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Document and Entity Information	12 Months Ended
Document and Entity Information	Dec. 31, 2015 shares
Document and Entity Information
Entity Registrant Name	TRANSCANADA CORP
Entity Central Index Key	0001232384
Document Type	40-F
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding	702,614,096
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENT OF INCOME - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Natural Gas Pipelines	$ 5,383	$ 4,913	$ 4,497
Liquids Pipelines	1,879	1,547	1,124
Energy	4,038	3,725	3,176
Total Revenues	11,300	10,185	8,797
Income from Equity Investments (Note 8)	440	522	597
Operating and Other Expenses
Plant operating costs and other	3,250	2,973	2,674
Commodity purchases resold	2,237	1,836	1,317
Property taxes	517	473	445
Depreciation and amortization	1,765	1,611	1,485
Asset impairment charges (Note 7)	3,745	0	0
Total Operating and Other Expenses	11,514	6,893	5,921
(Loss)/Gain on Assets Held for Sale/Sold (Notes 6 and 25)	(125)	117	0
Financial Charges
Interest expense (Note 16)	1,370	1,198	985
Interest income and other	(163)	(91)	(34)
Total Financial Charges/(Income)	1,207	1,107	951
(Loss)/Income before Income Taxes	(1,106)	2,824	2,522
Income Tax Expense/(Recovery) (Note 15)
Current	136	145	43
Deferred	(102)	686	568
Total Income Tax Expense/(Recovery)	34	831	611
Net (Loss)/Income	(1,140)	1,993	1,911
Net Income attributable to non-controlling interests (Note 18)	6	153	125
Net (Loss)/Income Attributable to Controlling Interests	(1,146)	1,840	1,786
Preferred share dividends	94	97	74
Net (Loss)/Income Attributable to Common Shares	$ (1,240)	$ 1,743	$ 1,712
Net (Loss)/Income per Common Share (Note 19)
Basic and diluted (in dollars per share)	$ (1.75)	$ 2.46	$ 2.42
Dividends Declared per Common Share (in dollars per share)	$ 2.08	$ 1.92	$ 1.84
Weighted Average Number of Common Shares (millions) (Note 19)
Basic (in shares)	709	708	707
Diluted (in shares)	709	710	708

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net (Loss)/Income	$ (1,140)	$ 1,993	$ 1,911
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains on net investment in foreign operations	813	517	383
Change in fair value of net investment hedges	(372)	(276)	(239)
Change in fair value of cash flow hedges	(57)	(69)	71
Reclassification to net income of gains and losses on cash flow hedges	88	(55)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	51	(102)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	32	18	23
Other comprehensive income/(loss) on equity investments	47	(204)	234
Other comprehensive income/(loss) (Note 21)	602	(171)	580
Comprehensive (Loss)/Income	(538)	1,822	2,491
Comprehensive income attributable to non-controlling interests	312	283	191
Comprehensive (Loss)/Income Attributable to Controlling Interests	(850)	1,539	2,300
Preferred share dividends	94	97	74
Comprehensive (Loss)/Income Attributable to Common Shares	$ (944)	$ 1,442	$ 2,226

CONSOLIDATED STATEMENT OF CASH FLOWS - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Generated from Operations
Net (Loss)/Income	$ (1,140)	$ 1,993	$ 1,911
Depreciation and amortization	1,765	1,611	1,485
Asset impairment charges (Note 7)	3,745	0	0
Deferred income taxes (Note 15)	(102)	686	568
Income from equity investments (Note 8)	(440)	(522)	(597)
Distributed earnings received from equity investments (Note 8)	576	579	605
Employee post-retirement benefits expense, net of funding (Note 22)	44	37	50
Loss/(gain) on assets held for sale/sold (Notes 6 and 25)	125	(117)	0
Equity allowance for funds used during construction	(165)	(95)	(19)
Unrealized losses/(gains) on financial instruments	58	74	(35)
Other	47	22	32
Increase in operating working capital (Note 24)	(398)	(189)	(326)
Net cash provided by operations	4,115	4,079	3,674
Investing Activities
Capital expenditures (Note 4)	(3,918)	(3,489)	(4,264)
Capital projects in development (Note 4)	(511)	(848)	(488)
Contributions to equity investments (Note 8)	(493)	(256)	(163)
Acquisitions, net of cash acquired (Note 25)	(236)	(241)	(216)
Proceeds from sale of assets, net of transaction costs (Note 25)	0	196	0
Distributions in excess of equity earnings (Note 8)	226	159	128
Deferred amounts and other	322	335	(117)
Net cash used in investing activities	(4,610)	(4,144)	(5,120)
Financing Activities
Notes payable (repaid)/issued, net	(1,382)	544	(492)
Long-term debt issued, net of issue costs	5,045	1,403	4,253
Long-term debt repaid	(2,105)	(1,069)	(1,286)
Junior subordinated notes issued, net of issue costs	917	0	0
Dividends on common shares	(1,446)	(1,345)	(1,285)
Dividends on preferred shares	(92)	(94)	(71)
Distributions paid to non-controlling interests	(224)	(178)	(166)
Common shares issued	27	47	72
Common shares repurchased (Note 19)	(294)	0	0
Preferred shares issued, net of issue costs (Note 20)	243	440	585
Partnership units of subsidiary issued, net of issue costs	55	79	384
Preferred shares of subsidiary redeemed (Note 18)	0	(200)	(200)
Net cash provided by/(used in) financing activities	744	(373)	1,794
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	112	0	28
Increase/(Decrease) in Cash and Cash Equivalents	361	(438)	376
Cash and Cash Equivalents, Beginning of year	489	927	551
Cash and Cash Equivalents, End of year	$ 850	$ 489	$ 927

CONSOLIDATED BALANCE SHEET - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 850	$ 489
Accounts receivable	1,388	1,313
Inventories	323	292
Other (Note 5)	1,353	1,019
Total Current Assets	3,914	3,113
Plant, Property and Equipment (Note 7)	44,817	41,774
Equity Investments (Note 8)	6,214	5,598
Regulatory Assets (Note 9)	1,184	1,297
Goodwill (Note 10)	4,812	4,034
Intangible and Other Assets (Note 11)	3,191	2,646
Restricted Investments	351	63
Total Assets	64,483	58,525
Current Liabilities
Notes payable (Note 12)	1,218	2,467
Accounts payable and other (Note 13)	3,021	2,892
Accrued interest	520	424
Current portion of long-term debt (Note 16)	2,547	1,797
Total Current Liabilities	7,306	7,580
Regulatory Liabilities (Note 9)	1,159	263
Other Long-Term Liabilities (Note 14)	1,260	1,052
Deferred Income Tax Liabilities (Note 15)	5,144	4,857
Long-Term Debt (Note 16)	29,037	22,960
Junior Subordinated Notes (Note 17)	2,422	1,160
Total Liabilities	46,328	37,872
EQUITY
Common shares, no par value (Note 19); Issued and outstanding: December 31, 2015 703 million shares; December 31, 2014 - 709 million shares	12,102	12,202
Preferred shares (Note 20)	2,499	2,255
Additional paid-in capital	7	370
Retained earnings	2,769	5,478
Accumulated other comprehensive loss (Note 21)	(939)	(1,235)
Controlling interests	16,438	19,070
Non-controlling interests (Note 18)	1,717	1,583
Total Equity	18,155	20,653
Total Liabilities and Equity	$ 64,483	$ 58,525

CONSOLIDATED BALANCE SHEET (Parenthetical) - shares shares in Millions	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common shares issued (in shares)	703	709
Common shares outstanding (in shares)	703	709

CONSOLIDATED STATEMENT OF EQUITY - CAD ($) $ in Millions	Total	Equity Attributable to Controlling Interests	Common Shares	Preferred Shares	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Equity Attributable to Non-Controlling Interests
Beginning balance at Dec. 31, 2012			$ 12,069	$ 1,224	$ 379	$ 4,687	$ (1,448)
Increase (decrease) in equity
Shares issued on exercise of stock options (Note 19)			80
Shares repurchased (Note 19)			0		0
Shares issued under public offering, net of issue costs (Note 20)				589
Issuance of stock options, net of exercises					(2)
Dilution impact from TC PipeLines, LP units issued					29			$ 384
Redemption of subsidiary's preferred shares					(5)			(195)
Impact of asset drop downs to TC PipeLines, LP (Note 25)					0
Net (loss)/income attributable to controlling interests	$ 1,786					1,786
Common share dividends						(1,301)
Preferred share dividends						(76)
Other comprehensive income/(loss) (Note 21)	580						514
Ending balance at Dec. 31, 2013		$ 18,525	12,149	1,813	401	5,096	(934)
Beginning balance at Dec. 31, 2012								1,425
Net (loss)/income attributable to non-controlling interests
TC PipeLines, LP								93
Portland Natural Gas Transmission System	125							12
Preferred share dividends of TCPL								20
Other comprehensive income attributable to non-controlling interests								66
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					29			384
Decrease in TransCanada's ownership of TC PipeLines, LP								(47)
Distributions declared to non-controlling interests								(166)
Redemption of subsidiary's preferred shares					(5)			(195)
Other								19
Ending balance at Dec. 31, 2013								1,611
Issuance of TC PipeLines, LP units
Total Equity	20,136
Shares issued on exercise of stock options (Note 19)			53
Shares repurchased (Note 19)			0		0
Shares issued under public offering, net of issue costs (Note 20)				442
Issuance of stock options, net of exercises					3
Dilution impact from TC PipeLines, LP units issued					9			79
Redemption of subsidiary's preferred shares					(6)			(194)
Impact of asset drop downs to TC PipeLines, LP (Note 25)					(37)
Net (loss)/income attributable to controlling interests	1,840					1,840
Common share dividends						(1,360)
Preferred share dividends						(98)
Other comprehensive income/(loss) (Note 21)	(171)						(301)
Ending balance at Dec. 31, 2014	19,070	19,070	12,202	2,255	370	5,478	(1,235)
Net (loss)/income attributable to non-controlling interests
TC PipeLines, LP								136
Portland Natural Gas Transmission System	153							15
Preferred share dividends of TCPL								2
Other comprehensive income attributable to non-controlling interests								130
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					9			79
Decrease in TransCanada's ownership of TC PipeLines, LP								(14)
Distributions declared to non-controlling interests								(182)
Redemption of subsidiary's preferred shares					(6)			(194)
Other								0
Ending balance at Dec. 31, 2014	1,583							1,583
Issuance of TC PipeLines, LP units
Total Equity	20,653
Shares issued on exercise of stock options (Note 19)			30
Shares repurchased (Note 19)			(130)		(164)
Shares issued under public offering, net of issue costs (Note 20)				244
Issuance of stock options, net of exercises					8
Dilution impact from TC PipeLines, LP units issued					6			55
Redemption of subsidiary's preferred shares					0			0
Impact of asset drop downs to TC PipeLines, LP (Note 25)					(213)
Net (loss)/income attributable to controlling interests	(1,146)					(1,146)
Common share dividends						(1,471)
Preferred share dividends						(92)
Other comprehensive income/(loss) (Note 21)	602						296
Ending balance at Dec. 31, 2015	16,438	$ 16,438	$ 12,102	$ 2,499	7	$ 2,769	$ (939)
Net (loss)/income attributable to non-controlling interests
TC PipeLines, LP								(13)
Portland Natural Gas Transmission System	6							19
Preferred share dividends of TCPL								0
Other comprehensive 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)
Redemption of subsidiary's preferred shares					$ 0			0
Other								0
Ending balance at Dec. 31, 2015	1,717							$ 1,717
Issuance of TC PipeLines, LP units
Total Equity	$ 18,155

DESCRIPTION OF TRANSCANADA'S BUSINESS	12 Months Ended
DESCRIPTION OF TRANSCANADA'S BUSINESS	Dec. 31, 2015
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 three business segments, Natural Gas Pipelines, Liquids Pipelines and Energy, each of which offers different products and services. Natural Gas Pipelines The Natural Gas Pipelines segment consists of the Company's investments in 67,300 km (41,900 miles) of regulated natural gas pipelines and 250 Bcf of regulated natural gas storage facilities. These assets are located in Canada, the United States (U.S.) and Mexico. Liquids Pipelines The Liquids Pipelines segment consists of 4,247 km (2,639 miles) of wholly-owned and operated 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 19 electrical power generation plants and 2 non-regulated natural gas storage facilities. These include Canadian plants in Alberta, Ontario, Québec and New Brunswick and U.S. plants in New York, New England and Arizona.

ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

ACCOUNTING POLICIES

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

Basis of Presentation

The consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. 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 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 and depreciation rates of plant, property and equipment (Note 7);


•	carrying value of regulatory assets and liabilities (Note 9);


•	fair value of goodwill (Note 10);


•	amortization rates and fair value of intangible assets (Note 11);


•	carrying value of asset retirement obligations (Note 14);


•	provisions for income taxes (Note 15);


•	assumptions used to measure retirement and other post-retirement obligations (Note 22);


•	fair value of financial instruments (Note 23); and


•	provision for commitments, contingencies and guarantees (Note 26).

Actual results could differ from those estimates.

Regulation

In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB). In the U.S., 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, natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). The Company's Canadian, U.S. and Mexican natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls. 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 expected 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 Mexican natural gas pipelines, regulated U.S. natural gas storage and certain of its liquids pipelines projects. RRA is not applicable to the Keystone Pipeline System as the regulators' decisions regarding operations and tolls on that system generally do not have an impact on timing of recognition of revenues and expenses.

Revenue Recognition

Natural Gas Pipelines and Liquids Pipelines

Revenues from the Company's natural gas and liquids pipelines, with the exception of Canadian natural gas pipelines which are subject to RRA, 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 rates 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 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 are at times 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 are recognized on firm contracted capacity 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 ROE assumptions. Adjustments to revenue 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 regulated natural gas storage services are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored and when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the gas or oil that it transports or stores for others.

Energy

Power

Revenues from the Company's Energy business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are 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 section of this note.

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 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 materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are carried at the lower of weighted average cost or market.

Plant, Property and Equipment

Natural Gas Pipelines

Plant, property and equipment for natural gas pipelines are 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 and the equity component of AFUDC is a non-cash expenditure with a corresponding credit recognized in Interest income and other expense in the Consolidated statement of income. Interest is capitalized during construction of non-regulated natural gas pipelines.

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 from service, net of any salvage proceeds, are also recorded in accumulated depreciation.

