT AND FINANCIA119

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)
Concentration Risk [Line Items]
Financing receivable, recorded investment, past due	CAD 0
Provision for other credit losses	0
Customer Concentration Risk
Concentration Risk [Line Items]
Credit risk concentration	CAD 0	CAD 200	$ 149

RISK MANAGEMENT AND FINANCIA120

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion (Note 17)	CAD (34,677)	CAD (40,048)
Junior subordinated notes (Note 18)	(7,007)	(3,931)
Long-term debt | $			$ 1,100	$ 850
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Fair value adjustments - gains (losses)	4	2
Long-term debt hedged | $			$ 1,100	$ 850
Level II | Carrying Amount
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion (Note 17)	(34,741)	(40,150)
Junior subordinated notes (Note 18)	(7,007)	(3,931)
Total liabilities	(41,748)	(44,081)
Level II | Fair Value
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion (Note 17)	(40,180)	(45,047)
Junior subordinated notes (Note 18)	(7,233)	(3,825)
Total liabilities	CAD (47,413)	CAD (48,872)

RISK MANAGEMENT AND FINANCIA121

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) MXN in Millions, CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017CADGWhBcfMMBbls	Dec. 31, 2016CADGWhBcfMMBbls	Dec. 31, 2017MXN	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Total Derivatives
Derivative Assets	CAD 405	CAD 509
Derivative Liabilities	(459)	(937)
Total Derivatives	(54)	(428)
Total trading activity
Total Derivatives
Derivative Assets	389	480
Derivative Liabilities	(244)	(486)
Total Derivatives	145	(6)
Cash Flow Hedges
Total Derivatives
Derivative Assets	8	12
Derivative Liabilities	(8)	(1)
Total Derivatives	0	11
Fair Value Hedges
Total Derivatives
Derivative Assets	0	1
Derivative Liabilities	(5)	(2)
Total Derivatives	(5)	(1)
Net Investment Hedges
Total Derivatives
Derivative Assets	8	16
Derivative Liabilities	(202)	(448)
Total Derivatives	(194)	(432)
Commodities | Power
Total Derivatives
Derivative Assets	319	479
Derivative Liabilities	CAD (242)	CAD (448)
Commodities | Power | Not designated as hedging instrument | Purchases
Notional and Maturity Summary
Power (in GWH) | GWh	66,132	86,887
Commodities | Power | Not designated as hedging instrument | Sales
Notional and Maturity Summary
Power (in GWH) | GWh	42,836	58,561
Commodities | Natural Gas | Not designated as hedging instrument | Purchases
Notional and Maturity Summary
Natural gas (in BCF and mmbbls) | Bcf	133	182
Commodities | Natural Gas | Not designated as hedging instrument | Sales
Notional and Maturity Summary
Natural gas (in BCF and mmbbls) | Bcf	135	147
Commodities | Liquids | Not designated as hedging instrument | Purchases
Notional and Maturity Summary
Natural gas (in BCF and mmbbls) | MMBbls	6	6
Commodities | Liquids | Not designated as hedging instrument | Sales
Notional and Maturity Summary
Natural gas (in BCF and mmbbls) | MMBbls	7	6
Foreign exchange
Total Derivatives
Derivative Assets	CAD 78	CAD 26
Derivative Liabilities	(212)	(486)
Notional and Maturity Summary
Notional or Principal Amount			MXN 100	$ 2,931	$ 2,394
Foreign exchange | Power
Notional and Maturity Summary
Notional or Principal Amount			0	0	0
Foreign exchange | Natural Gas
Notional and Maturity Summary
Notional or Principal Amount			0	0	0
Foreign exchange | Liquids
Notional and Maturity Summary
Notional or Principal Amount			0	0	0
Interest rate
Total Derivatives
Derivative Assets	8	4
Derivative Liabilities	(5)	(3)
Notional and Maturity Summary
Notional or Principal Amount			MXN 0	$ 2,300	$ 1,550
Other current assets
Total Derivatives
Derivative Assets	332	376
Other current assets | Total trading activity
Total Derivatives
Derivative Assets	320	362
Other current assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	4	7
Other current assets | Fair Value Hedges
Total Derivatives
Derivative Assets	0	1
Other current assets | Net Investment Hedges
Total Derivatives
Derivative Assets	8	6
Other current assets | Commodities
Total Derivatives
Derivative Assets	250	357
Other current assets | Commodities | Commodities
Total Derivatives
Derivative Assets	249	351
Other current assets | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Assets	1	6
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	78	16
Other current assets | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Assets	70	10
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	8	6
Other current assets | Interest rate
Total Derivatives
Derivative Assets	4	3
Other current assets | Interest rate | Interest rate
Total Derivatives
Derivative Assets	1	1
Other current assets | Interest rate | Cash Flow Hedges
Total Derivatives
Derivative Assets	3	1
Other current assets | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Assets	0	1
Other current assets | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Intangible and other assets
Total Derivatives
Derivative Assets	73	133
Intangible and other assets | Total trading activity
Total Derivatives
Derivative Assets	69	118
Intangible and other assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	4	5
Intangible and other assets | Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Intangible and other assets | Net Investment Hedges
Total Derivatives
Derivative Assets	0	10
Intangible and other assets | Commodities
Total Derivatives
Derivative Assets	69	122
Intangible and other assets | Commodities | Commodities
Total Derivatives
Derivative Assets	69	118
Intangible and other assets | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	4
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		10
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		10
Intangible and other assets | Interest rate
Total Derivatives
Derivative Assets	4	1
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	4	1
Intangible and other assets | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Intangible and other assets | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Accounts payable and other
Total Derivatives
Derivative Liabilities	(387)	(607)
Accounts payable and other | Total trading activity
Total Derivatives
Derivative Liabilities	(218)	(368)
Accounts payable and other | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(6)	(1)
Accounts payable and other | Fair Value Hedges
Total Derivatives
Derivative Liabilities	(4)	(1)
Accounts payable and other | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(159)	(237)
Accounts payable and other | Commodities
Total Derivatives
Derivative Liabilities	(214)	(330)
Accounts payable and other | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(208)	(330)
Accounts payable and other | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(6)	0
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	(169)	(275)
Accounts payable and other | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Liabilities	(10)	(38)
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	(159)	(237)
Accounts payable and other | Interest rate
Total Derivatives
Derivative Liabilities	(4)	(2)
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	(1)
Accounts payable and other | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Liabilities	(4)	(1)
Accounts payable and other | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities
Total Derivatives
Derivative Liabilities	(72)	(330)
Other long-term liabilities | Total trading activity
Total Derivatives
Derivative Liabilities	(26)	(118)
Other long-term liabilities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(2)	0
Other long-term liabilities | Fair Value Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Other long-term liabilities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(43)	(211)
Other long-term liabilities | Commodities
Total Derivatives
Derivative Liabilities	(28)	(118)
Other long-term liabilities | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(26)	(118)
Other long-term liabilities | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(2)	0
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	(43)	(211)
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	(43)	(211)
Other long-term liabilities | Interest rate
Total Derivatives
Derivative Liabilities	(1)	(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	0	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 (losses)/gains in the year ended December 31	(3)	(28)
Net realized (losses)/gains in the year ended December 31	(1)	0
Other Restricted Investments
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized (losses)/gains in the year ended December 31	1	(1)
Net realized (losses)/gains in the year ended December 31	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)	14	9
Fixed income securities (maturing after 10 years)	790	513
Fixed income securities	804	522
Fixed income securities | Other Restricted Investments
Fair value
Fixed income securities (maturing within 1 year)	23	19
Fixed income securities (maturing within 1-5 years)	107	117
Fixed income securities (maturing within 5-10 years)	0	0
Fixed income securities (maturing after 10 years)	0	0
Fixed income securities	CAD 130	CAD 136