Liquids Pipelines

Plant, property and equipment for liquids pipelines are 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 major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of these assets includes interest capitalized during construction for non-regulated liquids pipelines and AFUDC for regulated pipelines. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings.

Energy

Power generation and natural gas storage plant, equipment and structures 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 and amortization are derecognized and any gain or loss is recorded in earnings.

Corporate

Corporate Plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent.

Capitalized Project Costs

The Company capitalizes project costs once advancement to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest for non-regulated projects in development and AFUDC for regulated projects. Capital projects in development are included in Intangible and other assets. 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 depreciation policies.

Project costs related to acquisitions are capitalized once the acquisition is probable.

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, reduced for selling costs, and any losses are recognized in income. Depreciation expense is no longer recorded for any assets that are classified as held for sale.

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 price to sell is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the fair value of the asset.

Acquisitions and Goodwill

The Company accounts for business acquisitions using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair value at the date of acquisition. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that the asset 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 initially assesses qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. If TransCanada 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 the 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 is less than carrying value, an impairment is indicated and a 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.

Power Purchase Arrangements

A power purchase agreement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. Substantially all PPAs under which TransCanada buys power are accounted for as operating leases. Initial payments for these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TransCanada records the margin earned from the subleases as a component of Revenues.

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. Collected funds 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 abandon 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 income in the period during which they occur except for changes in balances related to the Canadian Mainline, NGTL System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

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 expenses.

The Company has recorded ARO related to the non-regulated natural gas storage operations and certain power generation facilities. The scope and timing of asset retirements related to natural gas pipelines, liquids pipelines and hydroelectric power plants 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.

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. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The 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.

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) 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, 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 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. 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 has 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 and are designated for hedge accounting treatment, which 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 expense 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, can be 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

The Company records Long-term debt transaction costs as other assets 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 or 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.

ACCOUNTING CHANGES	12 Months Ended
ACCOUNTING CHANGES	Dec. 31, 2015
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES Changes in Accounting Policies for 2015 Derivatives and Hedging In August 2015, the Financial Accounting Standards Board (FASB) issued new guidance on the application of the normal purchases and normal sales scope exception to certain electricity contracts within nodal energy markets. The amendments in this update apply to entities that enter into contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through or delivery to a location within a nodal energy market whereby one of the contracting parties incurs charges (or credits) for the transmission of that electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. This new guidance was effective upon issuance, was applied prospectively and did not have a material impact on the Company's consolidated financial statements. Balance Sheet Classification of Deferred Taxes In November 2015, the FASB issued new guidance which requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The new guidance is effective January 1, 2017, however, since early application is permitted, the Company elected to retrospectively apply this guidance effective January 1, 2015. Application of this new guidance will simplify the Company’s process in determining deferred tax amounts and simplify their presentation. The application of this amendment resulted in a reclassification of Deferred tax assets previously recorded in Other current assets, and Deferred tax liabilities previously recorded in Accounts payable and other to non-current Deferred income tax assets and liabilities. Prior year amounts have been reclassified to conform to current year presentation. Reporting discontinued operations In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance was applied prospectively from January 1, 2015 and there was no impact on the Company's consolidated financial statements as a result of applying this new standard. Future Accounting Changes Revenue from contracts with customers In 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB deferred the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. 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. Extraordinary and unusual income statement items In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from GAAP the concept of extraordinary items. This new guidance is effective from January 1, 2016 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements. Consolidation In February 2015, the FASB issued new guidance on consolidation analysis. This update requires that entities reevaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance is effective from January 1, 2016 and will be applied retrospectively. 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. Imputation of interest In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance is effective January 1, 2016 and will be applied retrospectively. The application of this amendment will result in a reclassification of debt issuance costs currently recorded in Intangible and other assets to an offset of their respective debt liabilities. Inventory In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify that an entity should measure inventory within the scope of this update 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 is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements. Business Combinations In September 2015, the FASB issued guidance which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements as the adjustment was determined, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

- Definition

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

SEGMENTED INFORMATION

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

SEGMENTED INFORMATION



year ended December 31, 2015	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total

Revenues	5,383		1,879		4,038		—		11,300
Income from equity investments	179		—		261		—		440
Plant operating costs and other	(1,736	)	(478	)	(766	)	(270	)	(3,250	)
Commodity purchases resold	—		—		(2,237	)	—		(2,237	)
Property taxes	(349	)	(79	)	(89	)	—		(517	)
Depreciation and amortization	(1,132	)	(266	)	(336	)	(31	)	(1,765	)
Asset impairment charges	—		(3,686	)	(59	)	—		(3,745	)
Loss on assets held for sale	(125	)	—		—		—		(125	)
Segmented earnings/(losses)	2,220		(2,630	)	812		(301	)	101
Interest expense									(1,370	)
Interest income and other									163
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	2,466		1,012		376		64		3,918
Capital projects in development	233		278		—		—		511
	2,699		1,290		376		64		4,429



year ended December 31, 2014	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total

Revenues	4,913		1,547		3,725		—		10,185
Income from equity investments	163		—		359		—		522
Plant operating costs and other	(1,501	)	(426	)	(919	)	(127	)	(2,973	)
Commodity purchases resold	—		—		(1,836	)	—		(1,836	)
Property taxes	(334	)	(62	)	(77	)	—		(473	)
Depreciation and amortization	(1,063	)	(216	)	(309	)	(23	)	(1,611	)
Gain on assets sold	9		—		108		—		117
Segmented earnings/(losses)	2,187		843		1,051		(150	)	3,931
Interest expense									(1,198	)
Interest income and other									91
Income before income taxes									2,824
Income tax expense									(831	)
Net income									1,993
Net income attributable to non-controlling interests									(153	)
Net income attributable to controlling interests									1,840
Preferred share dividends									(97	)
Net income attributable to common shares									1,743

Capital spending
Capital expenditures	1,768		1,469		206		46		3,489
Capital projects in development	368		480		—		—		848
	2,136		1,949		206		46		4,337



year ended December 31, 2013	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total

Revenues	4,497		1,124		3,176		—		8,797
Income from equity investments	145		—		452		—		597
Plant operating costs and other	(1,405	)	(328	)	(833	)	(108	)	(2,674	)
Commodity purchases resold	—		—		(1,317	)	—		(1,317	)
Property taxes	(329	)	(44	)	(72	)	—		(445	)
Depreciation and amortization	(1,027	)	(149	)	(293	)	(16	)	(1,485	)
Segmented earnings/(losses)	1,881		603		1,113		(124	)	3,473
Interest expense									(985	)
Interest income and other									34
Income before income taxes									2,522
Income tax expense									(611	)
Net income									1,911
Net income attributable to non-controlling interests									(125	)
Net income attributable to controlling interests									1,786
Preferred share dividends									(74	)
Net income attributable to common shares									1,712

Capital spending
Capital expenditures	1,776		2,286		152		50		4,264
Capital projects in development	245		243		—		—		488
	2,021		2,529		152		50		4,752



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Total Assets
Natural Gas Pipelines	31,072	27,103
Liquids Pipelines	16,046	16,116
Energy	15,558	14,197
Corporate	1,807	1,109
	64,483	58,525

Geographic Information



year ended December 31	2015	2014	2013
(millions of Canadian $)	2015	2014	2013

Revenues
Canada – domestic	3,877	3,956	4,659
Canada – export	1,292	1,314	997
United States	5,872	4,718	3,029
Mexico	259	197	112
	11,300	10,185	8,797



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Plant, Property and Equipment
Canada	19,287	19,191
United States	21,899	20,098
Mexico	3,631	2,485
	44,817	41,774

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8981-108599

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+ Details

OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2015

Other Assets [Abstract]

OTHER CURRENT ASSETS



at December 31		2014
(millions of Canadian $)	2015	2014

Cash held as collateral	585	423
Fair value of derivative contracts (Note 23)	442	409
Regulatory assets (Note 9)	85	16
Assets held for sale (Note 6)	20	—
Other	221	171
	1,353	1,019

ASSETS HELD FOR SALE

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

ASSETS HELD FOR SALE

On December 18, 2015, the Company entered into an agreement to sell TC Offshore LLC (TCO) to a third party and expects the sale to close in early 2016. As a result, at December 31, 2015, the related assets and liabilities were held for sale in the Natural Gas Pipelines segment and were recorded at their fair values less costs to sell. This resulted in a loss of $125 million pre-tax in 2015 which is included in (Loss)/gain on assets held for sale/sold in the Consolidated statement of income. TCO is a FERC regulated entity that operates as part of ANR. TCO does not represent a major line of business or geographical area of the Company, and therefore is not considered to be a discontinued operation as of December 31, 2015.



at December 31		2015
(millions of Canadian $)		2015

Assets Held for Sale
Accounts receivable		4
Inventories		1
Other current assets		1
Plant, property and equipment		14
Total Assets Held for Sale (included in Other current assets, Note 5)		20
Liabilities Related to Assets Held for Sale
Accounts payable and other		38
Other long-term liabilities		1
Total Liabilities Related to Assets Held for Sale (included in Accounts payable and other, Note 13)		39

PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

PLANT, PROPERTY AND EQUIPMENT



	2015			2014
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Natural Gas Pipelines
Canadian Mainline
Pipeline	9,164	5,966	3,198	9,045	5,712	3,333
Compression	3,433	2,220	1,213	3,423	2,100	1,323
Metering and other	499	192	307	458	180	278
	13,096	8,378	4,718	12,926	7,992	4,934
Under construction	257	—	257	135	—	135
	13,353	8,378	4,975	13,061	7,992	5,069
NGTL System
Pipeline	8,456	3,820	4,636	8,185	3,619	4,566
Compression	2,188	1,404	784	2,055	1,318	737
Metering and other	1,096	489	607	1,032	446	586
	11,740	5,713	6,027	11,272	5,383	5,889
Under construction	969	—	969	413	—	413
	12,709	5,713	6,996	11,685	5,383	6,302
ANR¹
Pipeline	1,449	350	1,099	1,217	227	990
Compression	1,101	187	914	780	140	640
Metering and other	977	252	725	737	231	506
	3,527	789	2,738	2,734	598	2,136
Under construction	304	—	304	127	—	127
	3,831	789	3,042	2,861	598	2,263
Mexico
Pipeline	1,296	162	1,134	1,053	104	949
Compression	183	14	169	151	6	145
Metering and other	388	27	361	314	20	294
	1,867	203	1,664	1,518	130	1,388
Under construction	1,959	—	1,959	1,098	—	1,098
	3,826	203	3,623	2,616	130	2,486
Other Natural Gas Pipelines
GTN	2,278	765	1,513	1,842	588	1,254
Great Lakes	2,157	1,155	1,002	1,807	939	868
Foothills	1,606	1,162	444	1,671	1,180	491
Other²	2,223	572	1,651	1,800	363	1,437
	8,264	3,654	4,610	7,120	3,070	4,050
Under construction	71	—	71	34	—	34
	8,335	3,654	4,681	7,154	3,070	4,084
	42,054	18,737	23,317	37,377	17,173	20,204




Liquids Pipelines
Keystone
Pipeline	9,288	718	8,570	7,931	463	7,468
Pumping equipment	1,092	108	984	964	80	884
Tanks and other	3,034	228	2,806	2,282	144	2,138
	13,414	1,054	12,360	11,177	687	10,490
Under construction	1,826	—	1,826	4,438	—	4,438
	15,240	1,054	14,186	15,615	687	14,928
Energy
Natural Gas – Ravenswood	2,607	654	1,953	2,140	476	1,664
Natural Gas – Other^3,4	3,361	1,164	2,197	3,214	971	2,243
Hydro, Wind and Solar⁵	2,417	476	1,941	2,194	359	1,835
Natural Gas Storage and Other	740	132	608	717	118	599
	9,125	2,426	6,699	8,265	1,924	6,341
Under construction	430	—	430	149	—	149
	9,555	2,426	7,129	8,414	1,924	6,490
Corporate	267	82	185	232	80	152
	67,116	22,299	44,817	61,638	19,864	41,774


¹	TCO is excluded from the ANR net book value at December 31, 2015 as it has been classified as an asset held for sale. Refer to Note 6 for further information.


²	Includes Bison, Portland Natural Gas Transmission System (PNGTS), North Baja, Tuscarora and Ventures LP.

Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $813 million and $142 million, respectively, at December 31, 2015 (2014 – $695 million and $103 million, respectively). Revenues of $93 million were recognized in 2015 (2014 – $81 million; 2013 – $78 million) through the sale of electricity under the related PPAs.


⁴	Includes Halton Hills, Coolidge, Bécancour, Ocean State Power, Mackay River and other natural gas-fired facilities.


⁵	Includes the acquisitions of four solar power facilities in 2014.

Keystone XL Impairment

At December 31, 2015, the Company evaluated its investment in Keystone XL and related projects, including the Keystone Hardisty Terminal (KHT), 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 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 impairment charge includes $77 million ($56 million after-tax) for certain cancellation fees that will be incurred in the future if the project is ultimately abandoned.



at December 31, 2015	Estimated	Impairment charge
(millions of Canadian $)	Fair Value	Pre-tax	After-tax

Plant and equipment	463	1,460	1,391
Terminals, including KHT	158	274	219
Intangible assets	—	1,150	737
Capitalized interest	—	725	488
Future cancellation costs	—	77	56
	621	3,686	2,891

The estimated fair value of $463 million related to plant and equipment was based on the price that would be received on sale of the plant and equipment in its current condition. An independent third party valuation was utilized in the assessment of the fair value of these assets. Key assumptions used in the determination of selling price included an estimated two year disposal period and the current weak energy market conditions. The valuation considered a variety of potential selling prices that were based on the various markets that could be used in order to dispose of these assets.

The estimated $158 million fair value of the terminal assets, including KHT, was determined using a discounted cash flow approach as a measure of fair value. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value.

The valuation techniques above required the use of unobservable inputs. As a result, the fair value is classified within Level 3 of the fair value hierarchy. Refer to Note 23 for further information on the fair value hierarchy.

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). This impairment charge was based on the excess of the carrying value over the fair value of the turbines, which was determined based on a comparison to similar assets available for sale in the market.

EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

EQUITY INVESTMENTS



(millions of Canadian $)	Ownership Interest at December 31, 2015		Income / (Loss) from Equity Investments				Equity Investments
			year ended December 31				at December 31
			2015		2014	2013	2015	2014

Natural Gas Pipelines
Northern Border^1,2			85		76	66	664	587
Iroquois	44.5	%	51		43	41	238	210
TQM	50.0	%	12		12	13	72	73
Other	Various		31		32	25	73	68
Liquids Pipelines
Grand Rapids	50.0	%	—		—	—	542	240
Canaport Energy East Marine Terminal	50.0	%	—		—	—	16	—
Energy
Bruce Power^3,4	48.5	%	249		314	310	4,200	3,995
ASTC Power Partnership	50.0	%	(23	)	8	110	21	29
Portlands Energy	50.0	%	30		36	31	321	335
Other	Various		5		1	1	67	61
			440		522	597	6,214	5,598

The results reflect a 50.0 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2015, TransCanada had an ownership interest in TC PipeLines, LP of 28.0 per cent (2014 – 28.3 and 2013 – 28.9 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.0 per cent (2014 – 14.2 and 2013 – 14.5 per cent).


²	At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$117 million (2014 – US$117 million) due to the fair value assessment of assets at the time of acquisition.

As a result of TransCanada's increased ownership in Bruce Power L.P. (Bruce B) and the merger of Bruce Power A L.P. (Bruce A) and Bruce B (to form Bruce Power) in December 2015, TransCanada has an ownership interest in Bruce Power of 48.5 per cent. Prior to the acquisition and merger, TransCanada applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. TransCanada continues to apply equity accounting to Bruce Power. Refer to Note 25 for further information.


⁴	At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $973 million (2014 – $776 million) due to the fair value assessment of assets at the time of acquisitions.

Distributions received from equity investments for the year ended December 31, 2015 were $802 million (2014 – $738 million; 2013 – $733 million) of which $226 million (2014 – $159 million; 2013 – $128 million) were returns of capital and are included in Investing activities in the Consolidated statement of cash flows. The undistributed earnings from equity investments as at December 31, 2015 were $198 million (2014 – $551 million; 2013 – $754 million).

Contributions made to equity investments for the year ended December 31, 2015 were $493 million (2014 – $256 million; 2013 –$163 million) and are included in Equity investments in the Consolidated statement of cash flows.

Summarized Financial Information of Equity Investments



year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Income
Revenues	4,337		4,814		4,989
Operating and other expenses	(3,254	)	(3,489	)	(3,536	)
Net income	1,046		1,264		1,390
Net income attributable to TransCanada	440		522		597



at December 31	2015		2014
(millions of Canadian $)	2015		2014

Balance Sheet
Current assets	1,530		1,412
Non-current assets	13,190		12,260
Current liabilities	(1,370	)	(1,067	)
Non-current liabilities	(3,116	)	(3,255	)

RATE-REGULATED BUSINESSES

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

RATE-REGULATED BUSINESSES

TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain Canadian liquids pipelines currently in development. Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities.

Canadian Regulated Operations

The Canadian Mainline, NGTL System, Foothills and TQM 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 that actual costs and revenues are more or less than the 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.

Canadian Mainline

In March 2015, TransCanada filed a compliance filing with the NEB in response to the RH-001-2014 Decision on TransCanada's 2015-2030 Tolls Application (the NEB 2014 Decision) and is required to file a toll review for the 2018 to 2020 period prior to December 31, 2017. In June 2015, the NEB approved the applied-for compliance tolls as filed and these tolls became effective on July 1, 2015.

The NEB's 2014 Decision acknowledged that an off-ramp had been reached on the NEB 2013 Decision (described below) and approved fixed tolls for 2015 to 2020 as well as certain parameters for a toll setting methodology to 2030. Features of the settlement reached with shippers as approved in the NEB 2014 Decision 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 Long-term adjustment account (LTAA) and the Bridging amortization account, to capture the surplus or the 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.

In March 2013, the Company received a decision from the NEB which set tolls for 2013 through 2017 at competitive levels, fixing tolls for some services and providing unlimited pricing discretion for others (the NEB 2013 Decision). The decision established an ROE of 11.5 per cent on deemed common equity of 40 per cent and included mechanisms to achieve the fixed tolls through the use of a LTAA as well as the establishment of a Tolls Stabilization Account (TSA) to capture the surplus or the shortfall between revenues and cost of service for each year over the five-year term of the decision. In addition, the decision provided an opportunity to generate incentive earnings by increasing revenues and reducing costs. The NEB also identified certain circumstances that would require a new tolls application prior to the end of the five-year term. One of those circumstances occurred in 2013 when the TSA balance became positive. In December 2013, TransCanada filed the 2015-2030 Tolls Application with the NEB that addressed tolls moving forward including continuation of the NEB 2013 Decision tolls for 2014.

NGTL System

In February 2015, the NEB approved the NGTL System’s 2015 Revenue Requirement Settlement. The terms of the one year settlement include ROE of 10.1 per cent on 40 per cent deemed equity, a continuation of the 2014 depreciation rates and a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration (OM&A) cost amount that was based on an escalation of 2014 actual costs.

The NGTL System’s 2014 results reflect the terms of the 2013-2014 Revenue Requirement Settlement Application. This settlement had fixed annual OM&A costs and a 10.1 per cent ROE on deemed common equity of 40 per cent. Any variance between fixed OM&A costs in the settlement and actual costs accrued to TransCanada. The settlement also included a composite depreciation rate of 3.12 per cent in 2014.

Energy East

Energy East is currently in the development stage, awaiting regulatory approval from the NEB. Tolls will be designed to provide for cost recovery including return of and on capital as approved by the NEB.

Other Canadian Pipelines

The Foothills operating model for 2014 and 2015 provides for recovery of all revenue requirement components on a flow-through basis. TQM operates under a model consisting of fixed and flow-through revenue requirement components for 2014 through 2016. Any variances between actual costs and those included in the fixed component accrue to TQM.

U.S. Regulated Operations

TransCanada's U.S. natural gas pipelines are "natural gas companies" operating 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. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The Company's significant regulated U.S. natural gas pipelines are described below.

ANR

ANR's natural gas transportation and storage services are provided under tariffs regulated by the FERC. These tariffs include maximum and minimum rates for services and allow ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline Company rates were established pursuant to a settlement approved by the FERC that was effective for all periods presented, beginning in 1997. On January 29, 2016, ANR Pipeline Company filed an application with the FERC under section 4 of the NGA to establish new rates expected to be effective, subject to refund, on August 1, 2016.

ANR Storage Company rates were established pursuant to a settlement approved by the FERC in August 2012 and ANR Storage Company is required to file for new rates to be effective no later than July 1, 2016.

TCO, another ANR-related regulated entity, began operating under FERC-approved tariff rates on November 1, 2012. As at December 31, 2015, TCO assets were classified as Assets held for sale. Refer to Note 6 for more information.

Other U.S. Natural Gas Pipelines

GTN, Great Lakes and Bison are regulated by the FERC and operate in accordance with FERC-approved tariffs that establish maximum and minimum rates for various services. Each pipeline is permitted to discount or negotiate these rates on a non-discriminatory basis.

GTN’s rates were established pursuant to a settlement approved by the FERC in January 2012. On June 30, 2015, FERC approved GTN’s new settlement with its shippers which satisfies GTN’s obligations from the 2012 settlement for new rates to be in effect on January 1, 2016, and reduced rates on the mainline by three per cent on July 1, 2015. In January 2016, GTN’s rates will decrease a further 10 percent and will continue in effect through December 31, 2019. Unless superseded by a subsequent rate case or settlement, GTN’s rates will decrease an additional eight per cent for the period January 1, 2020 through December 31, 2021 when GTN will be required to establish new rates.

Great Lakes operates under rates established pursuant to a settlement approved by the FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018.

Bison continues to operate under the rates approved by FERC in connection with Bison's initial construction and has no requirement to file a new rate proceeding.

Mexico Regulated Operations

TransCanada's Mexican operations are regulated by the CRE and operate in accordance with CRE-approved tariffs. In 2014, TransCanada began using RRA for all natural gas pipelines in Mexico. The rates were established based on CRE approved negotiated contracts.

Regulatory Assets and Liabilities



at December 31	2015	2014	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)	2015	2014	Remaining Recovery/ Settlement Period (years)

Regulatory Assets
Deferred income taxes¹	848	1,001	n/a
Operating and debt-service regulatory assets²	47	4	1
Pensions and other post retirement benefits³	210	236	n/a
Foreign exchange on long-term debt⁵	54	—	1-14
Other⁴	110	72	n/a
	1,269	1,313
Less: Current portion included in Other current assets (Note 5)	85	16
	1,184	1,297
Regulatory Liabilities
Foreign exchange on long-term debt⁵	—	42	1-14
Operating and debt-service regulatory liabilities²	32	21	1
ANR-related post-employment and retirement benefits other than pension⁶	147	117	n/a
Long term adjustment account⁷	231	64	45
Pipeline abandonment costs⁸	285	—	n/a
Bridging amortization account⁹	456	—	15
Other⁴	52	49	n/a
	1,203	293
Less: Current portion included in Accounts payable and other (Note 13)	44	30
	1,159	263


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.

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 year. Pre-tax operating results in 2015 would have been $32 million lower (2014 – $28 million higher; 2013 – $76 million lower) had these amounts not been recorded as Regulatory assets and liabilities.

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. The balances are excluded from the rate base and do not earn a return on investment. Pre-tax operating results in 2015 would have been $26 million higher (2014 – $46 million lower; 2013 – $171 million higher) had these amounts not been recorded as regulatory assets and liabilities.


⁴	Pre-tax operating results in 2015 would have been $35 million lower (2014 – $2 million higher; 2013 – $2 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁵

Foreign exchange on long-term debt of the NGTL System and Foothills 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. In the absence of RRA, GAAP would have required the inclusion of these unrealized gains or losses in Net income.

⁶

Under the terms of ANR’s last rate settlement, ANR will be required to make refunds to its customers, pursuant to a refund plan to be approved by FERC in a future rate proceeding, of those amounts in the post-retirement benefit trust fund that have not been used to pay benefits to its employees. This regulatory liability represents the difference between the amount collected in rates and the amount of post-retirement benefits expense. ANR anticipates that the resolution of this liability will be determined through the section 4 rate case ANR filed with the FERC on January 29, 2016. Since the timing of the rate case conclusion is uncertain, a settlement period cannot be determined at this time. Pre-tax operating results in 2015 would have been $30 million higher (2014 – $13 million higher; 2013 – $16 million higher) had these amounts not been recorded as regulatory assets and liabilities.


⁷	Pre-tax operating results in 2015 would have been $167 million higher (2014 – $418 million higher; 2013 – $247 million lower) had these amounts not been recorded as regulatory liabilities.

⁸

Effective January 1, 2015, NEB regulated pipelines including the Mainline, NGTL System, Foothills, Keystone and TQM are required to collect and set-aside funds received from customers to be used for future pipeline abandonment activities. Funds are collected through a surcharge mechanism, set-aside in trust accounts, and the obligation to use these funds for future pipeline abandonment activities is recorded as a regulatory liability. Pre-tax operating results in 2015 would have been $285 million higher (2014 – nil; 2013 – nil) had these amounts not been recorded as regulatory liabilities.


⁹	Pre-tax operating results in 2015 would have been $456 million higher (2014 – nil; 2013 – nil) had these amounts not been recorded as regulatory liabilities.

Allowance for Funds Used During Construction

The total amount of debt and equity AFUDC included in the Consolidated statement of income was $295 million in 2015 (2014 – $136 million; 2013 – $37 million).

GOODWILL

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL

The Company has recorded the following Goodwill on its acquisitions in the U.S.:



(millions of Canadian $)	Natural Gas Pipelines	Energy	Total

Balance at January 1, 2014	2,816	880	3,696
Foreign exchange rate changes	258	80	338
Balance at December 31, 2014	3,074	960	4,034
Foreign exchange rate changes	593	185	778
Balance at December 31, 2015	3,667	1,145	4,812

At December 31, 2015, TransCanada’s Goodwill included US$573 million (2014 - US$573 million) related to the Great Lakes natural gas transportation business. TransCanada's share of this Goodwill (net of non-controlling interests) was US$386 million (2014 – US$243 million). The increase in TransCanada's share is a result of the impairment charge of US$199 million recorded by TC PipeLines, LP on its equity method goodwill related to Great Lakes. On a consolidated basis, TransCanada’s carrying value of its investment in Great Lakes is proportionately lower compared to the 46.45% owned through TC PipeLines, LP. As a result, the estimated fair value of Great Lakes exceeded TransCanada's consolidated carrying value of the investment and no impairment was recorded in 2015.

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 by using a discounted cash flow analysis. Assumptions regarding Great Lakes’ ability to realize long-term value in the North American energy market have been adversely impacted by the changing natural gas flows in its market region as well as a change in the Company's view of other strategic alternatives to increase utilization of Great Lakes. As a result, the Company reduced forecasted cash flows from the reporting unit for the next ten years as compared to those utilized in previous impairment tests. There is a risk that continued reductions in future cash flow forecasts and adverse changes in other key assumptions could result in a future impairment of a portion of the Goodwill balance relating to Great Lakes.

INTANGIBLE AND OTHER ASSETS

12 Months Ended

Dec. 31, 2015

INTANGIBLES AND OTHER ASSETS

INTANGIBLES AND OTHER ASSETS

INTANGIBLE AND OTHER ASSETS



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Capital projects in development	1,814	1,286
PPAs	220	272
Fair value of derivative contracts (Note 23)	168	93
Loans and advances¹	159	167
Employee post-retirement benefits (Note 22)	18	14
Deferred income tax assets and charges (Note 15)	15	185
Other	797	629
	3,191	2,646

TransCanada held a note receivable from the seller of Ravenswood of $213 million (US$154 million) and $213 million (US$184 million) as at December 31, 2015 and at December 31, 2014, which bears interest at 6.75 per cent and matures in 2040. The current portion included in Other current assets was $55 million (US$40 million) at December 31, 2015 and $46 million (US$40 million) at December 31, 2014.

The following amounts related to PPAs are included in Intangible and other assets:



	2015			2014
at December 31	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
(millions of Canadian $)	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value

Sheerness (expires 2020)	585	390	195	585	351	234
Sundance A (expires 2017)	225	200	25	225	187	38
	810	590	220	810	538	272

Amortization expense for these PPAs was $52 million for the year ended December 31, 2015 (2014 and 2013 – $52 million). The expected annual amortization expense for 2016 and 2017 is $52 million, and $39 million for 2018 to 2020.