RISK MANAGEMENT AND FINANCIA122

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses)/Gains (Details) - CAD	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commodities
Derivative [Line Items]
Amount of unrealized gains/(losses) in the year	CAD 62,000,000	CAD 123,000,000	CAD (37,000,000)
Amount of realized (losses)/gains in the year	(107,000,000)	(204,000,000)	(151,000,000)
Commodities | Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized gains/(losses) in the year	23,000,000	(167,000,000)	(179,000,000)
Foreign exchange
Derivative [Line Items]
Amount of unrealized gains/(losses) in the year	88,000,000	25,000,000	(21,000,000)
Amount of realized (losses)/gains in the year	18,000,000	62,000,000	(112,000,000)
Foreign exchange | Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized gains/(losses) in the year	5,000,000	(101,000,000)	0
Interest rate
Derivative [Line Items]
Amount of unrealized gains/(losses) in the year	(1,000,000)	0	0
Amount of realized (losses)/gains in the year	1,000,000	0	0
Interest rate | Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized gains/(losses) in the year	1,000,000	4,000,000	CAD 8,000,000
U.S. Northeast Merchant Power Assets
Derivative [Line Items]
Gain (loss) on cash flow hedge	CAD 0
Loss on cash flow hedge		CAD 42,000,000

RISK MANAGEMENT AND FINANCIA123

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - CAD	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Components of OCI related to derivatives
Components of fair value hedge ineffectiveness, amounts excluded from assessment of hedge effectiveness, amount	CAD 0	CAD 0
Cash Flow Hedges
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	3,000,000	44,000,000	CAD (92,000,000)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion)	(3,000,000)	71,000,000	144,000,000
Cash Flow Hedges | Commodities | Power
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	(1,000,000)	39,000,000	(92,000,000)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion)	(20,000,000)	57,000,000	128,000,000
Cash Flow Hedges | Interest rate
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	4,000,000	5,000,000	0
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion)	CAD 17,000,000	CAD 14,000,000	CAD 16,000,000

RISK MANAGEMENT AND FINANCIA124

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD	Dec. 31, 2017	Dec. 31, 2016
Derivative – Asset
Gross Derivative Instruments Presented on the Balance Sheet	CAD 405,000,000	CAD 509,000,000
Amounts Available for Offset	(255,000,000)	(389,000,000)
Net Amounts	150,000,000	120,000,000
Derivative – Liability
Gross Derivative Instruments Presented on the Balance Sheet	(459,000,000)	(937,000,000)
Amounts Available for Offset	255,000,000	389,000,000
Net Amounts	(204,000,000)	(548,000,000)
Cash collateral provided by the Company	165,000,000	305,000,000
Letters of credit provided by the Company	30,000,000	27,000,000
Cash collateral received by the Company	0	0
Letters of credit received by the Company	3,000,000	3,000,000
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	2,000,000	19,000,000
Derivative liability, fair value of collateral	0	0
Additional collateral required if credit-risk-related contingent features were triggered	2,000,000	19,000,000
Foreign exchange
Derivative – Asset
Gross Derivative Instruments Presented on the Balance Sheet	78,000,000	26,000,000
Amounts Available for Offset	(56,000,000)	(26,000,000)
Net Amounts	22,000,000	0
Derivative – Liability
Gross Derivative Instruments Presented on the Balance Sheet	(212,000,000)	(486,000,000)
Amounts Available for Offset	56,000,000	26,000,000
Net Amounts	(156,000,000)	(460,000,000)
Interest rate
Derivative – Asset
Gross Derivative Instruments Presented on the Balance Sheet	8,000,000	4,000,000
Amounts Available for Offset	(1,000,000)	(1,000,000)
Net Amounts	7,000,000	3,000,000
Derivative – Liability
Gross Derivative Instruments Presented on the Balance Sheet	(5,000,000)	(3,000,000)
Amounts Available for Offset	1,000,000	1,000,000
Net Amounts	(4,000,000)	(2,000,000)
Power | Commodities
Derivative – Asset
Gross Derivative Instruments Presented on the Balance Sheet	319,000,000	479,000,000
Amounts Available for Offset	(198,000,000)	(362,000,000)
Net Amounts	121,000,000	117,000,000
Derivative – Liability
Gross Derivative Instruments Presented on the Balance Sheet	(242,000,000)	(448,000,000)
Amounts Available for Offset	198,000,000	362,000,000
Net Amounts	CAD (44,000,000)	CAD (86,000,000)