NOTES PAYABLE

12 Months Ended

Dec. 31, 2015

Short-term Debt [Abstract]

NOTES PAYABLE



	2015			2014
(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	697	0.8	%	1,540	1.2	%
U.S. (2015 – US$376; 2014 – US$800)	521	1.1	%	927	0.7	%
	1,218			2,467

At December 31, 2015, Notes payable consists of commercial paper issued by TransCanada PipeLines Limited (TCPL), TransCanada American Investments Ltd. (TAIL), and TransCanada Power Marketing Ltd. (TCPM). In November 2015, the TAIL credit facility was increased to US$1.5 billion from US$1.0 billion and, subsequently, TAIL and TCPM became co-borrowers under the facility and co-issuers under the related commercial paper program. At the same time, the TCPL USA credit facility was reduced from the US$1.0 billion to US$0.5 billion. In December 2015, a new US$1.0 billion credit facility and related commercial paper program was initiated for TCPL.

At December 31, 2015, total committed revolving and demand credit facilities of $8.9 billion (2014 – $6.7 billion) were available. When drawn, interest on these lines of credit is charged at prime rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:

year ended December 31

at December 31, 2015

2015

2014

2013

Amount

Unused Capacity

Borrower

Description

Matures

Cost to maintain

(millions of Canadian $)

$3 billion

TCPL

Committed, syndicated, revolving, extendible TCPL credit facility

December 2020

US$1 billion

TCPL

Committed, syndicated, revolving, extendible TCPL credit facility

December 2016

—

US$0.5 billion

TCPL USA

Committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL

December 2016

US$1.5 billion

TAIL/TCPM

Committed, syndicated, revolving, extendible TAIL/TCPM credit facility, guaranteed by TCPL

December 2016

—

$1.7 billion

$0.7 billion

TCPL/TCPL USA

Supports the issuance of letters of credit and provides additional liquidity

Demand

—

At December 31, 2015, the Company's operated affiliates had an additional $0.6 billion (2014 – $0.4 billion) of undrawn capacity on committed credit facilities.

ACCOUNTS PAYABLE AND OTHER

12 Months Ended

Dec. 31, 2015

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE AND OTHER



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Trade payables	1,506	1,624
Fair value of derivative contracts (Note 23)	926	749
Dividends payable	385	359
Regulatory liabilities (Note 9)	44	30
Liabilities related to assets held for sale (Note 6)	39	—
Other	121	130
	3,021	2,892

OTHER LONG-TERM LIABILITIES

12 Months Ended

Dec. 31, 2015

Deferred Costs, Noncurrent [Abstract]

OTHER LONG-TERM LIABILITIES



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Fair value of derivative contracts (Note 23)	625	411
Employee post-retirement benefits (Note 22)	380	444
Asset retirement obligations	109	98
Guarantees (Note 26)	26	20
Other	120	79
	1,260	1,052

INCOME TAXES

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

INCOME TAXES

Provision for Income Taxes



year ended December 31	2015		2014	2013
(millions of Canadian $)	2015		2014	2013

Current
Canada	44		103	27
Foreign	92		42	16
	136		145	43
Deferred
Canada	33		309	245
Foreign	(135	)	377	323
	(102	)	686	568
Income Tax Expense	34		831	611

Geographic Components of Income



year ended December 31	2015		2014	2013
(millions of Canadian $)	2015		2014	2013

Canada	(624	)	1,146	1,224
Foreign	(482	)	1,678	1,298
(Loss)/Income Before Income Taxes	(1,106	)	2,824	2,522

Reconciliation of Income Tax Expense



year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

(Loss)/Income before income taxes	(1,106	)	2,824		2,522
Federal and provincial statutory tax rate	26.0	%	25.0	%	25.0	%
Expected income tax (recovery)/expense	(288	)	706		631
Income tax differential related to regulated operations	159		129		(13	)
Higher effective foreign tax rates	14		25		33
Income from equity investments and non-controlling interests	(56	)	(38	)	(28	)
Tax rate and legislative changes	34		—		(25	)
Asset impairment charges¹	170		—		—
Other	1		9		13
Actual Income Tax Expense	34		831		611


¹	The asset impairment impact is net of $311 million attributed to higher foreign tax rates.

Deferred Income Tax Assets and Liabilities



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Deferred Income Tax Assets
Difference in accounting and tax bases of impaired assets	916	—
Tax loss and credit carryforwards	1,327	1,344
Regulatory and other deferred amounts	231	236
Unrealized foreign exchange losses on long-term debt	589	140
Financial instruments	111	104
Other	136	149
	3,310	1,973
Less: Valuation allowance¹	1,060	125
	2,250	1,848
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,441	5,548
Equity investments	656	648
Taxes on future revenue requirement	227	253
Other	55	71
	7,379	6,520
Net Deferred Income Tax Liabilities	5,129	4,672


¹	In 2015, an increase to the valuation allowance of $935 million was recorded as the Company believes that it is more likely than not that the tax benefits related to the unrealized foreign exchange losses on long-term debt and unrealized losses on certain impaired assets will not be realized in the future.

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



at December 31	2015	2014¹
(millions of Canadian $)	2015	2014¹

Deferred Income Tax Assets
Intangible and other assets (Note 11)	15	185
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,144	4,857
Net Deferred Income Tax Liabilities	5,129	4,672


¹	As a result of retrospectively applying guidance on the presentation of deferred taxes on the Consolidated balance sheet on January 1, 2015, the Company reclassified its December 31, 2014 current Deferred income tax assets of $427 million, and current Deferred income tax liabilities of $4 million to its non-current Deferred income tax assets and liabilities.

At December 31, 2015, the Company has recognized the benefit of unused non-capital loss carryforwards of $1,283 million (2014 – $1,131 million) for federal and provincial purposes in Canada, which expire from 2026 to 2035. The Company also has Ontario minimum tax credits of $57 million (2014 – $50 million), which expire from 2016 to 2035.

At December 31, 2015, the Company has recognized the benefit of unused net operating loss carryforwards of US$1,617 million (2014 – US$2,267 million) for federal purposes in the U.S., which expire from 2029 to 2034. The Company also has alternative minimum tax credits of US$41 million (2014 – US$26 million).

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, 2015 by approximately $308 million (2014 – $236 million) if there had been a provision for these taxes.

Income Tax Payments

Income tax payments of $162 million, net of refunds, were made in 2015 (2014 – payments, net of refunds, of $109 million; 2013 – payments, net of refunds, of $202 million).

Reconciliation of Unrecognized Tax Benefit

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



at December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Unrecognized tax benefit at beginning of year	18		23		49
Gross increases – tax positions in prior years	2		3		3
Gross decreases – tax positions in prior years	(2	)	(8	)	(28	)
Gross increases – tax positions in current year	1		1		2
Lapses of statute of limitations	(2	)	(1	)	(3	)
Unrecognized Tax Benefit at End of Year	17		18		23

TransCanada recognized a favourable income tax adjustment of approximately $25 million due to the enactment of certain Canadian federal tax legislation in June 2013.

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 2007. 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, 2015 reflects a $1 million reversal of Interest expense and nil for penalties (2014 – $1 million increase of Interest expense and nil for penalties; 2013 – $1 million reversal for Interest expense and nil for penalties). At December 31, 2015, the Company had $4 million accrued for Interest expense and nil accrued for penalties (December 31, 2014 –$5 million accrued for Interest expense and nil accrued for penalties).

LONG-TERM DEBT

12 Months Ended

Dec. 31, 2015

Long-term Debt, Unclassified [Abstract]

LONG-TERM DEBT



		2015			2014
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate¹		Outstanding at December 31	Interest Rate¹
(millions of Canadian $, unless otherwise noted)	Maturity Dates	Outstanding at December 31	Interest Rate¹		Outstanding at December 31	Interest Rate¹

TRANSCANADA PIPELINES LIMITED
Debentures
Canadian	2017 to 2020	599	10.7	%	749	10.9	%
U.S. (2015 and 2014 – US$400)	2021	554	9.9	%	464	9.9	%
Medium-Term Notes
Canadian	2016 to 2041	5,192	5.3	%	4,048	5.7	%
Senior Unsecured Notes
U.S. (2015 – US$14,723; 2014 – US$13,526)	2016 to 2045	20,340	4.8	%	15,655	5.0	%
		26,685			20,916
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian²	2016 to 2024	325	11.5	%	325	11.5	%
U.S. (2015 and 2014 – US$200)	2023	277	7.9	%	232	7.9	%
Medium-Term Notes
Canadian	2025 to 2030	504	7.4	%	504	7.4	%
U.S. (2015 and 2014 – US$33)	2026	45	7.5	%	38	7.5	%
		1,151			1,099
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2015 and 2014 – US$432)	2021 to 2025	598	8.9	%	502	8.9	%
GAS TRANSMISSION NORTHWEST LLC
Unsecured Term Loan
U.S. (2015 – US$75)	2019	104	1.4	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$250; 2014 – US$325)	2020 to 2035	346	5.6	%	377	5.5	%
		450			377
TC PIPELINES, LP
Unsecured Loan
U.S. (2015 – US$200; 2014 – US$330)	2017	277	1.6	%	383	1.4	%
Unsecured Term Loan Facility
U.S. (2015 and 2014 – US$500)	2018	692	1.6	%	580	1.4	%
Unsecured Term Loan
U.S. (2015 – US$170)	2018	235	1.6	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$698; 2014 – US$350)	2021 to 2025	967	4.7	%	405	4.7	%
		2,171			1,368
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2015 – US$297; 2014 – US$316)	2018 to 2030	411	7.8	%	367	7.8	%




TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
U.S. (2015 – US$16; 2014 – US$20)	2017	22	4.0	%	23	4.0	%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes³
U.S. (2015 – US$69; 2014 – US$90)	2018	96	6.1	%	105	6.1	%
		31,584			24,757
Less: Current portion of Long-term debt		2,547			1,797
		29,037			22,960


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	Debentures issued by NGTL in the amount of $225 million have retraction provisions that entitle the holders to periodically require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions were made in 2015 or 2014.


³	Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

Principal Repayments

At December 31, 2015, principal repayments on the Long-term debt of the Company for the next five years are approximately as follows:



(millions of Canadian $)	2016	2017	2018	2019	2020

Principal repayments on Long-term debt	2,547	2,150	3,379	1,228	1,801

Long-Term Debt Issued

The Company issued Long-term debt over the three years ended December 31, 2015 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Issue date

Type

Maturity date

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

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

February 2014

Senior Unsecured Notes

March 2034

US 1,250

4.63

October 2013

Senior Unsecured Notes

October 2023

US 625

3.75

October 2013

Senior Unsecured Notes

October 2043

US 625

5.00

July 2013

Senior Unsecured Notes

June 2016

US 500

Floating

July 2013

Medium-Term Notes

July 2023

450

3.69

July 2013

Medium-Term Notes

November 2041

300

4.55

January 2013

Senior Unsecured Notes

January 2016

US 750

0.75

TC PIPELINES, LP

September 2015

Unsecured Term Loan

October 2018

US 170

Floating

March 2015

Senior Unsecured Notes

March 2025

US 350

4.375

July 2013

Unsecured Term Loan Facility

July 2018

US 500

Floating

GAS TRANSMISSION NORTHWEST LLC

June 2015

Unsecured Term Loan

June 2019

US 75

Floating

Long-Term Debt Retired

The Company retired Long-term debt over the three years ended December 31, 2015 as follows:



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

TRANSCANADA PIPELINES LIMITED
	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	%
	June 2014	Debentures	125	11.10	%
	February 2014	Medium-Term Notes	300	5.05	%
	January 2014	Medium-Term Notes	450	5.65	%
	August 2013	Senior Unsecured Notes	US 500	5.05	%
	June 2013	Senior Unsecured Notes	US 350	4.00	%
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Senior Unsecured Notes	US 75	5.09	%
NOVA GAS TRANSMISSION LTD.
	June 2014	Debentures	53	11.20	%

Interest Expense

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



year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Interest on Long-term debt	1,487		1,317		1,216
Interest on Junior subordinated notes (Note 17)	116		70		65
Interest on short-term debt	16		15		12
Capitalized interest	(280	)	(259	)	(287	)
Amortization and other financial charges¹	31		55		(21	)
	1,370		1,198		985


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.

The Company made interest payments of $1,266 million in 2015 (2014 – $1,123 million; 2013 – $985 million) on Long-term debt, Junior subordinated notes and Notes payable, net of interest capitalized.

JUNIOR SUBORDINATED NOTES

12 Months Ended

Dec. 31, 2015

Junior Subordinated Notes [Abstract]

JUNIOR SUBORDINATED NOTES



		2015			2014
Outstanding loan amount	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
(millions of Canadian $, unless otherwise noted)	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate

TRANSCANADA PIPELINES LIMITED
U.S. (2015 and 2014 – US$1,000)¹	2067	1,384	6.4	%	1,160	6.5	%
U.S. (2015 – US$750)¹	2075	1,038	5.3	%	—	—
		2,422			1,160


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

Junior subordinated notes of US$1.0 billion mature in May 2067 and bear interest at 6.35 per cent per annum until May 15, 2017, when interest will convert to a floating rate that is reset quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 2.21 per cent. The Company has the option to defer payment of interest for periods of up to 10 years without giving rise to a default or permitting acceleration of payment under the terms of the Junior subordinated notes, however, the Company would be prohibited from paying dividends during any such deferral period. The Junior subordinated notes are callable at the Company's option at any time on or after May 15, 2017 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. The Junior subordinated notes are callable earlier, in whole or in part, upon the occurrence of certain events and at the Company's option at an amount equal to the greater of 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption and an amount determined by a specified formula in accordance with their terms.

In May 2015, TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL, issued US$750 million Trust Notes - Series 2015-A (Trust Notes) to third party investors at a fixed interest rate of 5.625 per cent for the first 10 years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$750 million of Junior subordinated notes of TCPL at a rate of 5.875 per cent, including a 0.25 per cent administration charge. The rate will reset commencing May 2025 until May 2045 to the three month LIBOR plus 3.778 per cent per annum; from May 2045 to May 2075 the interest rate will reset to the three month LIBOR plus 4.528 per cent per annum. The Junior subordinated notes of TCPL are callable at TCPL's option at any time on or after May 20, 2025 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL.

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 other outstanding first preferred shares of TCPL.

NON-CONTROLLING INTERESTS

12 Months Ended

Dec. 31, 2015

Noncontrolling Interest [Abstract]

NON-CONTROLLING INTERESTS

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



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Non-controlling interest in TC PipeLines, LP	1,590	1,479
Non-controlling interest in PNGTS	127	104
	1,717	1,583

The Company's Non-controlling interests included in the Consolidated statement of income are as follows:



year ended December 31	2015		2014	2013
(millions of Canadian $)	2015		2014	2013

Non-controlling interest in TC PipeLines, LP	(13	)	136	93
Non-controlling interest in PNGTS	19		15	12
Preferred shares of TCPL	—		2	20
	6		153	125

During 2015, the Non-controlling interest in TC PipeLines, LP increased from 71.7 per cent to 72.0 per cent due to periodic issuances of common units in TC PipeLines, LP to non-controlling interests. In 2014, the Non-controlling interest in TC PipeLines, LP ranged between 71.1 per cent and 71.7 per cent and, in 2013, between 66.7 per cent and 71.1 per cent.

At December 31, 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 is included in the $13 million Non-controlling interest in TC PipeLines, LP in the Consolidated statement of income.

The Non-controlling interest in PNGTS as at December 31, 2015 represented the 38.3 per cent interest held by third parties (2014 and 2013 – 38.3 per cent).

In 2015, TransCanada received fees of $4 million from TC PipeLines, LP (2014 and 2013 – $3 million) and $11 million from PNGTS (2014 – $8 million; 2013 – $7 million) for services provided.

On March 5, 2014, TCPL redeemed all of its four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series Y at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends to the redemption date.

On October 15, 2013, TCPL redeemed all of its four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series U at a price of $50 per share plus $0.5907 representing accrued and unpaid dividends to the redemption date.

COMMON SHARES

12 Months Ended

Dec. 31, 2015

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

COMMON SHARES



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

Outstanding at January 1, 2013	705,461		12,069
Exercise of options	1,980		80
Outstanding at December 31, 2013	707,441		12,149
Exercise of options	1,221		53
Outstanding at December 31, 2014	708,662		12,202
Exercise of options	737		30
Repurchase of shares	(6,785	)	(130	)
Outstanding at December 31, 2015	702,614		12,102

Common Shares Issued and Outstanding

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

Common Shares Repurchased

On November 19, 2015, the Company received approval from the Toronto Stock Exchange (TSX) for a normal course issuer bid (NCIB) allowing it to repurchase, for cancellation, up to 21,270,257 of its common shares representing three per cent of the issued and outstanding common shares. Under the NCIB, which expires on November 22, 2016, the Company may purchase these common shares through the facilities of the TSX, the New York Stock Exchange and other designated exchanges and published markets in both Canada and the U.S., or through off-exchange block purchases by way of private agreement.

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 (weighted average cost of $130 million). The difference of $164 million between the total price paid and the weighted average cost was recorded in Additional paid-in capital.

Basic and Diluted Net (Loss)/Income per Share

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



Weighted Average Common Shares Outstanding	2015	2014	2013
(millions)	2015	2014	2013

Basic	709	708	707
Diluted	709	710	708

Stock Options



	Number of Options		Weighted Average Exercise Price		Options Exercisable
	(thousands)				(thousands)

Outstanding at January 1, 2013	7,434			$37.69	4,568
Granted	1,939			$47.09
Exercised	(1,980	)		$36.12
Outstanding at December 31, 2013	7,393			$40.57	3,914
Granted	2,292			$49.03
Exercised	(1,221	)		$43.00
Outstanding at December 31, 2014	8,464			$43.17	4,556
Granted	2,214			$56.58
Exercised	(737	)		$36.14
Forfeited	(107	)		$50.74
Outstanding at December 31, 2015	9,834			$46.63	5,566

Stock options outstanding at December 31, 2015 were as follows:



	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
	(thousands)			(years)	(thousands)			(years)

$31.93 to $36.26	970		$34.27	0.9	970		$34.27	0.9
$36.90 to $41.65	888		$37.91	2.1	888		$37.91	2.1
$41.95 to $45.29	1,759		$42.04	3.2	1,759		$42.04	3.2
$47.09	1,800		$47.09	4.1	1,195		$47.09	4.1
$49.03	2,242		$49.03	5.2	754		$49.03	5.2
$56.58	2,175		$56.58	6.2	—	—		0.0
	9,834		$46.63	4.1	5,566		$42.04	3.1

An additional 6,123,649 common shares were reserved for future issuance under TransCanada's Stock Option Plan at December 31, 2015. The weighted average fair value of options granted to purchase common shares under the Company's Stock Option Plan was determined to be $6.45 for the year ended December 31, 2015 (2014 – $5.54; 2013 – $5.74). 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 33.3 per cent 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	2015		2014		2013

Expected life (years)	5.8		6.0		6.0
Interest rate	1.1	%	1.8	%	1.7	%
Volatility¹	18	%	17	%	18	%
Dividend yield	3.7	%	3.8	%	3.7	%
Forfeiture rate	5	%	5	%	15	%


¹	Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.

The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $11 million in 2015 (2014 – $9 million; 2013 – $6 million).

The following table summarizes additional stock option information:



year ended December 31	2015	2014	2013
(millions of Canadian $, unless otherwise noted)	2015	2014	2013

Total intrinsic value of options exercised	37	68	25
Fair value of options that have vested	91	95	64
Total options vested	2.0 million	1.7 million	1.3 million

As at December 31, 2015, the aggregate intrinsic value of the total options exercisable was $23 million and the total intrinsic value of options outstanding was $23 million.

Shareholder Rights Plan

TransCanada's Shareholder Rights Plan is designed to provide the Board of Directors (Board) 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 two common shares of the Company for the then current market price of one.

PREFERRED SHARES

12 Months Ended

Dec. 31, 2015

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

PREFERRED SHARES



at December 31	Number of Shares Authorized and Outstanding	Current Yield		Annual Dividend Per Share¹		Redemption Price Per Share²		Redemption and Conversion Option Date^2,3	Right to Convert Into^3,4	2015	2014
	(thousands)									(millions of Canadian $)⁶	(millions of Canadian $)⁶

Cumulative First Preferred Shares⁵
Series 1	9,498	3.266	%		$0.8165		$25.00	December 31, 2019	Series 2	233	233
Series 2	12,502	Floating⁷		Floating			$25.00	December 31, 2019	Series 1	306	306
Series 3	8,533	2.152	%		$0.538		$25.00	June 30, 2020	Series 4	209	343
Series 4	5,467	Floating⁷		Floating			$25.00	June 30, 2020	Series 3	134	—
Series 5	14,000	4.40	%		$1.10		$25.00	January 30, 2016	Series 6	342	342
Series 7	24,000	4.00	%		$1.00		$25.00	April 30, 2019	Series 8	589	589
Series 9	18,000	4.25	%		$1.0625		$25.00	October 30, 2019	Series 10	442	442
Series 11	10,000	3.80	%		$0.95		$25.00	November 30, 2020	Series 12	244	—
										2,499	2,255


¹	The holder is entitled to receive a fixed cumulative quarterly preferential dividend as and when declared by the Board with the exception of Series 2 and Series 4 preferred shares. The holders of Series 2 and Series 4 preferred shares are entitled to receive quarterly floating rate cumulative preferential dividends as and when declared by the Board.

TransCanada may, at its option, redeem all or a portion of the outstanding 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 and Series 4 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, in which case they are redeemable at $25.00 per share plus all accrued and unpaid dividends.


³	The holder 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.

⁴

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 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) and 2.96 per cent (Series 12). These rates will reset each quarter going forward.

⁵

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, equal to 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), and 2.96 per cent (Series 11).


⁶	Net of underwriting commissions and deferred income taxes.


⁷	Commencing December 31, 2015, the floating quarterly dividend rate for the Series 2 preferred shares is 2.418 per cent and the Series 4 preferred shares is 1.778 per cent for the period starting December 31, 2015 to, but excluding, March 31, 2016. These rates will reset each quarter going forward.

In March 2015, TransCanada completed a public offering of 10 million Series 11 cumulative redeemable first preferred shares at a price of $25.00 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 redeemable first preferred shares and receive quarterly floating rate, cumulative, dividends at an annualized rate equal to the applicable 90-day Government of Canada Treasury Bill rate plus 1.28 per cent which will reset every quarter going forward. The 8,533,405 Series 3 preferred shares will pay on a quarterly basis, for the five year period beginning on June 30, 2015, a fixed quarterly dividend based on an annualized dividend rate of 2.152 per cent.

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

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

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

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

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



year ended December 31, 2015	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount

Foreign currency translation gains on net investment in foreign operations	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 to net income of actuarial gains and losses and prior service costs 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



year ended December 31, 2014	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount

Foreign currency translation gains on net investment in foreign operations	462		55		517
Change in fair value of net investment hedges	(373	)	97		(276	)
Change in fair value of cash flow hedges	(118	)	49		(69	)
Reclassification to net income of gains and losses on cash flow hedges	(95	)	40		(55	)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(146	)	44		(102	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	25		(7	)	18
Other comprehensive loss on equity investments	(272	)	68		(204	)
Other Comprehensive Loss	(517	)	346		(171	)



year ended December 31, 2013	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
Foreign currency translation gains on net investment in foreign operations	269		114		383
Change in fair value of net investment hedges	(323	)	84		(239	)
Change in fair value of cash flow hedges	121		(50	)	71
Reclassification to net income of gains and losses on cash flow hedges	60		(19	)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	96		(29	)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	34		(11	)	23
Other comprehensive income on equity investments	313		(79	)	234
Other Comprehensive Income	570		10		580

The changes in AOCI by component are as follows:



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

AOCI balance at January 1, 2013	(707	)	(116	)	(287	)	(338	)	(1,448	)
Other comprehensive income before reclassifications²	78		71		67		219		435
Amounts reclassified from accumulated other comprehensive loss	—		41		23		15		79
Net current period other comprehensive income	78		112		90		234		514
AOCI balance at December 31, 2013	(629	)	(4	)	(197	)	(104	)	(934	)
Other comprehensive income/(loss) before reclassifications²	111		(69	)	(102	)	(206	)	(266	)
Amounts reclassified from accumulated other comprehensive loss	—		(55	)	18		2		(35	)
Net current period other comprehensive income/(loss)	111		(124	)	(84	)	(204	)	(301	)
AOCI balance at December 31, 2014	(518	)	(128	)	(281	)	(308	)	(1,235	)
Other comprehensive income/(loss) before reclassifications²	135		(57	)	51		33		162
Amounts reclassified from accumulated other comprehensive loss³	—		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	)


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


²	Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $306 million in 2015 (2014 – $130 million gains; 2013 – $66 million gains).

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 $83 million ($51 million, net of tax) at December 31, 2015. 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 From Accumulated Other Comprehensive Loss¹						Affected Line Item in the Consolidated Statement of Income
year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Cash flow hedges
Commodities	(128	)	111		(44	)	Revenues (Energy)
Interest	(16	)	(16	)	(16	)	Interest expense
	(144	)	95		(60	)	Total before tax
	56		(40	)	19		Income tax expense/(recovery)
	(88	)	55		(41	)	Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial loss and past service cost	(41	)	(25	)	(34	)	²
	9		7		11		Income tax recovery
	(32	)	(18	)	(23	)	Net of tax
Equity investments
Equity income	(19	)	(2	)	(20	)	Income from equity investments
	5		—		5		Income tax recovery
	(14	)	(2	)	(15	)	Net of tax


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


²	These Accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 22 for further information.

- Definition

The entire disclosure for comprehensive income, which includes, but is not limited to, 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e689-108580

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=36458714&loc=SL7669619-108580

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e640-108580

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e716-108580

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e709-108580

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187085-122770

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e637-108580

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e681-108580

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

+ Details

EMPLOYEE POST-RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

EMPLOYEE POST-RETIREMENT BENEFITS

The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining service life of employees, which is approximately nine years at December 31, 2015 (2014 and 2013 – nine years).

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 life expectancy of former employees, which was approximately 12 years at December 31, 2015 (2014 – 12 years; 2013 – 11 years). In 2015, the Company expensed $41 million (2014 – $37 million; 2013 – $29 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	2015	2014	2013
(millions of Canadian $)	2015	2014	2013

DB Plans	96	73	79
Other post-retirement benefit plans	6	6	6
Savings and DC Plans	41	37	29
	143	116	114

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 $33 million letter of credit to the Canadian DB Plan in 2015 (2014 – $47 million; 2013 – $59 million), resulting in a total of $214 million provided to the Canadian DB Plan under letters of credit at December 31, 2015.

The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2015 and the next required valuation will be as at January 1, 2016.

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



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014

Change in Benefit Obligation¹
Benefit obligation – beginning of year	2,658		2,224		216		191
Service cost	108		85		3		2
Interest cost	115		113		10		10
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Actuarial (gain)/loss	(57	)	302		(11	)	14
Foreign exchange rate changes	81		32		14		6
Benefit obligation – end of year	2,780		2,658		225		216
Change in Plan Assets
Plan assets at fair value – beginning of year	2,398		2,152		39		35
Actual return on plan assets	160		246		(1	)	2
Employer contributions²	96		73		6		6
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Foreign exchange rate changes	62		25		8		3
Plan assets at fair value – end of year	2,591		2,398		45		39
Funded Status – Plan Deficit	(189	)	(260	)	(180	)	(177	)


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 $214 million in letters of credit provided to the Canadian DB Plans for funding purposes (2014 – $181 million).