RISK MANAGEMENT AND FINANCIA125

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value Hierarchy
Derivative Instrument Assets:	CAD 405	CAD 509
Derivative Instrument Liabilities:	(459)	(937)
Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets:	319	479
Derivative Instrument Liabilities:	(242)	(448)
Foreign exchange contracts
Fair Value Hierarchy
Derivative Instrument Assets:	78	26
Derivative Instrument Liabilities:	(212)	(486)
Interest rate
Fair Value Hierarchy
Derivative Instrument Assets:	8	4
Derivative Instrument Liabilities:	(5)	(3)
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	(54)	(428)
Recurring basis | Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets:	319	479
Derivative Instrument Liabilities:	(242)	(448)
Recurring basis | Foreign exchange contracts
Fair Value Hierarchy
Derivative Instrument Assets:	78	26
Derivative Instrument Liabilities:	(212)	(486)
Recurring basis | Interest rate
Fair Value Hierarchy
Derivative Instrument Assets:	8	4
Derivative Instrument Liabilities:	(5)	(3)
Recurring basis | Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	(6)	32
Recurring basis | Quoted Prices in Active Markets (Level I) | Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets:	21	134
Derivative Instrument Liabilities:	(27)	(102)
Recurring basis | Quoted Prices in Active Markets (Level I) | Foreign exchange contracts
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	(41)	(476)
Recurring basis | Significant Other Observable Inputs (Level II) | Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets:	283	326
Derivative Instrument Liabilities:	(193)	(343)
Recurring basis | Significant Other Observable Inputs (Level II) | Foreign exchange contracts
Fair Value Hierarchy
Derivative Instrument Assets:	78	26
Derivative Instrument Liabilities:	(212)	(486)
Recurring basis | Significant Other Observable Inputs (Level II) | Interest rate
Fair Value Hierarchy
Derivative Instrument Assets:	8	4
Derivative Instrument Liabilities:	(5)	(3)
Recurring basis | Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	(7)	16
Recurring basis | Significant Unobservable Inputs (Level III) | Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets:	15	19
Derivative Instrument Liabilities:	(22)	(3)
Recurring basis | Significant Unobservable Inputs (Level III) | Foreign exchange contracts
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:	CAD 0	CAD 0

RISK MANAGEMENT AND FINANCIA126

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Energy Revenue
Net change in the Level III fair value category
Revenues include unrealized gains (loss) attributed to derivatives in the Level III category	CAD (7)	CAD 7
Commodity contract | Power
Net change in the Level III fair value category
Balance at beginning of year	16	9
Transfers out of Level III	(19)	(1)
Total (losses)/gains included in Net income	(17)	13
Sales	(5)	(3)
Settlements	18	(2)
Balance at end of year	(7)	CAD 16
Commodity contract | 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	CAD 2

CHANGES IN OPERATING WORKING127

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CHANGES IN OPERATING WORKING CAPITAL
Increase in Accounts receivable	CAD (576)	CAD (482)	CAD (65)
Increase in Inventories	(38)	(87)	(3)
Decrease/(increase) in Assets held for sale	14	(13)	0
Decrease/(increase) in Other current assets	189	328	(272)
Increase/(decrease) in Accounts payable and other	151	424	(97)
Increase in Accrued interest	12	62	91
(Decrease)/increase in Liabilities related to assets held for sale	(25)	16	0
(Increase)/decrease in Operating Working Capital	CAD (273)	CAD 248	CAD (346)

OTHER ACQUISITIONS AND DISPO128

OTHER ACQUISITIONS AND DISPOSITIONS (Details) CAD in Millions, $ in Millions

Dec. 19, 2017CAD

Jun. 01, 2017USD ($)

Apr. 19, 2017USD ($)

May 01, 2016USD ($)

Mar. 31, 2016CAD

Mar. 31, 2016USD ($)

Feb. 29, 2016USD ($)

Jan. 31, 2016USD ($)

Dec. 31, 2015CAD

Apr. 30, 2015USD ($)

Dec. 31, 2017CAD

Dec. 31, 2016CAD

Dec. 31, 2015CAD

Jun. 02, 2017

Nov. 30, 2015

Business Acquisition [Line Items]

Contributions to equity investments

CAD 1,681

CAD 765

CAD 493

Gain (loss) on disposal

631

(833)

(125)

Proceeds from sale of assets, net of transaction costs

CAD 5,317

6

CAD 0

Natural Gas – Ironwood

Business Acquisition [Line Items]