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



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014

Intangible and other assets (Note 11)	—		—		18		14
Accounts payable and other	—		—		(7	)	(7	)
Other long-term liabilities (Note 14)	(189	)	(260	)	(191	)	(184	)
	(189	)	(260	)	(180	)	(177	)

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



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014

Projected benefit obligation¹	(2,780	)	(2,658	)	(198	)	(191	)
Plan assets at fair value	2,591		2,398		—		—
Funded Status – Plan Deficit	(189	)	(260	)	(198	)	(191	)


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	2015		2014
(millions of Canadian $)	2015		2014

Accumulated benefit obligation	(2,600	)	(2,437	)
Plan assets at fair value	2,591		2,398
Funded Status – Plan Deficit	(9	)	(39	)

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	2015		2014
(millions of Canadian $)	2015		2014

Accumulated benefit obligation	(807	)	(715	)
Plan assets at fair value	680		597
Funded Status – Plan Deficit	(127	)	(118	)

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



	Percentage of Plan Assets				Target Allocations
at December 31	2015		2014		2015

Debt securities	34	%	31	%	25% to 35%
Equity securities	66	%	69	%	50% to 70%
Alternatives	—		—		5 % to 15%
	100	%	100	%

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



at December 31			Percentage of Plan Assets
(millions of Canadian $)	2015	2014	2015		2014

Debt securities	2	1	0.1	%	0.1	%
Equity securities	4	1	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 23.



at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $)	2015	2014	2015	2014	2015	2014	2015	2014	2015	2014

Asset Category
Cash and Cash Equivalents	44	20	2	—	—	—	46	20	2	1
Equity Securities:
Canadian	317	361	147	142	—	—	464	503	17	21
U.S.	589	516	40	35	—	—	629	551	24	23
International	38	218	300	147	—	—	338	365	13	15
Global	—	—	154	141	—	—	154	141	6	6
Emerging	7	7	143	80	—	—	150	87	6	3
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	206	218	—	—	206	218	8	9
Provincial	—	—	202	180	—	—	202	180	8	7
Municipal	—	—	7	7	—	—	7	7	—	—
Corporate	—	—	113	76	—	—	113	76	4	3
U.S. Bonds:
State	—	—	50	47	—	—	50	47	2	2
Corporate	—	—	57	59	—	—	57	59	2	2
International:
Corporate	—	—	25	14	—	—	25	14	1	1
Mortgage backed	—	—	58	39	—	—	58	39	2	2
Other Investments:
Private equity funds	—	—	—	—	14	13	14	13	—	—
Funds held on deposit	123	117	—	—	—	—	123	117	5	5
	1,118	1,239	1,504	1,185	14	13	2,636	2,437	100	100

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



(millions of Canadian $, pre-tax)	Private Equity Funds

Balance at December 31, 2013	18
Purchases and sales	(7	)
Realized and unrealized gains	2
Balance at December 31, 2014	13
Purchases and sales	(1	)
Realized and unrealized gains	2
Balance at December 31, 2015	14

The Company's expected funding contributions in 2016 are approximately $70 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $37 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $33 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

2016	129	8
2017	133	9
2018	138	9
2019	142	9
2020	146	10
2021 to 2025	808	51

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, 2015. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.

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



	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31	2015		2014		2015		2014

Discount rate	4.20	%	4.15	%	4.40	%	4.20	%
Rate of compensation increase	0.50	%	3.15	%	—	%	—	%

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



	Pension Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2015		2014		2013		2015		2014		2013

Discount rate	4.15	%	4.95	%	4.35	%	4.20	%	5.00	%	4.35	%
Expected long-term rate of return on plan assets	6.95	%	6.90	%	6.70	%	4.60	%	4.60	%	4.60	%
Rate of compensation increase	3.15	%	3.15	%	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 average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2021 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	14	(12	)

The Company's net benefit cost recognized is as follows:



at December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2013		2015		2014		2013

Service cost	108		85		84		3		2		2
Interest cost	115		113		96		10		10		7
Expected return on plan assets	(155	)	(139	)	(120	)	(2	)	(2	)	(2	)
Amortization of actuarial loss	35		21		30		3		2		2
Amortization of past service cost	2		2		2		1		—		—
Amortization of regulatory asset	23		18		30		1		1		1
Amortization of transitional obligation related to regulated business	—		—		—		2		2		2
Net Benefit Cost Recognized	128		100		122		18		15		12

Pre-tax amounts recognized in AOCI were as follows:



	2015		2014		2013
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits

Net loss	247	28	348	39	236	32
Prior service cost	—	—	2	1	3	1
	247	28	350	40	239	33

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 2016 is $21 million and $3 million respectively.

Pre-tax amounts recognized in OCI were as follows:



	2015				2014				2013
at December 31	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits
(millions of Canadian $)	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits

Amortization of net loss from AOCI to OCI	(34	)	(4	)	(21	)	(2	)	(30	)	(2	)
Amortization of prior service costs from AOCI to OCI	(2	)	(1	)	(2	)	—		(2	)	—
Funded status adjustment	(67	)	(7	)	137		9		(96	)	—
	(103	)	(12	)	114		7		(128	)	(2	)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2015

Risk Management and Financial Instruments [Abstract]

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings 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 uses derivatives as part of its overall risk management strategy to assist in managing the exposure to market risk that results from these activities. These derivative contracts may consist of the following:


•	Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TransCanada enters into foreign exchange and commodity forwards and futures to manage the impact of changes in foreign exchange rates and commodity prices.


•	Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.


•	Options – contractual 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. The Company enters into option agreements to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

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:


•	Subject to its overall risk management strategy, the Company commits 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.


•	The Company purchases a portion of the natural gas required for its power plants or enters into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin.


•	The Company's power sales commitments are fulfilled through power generation or through purchased contracts, thereby reducing the Company's exposure to fluctuating commodity prices.


•	The Company enters into offsetting or back-to-back positions using derivative instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.

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 a forward purchase of natural gas for injection into storage and an offsetting forward sale 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.

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.

A portion of TransCanada’s earnings from its Natural Gas Pipelines, Liquids Pipelines and Energy segments are generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TransCanada’s net income. As the Company’s U.S. dollar-denominated operations continue to grow, exposure to changes in currency rates increases; some of this foreign exchange impact is partially offset by interest expense on U.S. dollar-denominated debt of the Company's foreign operations and by using foreign exchange derivatives.

The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to other U.S. dollar-denominated transactions including those that may arise on some of the Company’s regulated assets. The realized gains and losses on these derivatives are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers.

TransCanada has floating interest rate debt which subjects it to interest rate cash flow risk. 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, foreign exchange forward contracts and foreign exchange options.

U.S. Dollar-Denominated Debt Designated as a Net Investment Hedge



at December 31	2015	2014
(millions of Canadian $, unless otherwise noted)	2015	2014

Carrying value	23,000 (US 16,600)	17,000 (US 14,700)
Fair value	23,800 (US 17,200)	19,000 (US 16,400)

Derivatives Designated as a Net Investment Hedge



	2015				2014
at December 31	Fair Value¹		Notional or Principal Amount		Fair Value¹		Notional or Principal Amount
(millions of Canadian $, unless otherwise noted)	Fair Value¹		Notional or Principal Amount		Fair Value¹		Notional or Principal Amount

U.S. dollar cross-currency interest rate swaps (maturing 2016 to 2019)²	(730	)	US	3,150	(431	)	US	2,900
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	50		US	1,800	(28	)	US	1,400
	(680	)	US	4,950	(459	)	US	4,300


¹	Fair values equal carrying values.


²	In 2015, net realized gains of $8 million (2014 – gains of $21 million) related to the interest component of cross-currency swap settlements are included in Interest expense.

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, 2015, without taking into account security held, consisted of accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets, notes, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2015, there were no significant amounts past due or impaired, and there were no significant credit losses during the year.

The Company had a credit risk concentration due from a counterparty of $248 million (US$179 million) and $258 million (US$222 million) at December 31, 2015 and 2014, respectively. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.

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

Fair Value of Non-Derivative Financial Instruments

The fair value of the Company's Notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of Long-term debt and Junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers.

Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Intangible and other assets, Notes payable, Accounts payable and other, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy.

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

Balance Sheet Presentation of Non-Derivative Financial Instruments

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



	2015				2014
at December 31	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions of Canadian $)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Notes receivable¹	214		265		213		263
Current and Long-term debt^2,3 (Note 16)	(31,584	)	(34,309	)	(24,757	)	(28,713	)
Junior subordinated notes (Note 17)	(2,422	)	(2,011	)	(1,160	)	(1,157	)
	(33,792	)	(36,055	)	(25,704	)	(29,607	)


¹	Notes receivable are included in Other current assets and Intangible and other assets on the Consolidated balance sheet.


²	Long-term debt is recorded at amortized cost, except for US$850 million (2014 – US$400 million) that is attributed to hedged risk and recorded at fair value.

Consolidated Net income in 2015 included gains of $2 million (2014 – losses of $3 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of Long-term debt at December 31, 2015 (2014 – US$400 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:



	2015		2014
at December 31	LMCI Restricted Investments¹	Other Restricted Investments²	LMCI Restricted Investments¹	Other Restricted Investments²
(millions of Canadian $)	LMCI Restricted Investments¹	Other Restricted Investments²	LMCI Restricted Investments¹	Other Restricted Investments²

Fair values
Fixed income securities (maturing within 5 years)	—	90	—	75
Fixed income securities (maturing after 10 years)	261	—	—	—
	261	90	—	75


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 would record these gains and losses as regulatory assets or liabilities. In 2015 and 2014, there were no net realized or unrealized gains or losses on LMCI restricted investments.


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. In 2015 and 2014, there were no net realized or unrealized gains or losses on other restricted investments.

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 quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

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

Balance Sheet Presentation of Derivative Instruments

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2015 is as follows:



at December 31, 2015	Cash Flow Hedges¹		Fair Value Hedges¹		Net Investment Hedges¹		Held for Trading¹		Total Fair Value of Derivative Instruments
(millions of Canadian $)	Cash Flow Hedges¹		Fair Value Hedges¹		Net Investment Hedges¹		Held for Trading¹		Total Fair Value of Derivative Instruments

Other current assets (Note 5)
Commodities²	46		—		—		326		372
Foreign exchange	—		—		65		2		67
Interest rate	—		1		—		2		3
	46		1		65		330		442
Intangible and other assets (Note 11)
Commodities²	11		—		—		126		137
Foreign exchange	—		—		29		—		29
Interest rate	—		2		—		—		2
	11		2		29		126		168
Total Derivative Assets	57		3		94		456		610

Accounts payable and other (Note 13)
Commodities²	(112	)	—		—		(443	)	(555	)
Foreign exchange	—		—		(313	)	(54	)	(367	)
Interest rate	(1	)	(1	)	—		(2	)	(4	)
	(113	)	(1	)	(313	)	(499	)	(926	)
Other long-term liabilities (Note 14)
Commodities²	(31	)	—		—		(131	)	(162	)
Foreign exchange	—		—		(461	)	—		(461	)
Interest rate	(1	)	(1	)	—		—		(2	)
	(32	)	(1	)	(461	)	(131	)	(625	)
Total Derivative Liabilities	(145	)	(2	)	(774	)	(630	)	(1,551	)


¹	Fair value equals carrying value.


²	Includes purchases and sales of power and natural gas.

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2014 is as follows:



at December 31, 2014	Cash Flow Hedges¹		Fair Value Hedges¹	Net Investment Hedges¹		Held for Trading¹		Total Fair Value of Derivative Instruments
(millions of Canadian $)	Cash Flow Hedges¹		Fair Value Hedges¹	Net Investment Hedges¹		Held for Trading¹		Total Fair Value of Derivative Instruments

Other current assets (Note 5)
Commodities²	39		—	—		359		398
Foreign exchange	—		—	5		1		6
Interest rate	—		2	—		3		5
	39		2	5		363		409
Intangible and other assets (Note 11)
Commodities²	18		—	—		72		90
Foreign exchange	—		—	1		—		1
Interest rate	—		1	—		1		2
	18		1	1		73		93
Total Derivative Assets	57		3	6		436		502

Accounts payable and other (Note 13)
Commodities²	(136	)	—	—		(422	)	(558	)
Foreign exchange	—		—	(155	)	(32	)	(187	)
Interest rate	(1	)	—	—		(3	)	(4	)
	(137	)	—	(155	)	(457	)	(749	)
Other long-term liabilities (Note 14)
Commodities²	(27	)	—	—		(72	)	(99	)
Foreign exchange	—		—	(310	)	—		(310	)
Interest rate	(1	)	—	—		(1	)	(2	)
	(28	)	—	(310	)	(73	)	(411	)
Total Derivative Liabilities	(165	)	—	(465	)	(530	)	(1,160	)


¹	Fair value equals carrying value.


²	Includes purchases and sales of power and natural gas.

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 following tables present the maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations:



at December 31, 2015	Power	Natural Gas	Foreign Exchange	Interest

Purchases¹	70,331	133	—	—
Sales¹	54,382	70	—	—
Millions of dollars	—	—	US 1,476	US 1,100
Maturity dates	2016–2020	2016–2020	2016	2016–2019


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



at December 31, 2014	Power	Natural Gas	Foreign Exchange	Interest

Purchases¹	53,217	60	—	—
Sales¹	39,429	38	—	—
Millions of dollars	—	—	US 1,374	US 650
Maturity dates	2015–2019	2015–2020	2015	2015–2018


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

Unrealized and Realized (Losses)/Gains of Derivative Instruments

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



year ended December 31	2015		2014
(millions of Canadian $)	2015		2014

Derivative instruments held for trading¹
Amount of unrealized losses in the year
Commodities	(37	)	(40	)
Foreign exchange	(21	)	(20	)
Amount of realized losses in the year
Commodities	(151	)	(28	)
Foreign exchange	(112	)	(28	)
Derivative instruments in hedging relationships^2,3
Amount of realized (losses)/gains in the year
Commodities	(179	)	130
Interest rate	8		4


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 2015, net realized gains on fair value hedges were $11 million (2014 – gains of $7 million) and were included in Interest expense.


³	In 2015 and 2014, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

Derivatives in Cash Flow Hedging Relationships

The components of OCI (Note 21) related to derivatives in cash flow hedging relationships are as follows:



year ended December 31	2015		2014
(millions of Canadian $, pre-tax)	2015		2014

Change in fair value of derivative instruments recognized in OCI (effective portion)¹
Commodities	(92	)	(128	)
Foreign exchange	—		10
	(92	)	(118	)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net income (effective portion)¹
Commodities²	128		(111	)
Interest rate³	16		16
	144		(95	)
Losses on derivative instruments recognized in Net income (ineffective portion)
Commodities²	—		(13	)


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


²	Reported within Revenues on the 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:



at December 31, 2015	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts

Derivative - Asset
Commodities	509		(418	)	91
Foreign exchange	96		(93	)	3
Interest rate	5		(1	)	4
	610		(512	)	98
Derivative - Liability
Commodities	(717	)	418		(299	)
Foreign exchange	(828	)	93		(735	)
Interest rate	(6	)	1		(5	)
	(1,551	)	512		(1,039	)


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, 2014:



at December 31, 2014	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts

Derivative - Asset
Commodities	488		(387	)	101
Foreign exchange	7		(7	)	—
Interest rate	7		(1	)	6
	502		(395	)	107
Derivative - Liability
Commodities	(657	)	387		(270	)
Foreign exchange	(497	)	7		(490	)
Interest rate	(6	)	1		(5	)
	(1,160	)	395		(765	)


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, 2015, the Company had provided cash collateral of $482 million (2014 – $459 million) and letters of credit of $41 million (2014 – $26 million) to its counterparties. The Company held nil (2014 – $1 million) in cash collateral and $2 million (2014 – $1 million) in letters of credit from counterparties on asset exposures at December 31, 2015.

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, 2015, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $32 million (2014 – $15 million), for which the Company has provided collateral in the normal course of business of nil (2014 – nil). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2015, the Company would have been required to provide additional collateral of $32 million (2014 – $15 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.
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 fair value of the derivatives. This category includes long-dated commodity transactions in certain markets where liquidity is low and inputs may include long-term broker quotes. Valuation of options is based on the Black-Scholes pricing model. Long-term electricity prices may also be estimated using a third-party modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Model inputs include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices might be estimated on a view of future natural gas supply and demand, as well as exploration and development costs. Significant decreases in fuel prices or demand for electricity or natural gas, increases in the supply of electricity or natural gas, or a small number of transactions in markets with lower liquidity are expected to or may result in a lower fair value measurement of contracts included in Level III. 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 2015, are categorized as follows:



at December 31, 2015	Quoted Prices in Active Markets Level I¹		Significant Other Observable Inputs Level II¹		Significant Unobservable Inputs Level III¹		Total
(millions of Canadian $)	Quoted Prices in Active Markets Level I¹		Significant Other Observable Inputs Level II¹		Significant Unobservable Inputs Level III¹		Total

Derivative Instrument Assets:
Commodities	34		462		13		509
Foreign exchange	—		96		—		96
Interest rate	—		5		—		5
Derivative Instrument Liabilities:
Commodities	(102	)	(611	)	(4	)	(717	)
Foreign exchange	—		(828	)	—		(828	)
Interest rate	—		(6	)	—		(6	)
	(68	)	(882	)	9		(941	)


¹	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2015.

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2014, are categorized as follows:



at December 31, 2014	Quoted Prices in Active Markets Level I¹		Significant Other Observable Inputs Level II¹		Significant Unobservable Inputs Level III¹		Total
(millions of Canadian $)	Quoted Prices in Active Markets Level I¹		Significant Other Observable Inputs Level II¹		Significant Unobservable Inputs Level III¹		Total

Derivative Instrument Assets:
Commodities	40		441		7		488
Foreign exchange	—		7		—		7
Interest rate	—		7		—		7
Derivative Instrument Liabilities:
Commodities	(86	)	(568	)	(3	)	(657	)
Foreign exchange	—		(497	)	—		(497	)
Interest rate	—		(6	)	—		(6	)
	(46	)	(616	)	4		(658	)


¹	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2014.

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



(millions of Canadian $, pre-tax)	2015		2014

Balance at beginning of year	4		1
Transfers out of Level III	5		—
Total gains included in Net income	3		3
Sales	(2	)	—
Settlements	(1	)	—
Balance at end of year¹	9		4


¹	Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2015 of $7 million (2014 – $3 million).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2015.

CHANGES IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2015

CHANGES IN OPERATING WORKING CAPITAL

CHANGES IN OPERATING WORKING CAPITAL



year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Increase in Accounts receivable	(66	)	(189	)	(54	)
Increase in Inventories	(3	)	(28	)	(30	)
(Increase)/decrease in Other current assets	(267	)	(385	)	40
(Decrease)/increase in Accounts payable and other	(153	)	377		(290	)
Increase in Accrued interest	91		36		8
Increase in Operating Working Capital	(398	)	(189	)	(326	)

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
ACQUISITIONS AND DISPOSITIONS	Dec. 31, 2015
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS Natural Gas Pipelines TC PipeLines, LP On April 1, 2015, TransCanada completed the sale of its remaining 30 per cent interest in Gas Transmission Northwest LLC (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 in proportional GTN LLC debt and US$95 million of new Class B units of TC PipeLines, LP. On October 1, 2014, TransCanada completed the sale of its remaining 30 per cent interest in Bison Pipeline LLC (Bison LLC) to TC PipeLines, LP for an aggregate purchase price of US$215 million. In May 2013, TC PipeLines, LP completed a public offering of 8,855,000 common units at a price of US$43.85 per unit, resulting in gross proceeds of approximately US$388 million and net proceeds of US$373 million after unit issuance costs. TransCanada contributed approximately US$8 million to maintain its two per cent general partnership interest and did not purchase any other units. Upon completion of this offering, TransCanada’s ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent and an after-tax dilution gain of $29 million ($47 million pre-tax) was recorded in Additional paid-in capital. In July 2013, TransCanada completed the sale of a 45 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an aggregate purchase price of US$1.05 billion, which included US$146 million for the assumption of 45 per cent of GTN LLC debt outstanding, plus normal closing adjustments. GTN LLC and Bison LLC own the GTN and Bison natural gas pipelines, respectively. Gas Pacifico/INNERGY On November 26, 2014, TransCanada sold its 30 per cent equity investments in Gas Pacifico and INNERGY for aggregate gross proceeds of $9 million and recognized a gain of $9 million ($8 million after-tax). Energy Bruce Power On December 3, 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 (OMERS) 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 operating life of the Bruce Power facility to 2064. On December 4, 2015, Bruce B and Bruce A 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 accounting to its 48.5 per cent ownership interest in Bruce Power. Prior to the acquisition, TransCanada applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. Ontario Solar As part of a purchase agreement with Canadian Solar Solutions Inc. signed in 2011, TransCanada completed the acquisition of four Ontario solar facilities for $241 million in 2014. In 2013, TransCanada completed the acquisition of four solar facilities for $216 million. The Company's total investment in the eight solar facilities is $457 million. All power produced by the solar facilities is sold under 20-year PPAs with the Ontario Power Authority. Cancarb On April 15, 2014, TransCanada sold Cancarb Limited and its related power generation for aggregate gross proceeds of $190 million and recognized a gain of $108 million ($99 million after-tax).

COMMITMENTS, CONTINGENCIES AND GUARANTEES

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

Operating Leases

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



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

2016	354	46	308
2017	355	45	310
2018	270	26	244
2019	248	24	224
2020	185	20	165
2021 and thereafter	311	1	310
	1,723	162	1,561

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 2015 was $131 million (2014 – $114 million; 2013 – $98 million).

TransCanada's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Fixed payments under these PPAs have been included in the above operating leases table. Variable payments have been excluded as these payments are dependent upon plant availability and other factors. TransCanada's share of payments under the PPAs in 2015 was $348 million (2014 – $391 million; 2013 – $242 million). The generating capacities and expiry dates of the PPAs are as follows:



	MW	Expiry Date

Sundance A	560	December 31, 2017
Sheerness	756	December 31, 2020

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.

Other Commitments

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, 2015, TransCanada was committed to Natural Gas Pipelines capital expenditures totaling approximately $0.9 billion (2014 – $0.9 billion), primarily related to construction costs related to the NGTL System, Mexican and other natural gas pipeline projects.

At December 31, 2015, the Company was committed to Liquids Pipelines capital expenditures totaling approximately $0.8 billion (2014 – $1.8 billion), primarily related to construction costs of Grand Rapids and Northern Courier.

At December 31, 2015, the Company was committed to Energy capital expenditures totaling approximately $0.6 billion (2014 – $0.2 billion), related to capital costs of the Napanee Generating Station. The Company also entered into an agreement to acquire the Ironwood natural gas fired, combined cycle power plant for US$657 million, before post-closing adjustments.

Contingencies

TransCanada is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2015, the Company had accrued approximately $32 million (2014 – $31 million; 2013 – $32 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. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions, other than the Keystone XL legal proceeding described in Note 28, will not have a material impact on the Company's consolidated financial position or results of operations.

Guarantees

TransCanada and its joint venture partner on Bruce Power, OMERS, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company's exposure under certain of these guarantees is unlimited.

In addition to the guarantees for Bruce Power, 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 related primarily to redelivery of natural gas, PPA payments and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

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



		2015		2014
year ended December 31	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value
(millions of Canadian $)	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value

Bruce Power	Ranging to 2018²	88	2	634	6
Other jointly owned entities	Ranging to 2040	139	24	104	14
		227	26	738	20


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


²	Except for one guarantee with no termination date.

CORPORATE RESTRUCTURING COSTS	12 Months Ended
CORPORATE RESTRUCTURING COSTS	Dec. 31, 2015
Restructuring and Related Activities [Abstract]
CORPORATE RESTRUCTURING COSTS	CORPORATE RESTRUCTURING COSTS At December 31, 2015, the Company had incurred $122 million pre-tax of corporate restructuring charges primarily related to severance, and recorded a provision of $87 million pre-tax related to planned severance costs in 2016 and expected 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 in the Consolidated statement of income which was partially offset by $58 million 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 on the Consolidated balance sheet, 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.

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2015
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Portland Natural Gas Transmission System On January 1, 2016, TransCanada completed the sale of a 49.9 per cent interest in PNGTS to TC PipeLines, LP for an aggregate purchase price of US$223 million. Keystone XL legal proceeding On January 6, 2016, TransCanada filed a Notice of Intent to initiate a claim under Chapter 11 of North American Free Trade Agreement (NAFTA) in response to the denial of the U.S. Presidential permit for the Keystone XL Pipeline. Through the NAFTA claim, the Company is seeking to recover more than US$15 billion in costs and damages that it estimates it has suffered as a result of the U.S. Administration’s breach of its NAFTA obligations. This litigation is in a preliminary stage and the likelihood of success and resulting impact on the Company’s financial position or results of operations is unknown at this time. U.S. Senior Notes Issue On January 27, 2016, TCPL completed an offering of US$850 million, 4.875 per cent Senior Notes due January 15, 2026 and US$400 million, 3.125 per cent Senior Notes due January 15, 2019. Ironwood On February 1, 2016, TransCanada acquired the Ironwood natural gas fired, combined cycle power plant in Lebanon, Pennsylvania, with a capacity of 778 MW, for US$657 million, before post-closing adjustments.

ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Basis of Presentation

Use of Estimates and Judgments


•	fair value and depreciation rates of plant, property and equipment (Note 7);


•	carrying value of regulatory assets and liabilities (Note 9);


•	fair value of goodwill (Note 10);


•	amortization rates and fair value of intangible assets (Note 11);


•	carrying value of asset retirement obligations (Note 14);


•	provisions for income taxes (Note 15);


•	assumptions used to measure retirement and other post-retirement obligations (Note 22);


•	fair value of financial instruments (Note 23); and


•	provision for commitments, contingencies and guarantees (Note 26).

Actual results could differ from those estimates.

Regulation

Revenue Recognition

Natural Gas Pipelines and Liquids Pipelines

Energy

Power

Natural Gas Storage

Cash and Cash Equivalents

Inventories

Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are carried at the lower of weighted average cost or market.

Plant, Property and Equipment and Capitalized Project Costs

Plant, Property and Equipment

Natural Gas Pipelines

Liquids Pipelines

Energy

Corporate

Capitalized Project Costs

Project costs related to acquisitions are capitalized once the acquisition is probable.

Assets Held For Sale and Impairment of Long-Lived Assets

Assets Held For Sale

Impairment of Long-Lived Assets

Acquisitions and Goodwill

Power Purchase Arrangements

Restricted Investments

Income Taxes

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

Asset Retirement Obligations

Environmental Liabilities

Stock Options and Other Compensation Programs

Employee Post-Retirement Benefits

Foreign Currency Transactions and Translation

Derivative Instruments and Hedging Activities

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

Long-Term Debt Transaction Costs

Guarantees

SEGMENTED INFORMATION (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment



year ended December 31, 2015	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total

Revenues	5,383		1,879		4,038		—		11,300
Income from equity investments	179		—		261		—		440
Plant operating costs and other	(1,736	)	(478	)	(766	)	(270	)	(3,250	)
Commodity purchases resold	—		—		(2,237	)	—		(2,237	)
Property taxes	(349	)	(79	)	(89	)	—		(517	)
Depreciation and amortization	(1,132	)	(266	)	(336	)	(31	)	(1,765	)
Asset impairment charges	—		(3,686	)	(59	)	—		(3,745	)
Loss on assets held for sale	(125	)	—		—		—		(125	)
Segmented earnings/(losses)	2,220		(2,630	)	812		(301	)	101
Interest expense									(1,370	)
Interest income and other									163
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	2,466		1,012		376		64		3,918
Capital projects in development	233		278		—		—		511
	2,699		1,290		376		64		4,429



year ended December 31, 2014	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total

Revenues	4,913		1,547		3,725		—		10,185
Income from equity investments	163		—		359		—		522
Plant operating costs and other	(1,501	)	(426	)	(919	)	(127	)	(2,973	)
Commodity purchases resold	—		—		(1,836	)	—		(1,836	)
Property taxes	(334	)	(62	)	(77	)	—		(473	)
Depreciation and amortization	(1,063	)	(216	)	(309	)	(23	)	(1,611	)
Gain on assets sold	9		—		108		—		117
Segmented earnings/(losses)	2,187		843		1,051		(150	)	3,931
Interest expense									(1,198	)
Interest income and other									91
Income before income taxes									2,824
Income tax expense									(831	)
Net income									1,993
Net income attributable to non-controlling interests									(153	)
Net income attributable to controlling interests									1,840
Preferred share dividends									(97	)
Net income attributable to common shares									1,743

Capital spending
Capital expenditures	1,768		1,469		206		46		3,489
Capital projects in development	368		480		—		—		848
	2,136		1,949		206		46		4,337



year ended December 31, 2013	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total

Revenues	4,497		1,124		3,176		—		8,797
Income from equity investments	145		—		452		—		597
Plant operating costs and other	(1,405	)	(328	)	(833	)	(108	)	(2,674	)
Commodity purchases resold	—		—		(1,317	)	—		(1,317	)
Property taxes	(329	)	(44	)	(72	)	—		(445	)
Depreciation and amortization	(1,027	)	(149	)	(293	)	(16	)	(1,485	)
Segmented earnings/(losses)	1,881		603		1,113		(124	)	3,473
Interest expense									(985	)
Interest income and other									34
Income before income taxes									2,522
Income tax expense									(611	)
Net income									1,911
Net income attributable to non-controlling interests									(125	)
Net income attributable to controlling interests									1,786
Preferred share dividends									(74	)
Net income attributable to common shares									1,712

Capital spending
Capital expenditures	1,776		2,286		152		50		4,264
Capital projects in development	245		243		—		—		488
	2,021		2,529		152		50		4,752