Purchase price | $

$ 653

Iroquois

Business Acquisition [Line Items]

Ownership interest (percent)

50.00%

49.35%

49.35%

Additional ownership acquired (percent)

0.65%

4.87%

4.87%

Contributions to equity investments | $

$ 7

$ 54

Iroquois | U.S. Natural Gas Pipelines

Business Acquisition [Line Items]

Ownership interest (percent)

50.00%

50.00%

0.66%

Iroquois | Disposal group, disposed of by sale, not discontinued operations

Business Acquisition [Line Items]

Ownership interest before transaction, percent

49.34%

PNGTS | Disposal group, disposed of by sale, not discontinued operations

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

Gas Transmission Northwest | Disposal group, disposed of by sale, not discontinued operations | Natural Gas

Business Acquisition [Line Items]

Ownership interest before transaction, percent

30.00%

Total consideration | $

$ 457

Cash received | $

264

Assumption of debt by purchaser | $

98

Gas Transmission Northwest | Disposal group, disposed of by sale, not discontinued operations | Natural Gas | Class B units

Business Acquisition [Line Items]

Receipt of new units | $

$ 95

Ontario Solar Assets

Business Acquisition [Line Items]

Proceeds from sale of assets, net of transaction costs

CAD 541

Gain (loss) on disposition of property plant equipment

127

Gain (loss) on disposition of property plant equipment, net of tax

CAD 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

CAD 715

Gain (loss) on disposition of property plant equipment, net of tax

440

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

CAD 2

CAD 70

Bruce B

Business Acquisition [Line Items]

Ownership interest (percent)

46.50%

46.50%

31.60%

Additional ownership acquired (percent)

14.89%

14.89%

Contributions to equity investments

CAD 236

Bruce Power

Business Acquisition [Line Items]

Ownership interest (percent)

48.50%

48.50%

Bruce A

Business Acquisition [Line Items]

Ownership interest (percent)

48.90%

PNGTS And Iroquois Transmission systems | Disposal group, disposed of by sale, not discontinued operations

Business Acquisition [Line Items]

Total consideration | $

$ 765

Cash received | $

597

Assumption of debt by purchaser | $

$ 168

TC Offshore LLC | Disposal group, not discontinued operations

Business Acquisition [Line Items]

Gain (loss) on disposal

CAD (4)

CAD (125)

COMMITMENTS, CONTINGENCIES A129

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Operating Leases (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Minimum Lease Payments
2,018	CAD 75
2,019	76
2,020	73
2,021	71
2,022	63
2023 and thereafter	443
Minimum Lease Payments	801
Amounts Recoverable under Subleases
2,018	4
2,019	2
2,020	2
2,021	1
2,022	0
2023 and thereafter	2
Amounts Recoverable under Subleases	11
Net Payments
2,018	71
2,019	74
2,020	71
2,021	70
2,022	63
2023 and thereafter	441
Net Payments	790
Rent Expense
Net rental expense on operating leases	CAD 93	CAD 145	CAD 131
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 A130

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Other Commitments and Contingencies (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites	CAD 34	CAD 39
Canadian Natural Gas Pipelines | Capital expenditures
Other Commitments
Commitment for capital expenditures	300
U.S. Natural Gas Pipelines | Capital expenditures
Other Commitments
Commitment for capital expenditures	400
Mexico Natural Gas Pipelines | Capital expenditures
Other Commitments
Commitment for capital expenditures	700
Liquids Pipelines | Capital expenditures
Other Commitments
Commitment for capital expenditures	100
Energy | Capital expenditures
Other Commitments
Commitment for capital expenditures	400
Corporate | Capital expenditures
Other Commitments
Commitment for capital expenditures	CAD 100

COMMITMENTS, CONTINGENCIES A131

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Guarantees
Potential Exposure	CAD 507	CAD 980
Carrying Value	16	82
Sur de Texas
Guarantees
Potential Exposure	315	805
Carrying Value	2	53
Bruce Power
Guarantees
Potential Exposure	88	88
Carrying Value	1	1
Other jointly owned entities
Guarantees
Potential Exposure	104	87
Carrying Value	CAD 13	CAD 28

CORPORATE RESTRUCTURING COST132

CORPORATE RESTRUCTURING COSTS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restructuring Cost and Reserve [Line Items]
Provision recorded for restructuring charges	CAD 62	CAD 99	CAD 87
Total corporate restructuring charges	6	44
Restructuring and related activities, costs capitalized			8
Employee Severance
Restructuring Cost and Reserve [Line Items]
Corporate restructuring costs incurred			122
Provision recorded for restructuring charges	9	36	60
Total corporate restructuring charges	0	0	209
Restructuring costs recoverable through regulatory and tolling structures			58
Cumulative restructuring costs incurred	86
Employee Severance | Regulatory asset
Restructuring Cost and Reserve [Line Items]
Total corporate restructuring charges	3	22	44
Employee Severance | Plant operating cost and other
Restructuring Cost and Reserve [Line Items]
Total corporate restructuring charges	3	22	CAD 157
Lease Commitments
Restructuring Cost and Reserve [Line Items]
Total corporate restructuring charges	6	CAD 44
Cumulative restructuring costs incurred	CAD 38

CORPORATE RESTRUCTURING COSTS -

CORPORATE RESTRUCTURING COSTS - Schedule of Change In Restructuring Liability (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restructuring Reserve [Roll Forward]
Restructuring liability as at the beginning of period	CAD 99	CAD 87
Restructuring charges	6	44
Cash payments	(43)	(32)
Restructuring Liability as at the end of period	62	99	CAD 87
Employee Severance
Restructuring Reserve [Roll Forward]
Restructuring liability as at the beginning of period	36	60
Restructuring charges	0	0	209
Cash payments	(27)	(24)
Restructuring Liability as at the end of period	9	36	60
Lease Commitments
Restructuring Reserve [Roll Forward]
Restructuring liability as at the beginning of period	63	27
Restructuring charges	6	44
Cash payments	(16)	(8)
Restructuring Liability as at the end of period	CAD 53	CAD 63	CAD 27

VARIABLE INTEREST ENTITIES (Det

VARIABLE INTEREST ENTITIES (Details)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable interest entity ownership percentage	100.00%

VARIABLE INTEREST ENTITIES - As

VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	CAD 1,089	CAD 1,016	CAD 850	CAD 489
Accounts receivable	2,522	2,075
Inventories	378	368
Other	691	908
Total Current Assets	4,680	8,084
Plant, Property and Equipment	57,277	54,475
Equity Investments	6,366	6,544
Goodwill	13,084	13,958	CAD 4,812
Total Assets	86,101	88,051
Current Liabilities
Accounts payable and other	4,057	3,861
Accrued interest	605	595
Current portion of long-term debt	2,866	1,838
Total Current Liabilities	9,877	7,680
Total Regulatory Liabilities	4,321	2,121
Other Long-Term Liabilities (Note 15)	727	1,183
Deferred Income Tax Liabilities	5,403	7,662
Long-Term Debt	31,875	38,312
Total Liabilities	59,210	60,889
Variable Interest Entity, Primary Beneficiary
Current Assets
Cash and cash equivalents	41	77
Accounts receivable	63	71
Inventories	23	25
Other	11	10
Total Current Assets	138	183
Plant, Property and Equipment	3,535	3,685
Equity Investments	917	606
Goodwill	490	525
Intangible and Other Assets	3	1
Total Assets	5,083	5,000
Current Liabilities
Accounts payable and other	137	80
Dividends payable	1	0
Accrued interest	23	21
Current portion of long-term debt	88	76
Total Current Liabilities	249	177
Total Regulatory Liabilities	34	34
Other Long-Term Liabilities (Note 15)	3	4
Deferred Income Tax Liabilities	13	7
Long-Term Debt	3,244	2,827
Total Liabilities	CAD 3,543	CAD 3,049

VARIABLE INTEREST ENTITIES - Ca

VARIABLE INTEREST ENTITIES - Carrying Value of VIEs and Maximum Exposure (Details) - Variable Interest Entity, Not Primary Beneficiary - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Balance sheet
Equity investments	CAD 4,372	CAD 4,964
Off-balance sheet
Potential exposure to guarantees	171	163
Maximum exposure to loss	CAD 4,543	CAD 5,127