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Total Assets
Natural Gas Pipelines	31,072	27,103
Liquids Pipelines	16,046	16,116
Energy	15,558	14,197
Corporate	1,807	1,109
	64,483	58,525

Revenue from External Customers by Geographic Areas



year ended December 31	2015	2014	2013
(millions of Canadian $)	2015	2014	2013

Revenues
Canada – domestic	3,877	3,956	4,659
Canada – export	1,292	1,314	997
United States	5,872	4,718	3,029
Mexico	259	197	112
	11,300	10,185	8,797

Schedule of Long-Lived Assets by Country



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Plant, Property and Equipment
Canada	19,287	19,191
United States	21,899	20,098
Mexico	3,631	2,485
	44,817	41,774

OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2015

Other Assets [Abstract]

Schedule of Other Current Assets



at December 31		2014
(millions of Canadian $)	2015	2014

Cash held as collateral	585	423
Fair value of derivative contracts (Note 23)	442	409
Regulatory assets (Note 9)	85	16
Assets held for sale (Note 6)	20	—
Other	221	171
	1,353	1,019

ASSETS HELD FOR SALE (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Schedule of Assets Held for Sale



at December 31		2015
(millions of Canadian $)		2015

Assets Held for Sale
Accounts receivable		4
Inventories		1
Other current assets		1
Plant, property and equipment		14
Total Assets Held for Sale (included in Other current assets, Note 5)		20
Liabilities Related to Assets Held for Sale
Accounts payable and other		38
Other long-term liabilities		1
Total Liabilities Related to Assets Held for Sale (included in Accounts payable and other, Note 13)		39

PLANT, PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Schedule of Plant, Property and Equipment



	2015			2014
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Natural Gas Pipelines
Canadian Mainline
Pipeline	9,164	5,966	3,198	9,045	5,712	3,333
Compression	3,433	2,220	1,213	3,423	2,100	1,323
Metering and other	499	192	307	458	180	278
	13,096	8,378	4,718	12,926	7,992	4,934
Under construction	257	—	257	135	—	135
	13,353	8,378	4,975	13,061	7,992	5,069
NGTL System
Pipeline	8,456	3,820	4,636	8,185	3,619	4,566
Compression	2,188	1,404	784	2,055	1,318	737
Metering and other	1,096	489	607	1,032	446	586
	11,740	5,713	6,027	11,272	5,383	5,889
Under construction	969	—	969	413	—	413
	12,709	5,713	6,996	11,685	5,383	6,302
ANR¹
Pipeline	1,449	350	1,099	1,217	227	990
Compression	1,101	187	914	780	140	640
Metering and other	977	252	725	737	231	506
	3,527	789	2,738	2,734	598	2,136
Under construction	304	—	304	127	—	127
	3,831	789	3,042	2,861	598	2,263
Mexico
Pipeline	1,296	162	1,134	1,053	104	949
Compression	183	14	169	151	6	145
Metering and other	388	27	361	314	20	294
	1,867	203	1,664	1,518	130	1,388
Under construction	1,959	—	1,959	1,098	—	1,098
	3,826	203	3,623	2,616	130	2,486
Other Natural Gas Pipelines
GTN	2,278	765	1,513	1,842	588	1,254
Great Lakes	2,157	1,155	1,002	1,807	939	868
Foothills	1,606	1,162	444	1,671	1,180	491
Other²	2,223	572	1,651	1,800	363	1,437
	8,264	3,654	4,610	7,120	3,070	4,050
Under construction	71	—	71	34	—	34
	8,335	3,654	4,681	7,154	3,070	4,084
	42,054	18,737	23,317	37,377	17,173	20,204




Liquids Pipelines
Keystone
Pipeline	9,288	718	8,570	7,931	463	7,468
Pumping equipment	1,092	108	984	964	80	884
Tanks and other	3,034	228	2,806	2,282	144	2,138
	13,414	1,054	12,360	11,177	687	10,490
Under construction	1,826	—	1,826	4,438	—	4,438
	15,240	1,054	14,186	15,615	687	14,928
Energy
Natural Gas – Ravenswood	2,607	654	1,953	2,140	476	1,664
Natural Gas – Other^3,4	3,361	1,164	2,197	3,214	971	2,243
Hydro, Wind and Solar⁵	2,417	476	1,941	2,194	359	1,835
Natural Gas Storage and Other	740	132	608	717	118	599
	9,125	2,426	6,699	8,265	1,924	6,341
Under construction	430	—	430	149	—	149
	9,555	2,426	7,129	8,414	1,924	6,490
Corporate	267	82	185	232	80	152
	67,116	22,299	44,817	61,638	19,864	41,774


¹	TCO is excluded from the ANR net book value at December 31, 2015 as it has been classified as an asset held for sale. Refer to Note 6 for further information.


²	Includes Bison, Portland Natural Gas Transmission System (PNGTS), North Baja, Tuscarora and Ventures LP.


⁴	Includes Halton Hills, Coolidge, Bécancour, Ocean State Power, Mackay River and other natural gas-fired facilities.


⁵	Includes the acquisitions of four solar power facilities in 2014.

Summary of Keystone XL Impairment



at December 31, 2015	Estimated	Impairment charge
(millions of Canadian $)	Fair Value	Pre-tax	After-tax

Plant and equipment	463	1,460	1,391
Terminals, including KHT	158	274	219
Intangible assets	—	1,150	737
Capitalized interest	—	725	488
Future cancellation costs	—	77	56
	621	3,686	2,891

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Investments



(millions of Canadian $)	Ownership Interest at December 31, 2015		Income / (Loss) from Equity Investments				Equity Investments
			year ended December 31				at December 31
			2015		2014	2013	2015	2014

Natural Gas Pipelines
Northern Border^1,2			85		76	66	664	587
Iroquois	44.5	%	51		43	41	238	210
TQM	50.0	%	12		12	13	72	73
Other	Various		31		32	25	73	68
Liquids Pipelines
Grand Rapids	50.0	%	—		—	—	542	240
Canaport Energy East Marine Terminal	50.0	%	—		—	—	16	—
Energy
Bruce Power^3,4	48.5	%	249		314	310	4,200	3,995
ASTC Power Partnership	50.0	%	(23	)	8	110	21	29
Portlands Energy	50.0	%	30		36	31	321	335
Other	Various		5		1	1	67	61
			440		522	597	6,214	5,598


²	At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$117 million (2014 – US$117 million) due to the fair value assessment of assets at the time of acquisition.


⁴	At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $973 million (2014 – $776 million) due to the fair value assessment of assets at the time of acquisitions.

Summary of Financial Information of Equity Investments



year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Income
Revenues	4,337		4,814		4,989
Operating and other expenses	(3,254	)	(3,489	)	(3,536	)
Net income	1,046		1,264		1,390
Net income attributable to TransCanada	440		522		597



at December 31	2015		2014
(millions of Canadian $)	2015		2014

Balance Sheet
Current assets	1,530		1,412
Non-current assets	13,190		12,260
Current liabilities	(1,370	)	(1,067	)
Non-current liabilities	(3,116	)	(3,255	)

RATE-REGULATED BUSINESSES (Tables)

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities



at December 31	2015	2014	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)	2015	2014	Remaining Recovery/ Settlement Period (years)

Regulatory Assets
Deferred income taxes¹	848	1,001	n/a
Operating and debt-service regulatory assets²	47	4	1
Pensions and other post retirement benefits³	210	236	n/a
Foreign exchange on long-term debt⁵	54	—	1-14
Other⁴	110	72	n/a
	1,269	1,313
Less: Current portion included in Other current assets (Note 5)	85	16
	1,184	1,297
Regulatory Liabilities
Foreign exchange on long-term debt⁵	—	42	1-14
Operating and debt-service regulatory liabilities²	32	21	1
ANR-related post-employment and retirement benefits other than pension⁶	147	117	n/a
Long term adjustment account⁷	231	64	45
Pipeline abandonment costs⁸	285	—	n/a
Bridging amortization account⁹	456	—	15
Other⁴	52	49	n/a
	1,203	293
Less: Current portion included in Accounts payable and other (Note 13)	44	30
	1,159	263


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.


⁴	Pre-tax operating results in 2015 would have been $35 million lower (2014 – $2 million higher; 2013 – $2 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁵

⁶


⁷	Pre-tax operating results in 2015 would have been $167 million higher (2014 – $418 million higher; 2013 – $247 million lower) had these amounts not been recorded as regulatory liabilities.

⁸


⁹	Pre-tax operating results in 2015 would have been $456 million higher (2014 – nil; 2013 – nil) had these amounts not been recorded as regulatory liabilities.

GOODWILL (Tables)

12 Months Ended

Dec. 31, 2015

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 $)	Natural Gas Pipelines	Energy	Total

Balance at January 1, 2014	2,816	880	3,696
Foreign exchange rate changes	258	80	338
Balance at December 31, 2014	3,074	960	4,034
Foreign exchange rate changes	593	185	778
Balance at December 31, 2015	3,667	1,145	4,812

INTANGIBLE AND OTHER ASSETS (Tables)

12 Months Ended

Dec. 31, 2015

INTANGIBLES AND OTHER ASSETS

Schedule of Finite-Lived Intangible Assets

The following amounts related to PPAs are included in Intangible and other assets:



	2015			2014
at December 31	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
(millions of Canadian $)	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value

Sheerness (expires 2020)	585	390	195	585	351	234
Sundance A (expires 2017)	225	200	25	225	187	38
	810	590	220	810	538	272

Schedule of Other Assets



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Capital projects in development	1,814	1,286
PPAs	220	272
Fair value of derivative contracts (Note 23)	168	93
Loans and advances¹	159	167
Employee post-retirement benefits (Note 22)	18	14
Deferred income tax assets and charges (Note 15)	15	185
Other	797	629
	3,191	2,646

NOTES PAYABLE (Tables)

12 Months Ended

Dec. 31, 2015

Short-term Debt [Abstract]

Schedule of Notes Payable



	2015			2014
(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	697	0.8	%	1,540	1.2	%
U.S. (2015 – US$376; 2014 – US$800)	521	1.1	%	927	0.7	%
	1,218			2,467

Schedule of Credit Facilities

These unsecured credit facilities included the following:

year ended December 31

at December 31, 2015

2015

2014

2013

Amount

Unused Capacity

Borrower

Description

Matures

Cost to maintain

(millions of Canadian $)

$3 billion

TCPL

Committed, syndicated, revolving, extendible TCPL credit facility

December 2020

US$1 billion

TCPL

Committed, syndicated, revolving, extendible TCPL credit facility

December 2016

—

US$0.5 billion

TCPL USA

Committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL

December 2016

US$1.5 billion

TAIL/TCPM

Committed, syndicated, revolving, extendible TAIL/TCPM credit facility, guaranteed by TCPL

December 2016

—

$1.7 billion

$0.7 billion

TCPL/TCPL USA

Supports the issuance of letters of credit and provides additional liquidity

Demand

—

ACCOUNTS PAYABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2015

Payables and Accruals [Abstract]

Schedule of Accounts Payable and Other



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Trade payables	1,506	1,624
Fair value of derivative contracts (Note 23)	926	749
Dividends payable	385	359
Regulatory liabilities (Note 9)	44	30
Liabilities related to assets held for sale (Note 6)	39	—
Other	121	130
	3,021	2,892

OTHER LONG-TERM LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2015

Deferred Costs, Noncurrent [Abstract]

Schedule of Other Long-Term Liabilities



at December 31	2015	2014
(millions of Canadian $)	2015	2014

Fair value of derivative contracts (Note 23)	625	411
Employee post-retirement benefits (Note 22)	380	444
Asset retirement obligations	109	98
Guarantees (Note 26)	26	20
Other	120	79
	1,260	1,052

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Schedule of Provision for Income Taxes



year ended December 31	2015		2014	2013
(millions of Canadian $)	2015		2014	2013

Current
Canada	44		103	27
Foreign	92		42	16
	136		145	43
Deferred
Canada	33		309	245
Foreign	(135	)	377	323
	(102	)	686	568
Income Tax Expense	34		831	611

Schedule of Geographic Components of Income



year ended December 31	2015		2014	2013
(millions of Canadian $)	2015		2014	2013

Canada	(624	)	1,146	1,224
Foreign	(482	)	1,678	1,298
(Loss)/Income Before Income Taxes	(1,106	)	2,824	2,522

Reconciliation of Income Tax Expense



year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

(Loss)/Income before income taxes	(1,106	)	2,824		2,522
Federal and provincial statutory tax rate	26.0	%	25.0	%	25.0	%
Expected income tax (recovery)/expense	(288	)	706		631
Income tax differential related to regulated operations	159		129		(13	)
Higher effective foreign tax rates	14		25		33
Income from equity investments and non-controlling interests	(56	)	(38	)	(28	)
Tax rate and legislative changes	34		—		(25	)
Asset impairment charges¹	170		—		—
Other	1		9		13
Actual Income Tax Expense	34		831		611


¹	The asset impairment impact is net of $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	2015	2014
(millions of Canadian $)	2015	2014

Deferred Income Tax Assets
Difference in accounting and tax bases of impaired assets	916	—
Tax loss and credit carryforwards	1,327	1,344
Regulatory and other deferred amounts	231	236
Unrealized foreign exchange losses on long-term debt	589	140
Financial instruments	111	104
Other	136	149
	3,310	1,973
Less: Valuation allowance¹	1,060	125
	2,250	1,848
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,441	5,548
Equity investments	656	648
Taxes on future revenue requirement	227	253
Other	55	71
	7,379	6,520
Net Deferred Income Tax Liabilities	5,129	4,672


¹	In 2015, an increase to the valuation allowance of $935 million was recorded as the Company believes that it is more likely than not that the tax benefits related to the unrealized foreign exchange losses on long-term debt and unrealized losses on certain impaired assets will not be realized in the future.

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



at December 31	2015	2014¹
(millions of Canadian $)	2015	2014¹

Deferred Income Tax Assets
Intangible and other assets (Note 11)	15	185
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,144	4,857
Net Deferred Income Tax Liabilities	5,129	4,672


¹	As a result of retrospectively applying guidance on the presentation of deferred taxes on the Consolidated balance sheet on January 1, 2015, the Company reclassified its December 31, 2014 current Deferred income tax assets of $427 million, and current Deferred income tax liabilities of $4 million to its non-current Deferred income tax assets and liabilities.

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	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Unrecognized tax benefit at beginning of year	18		23		49
Gross increases – tax positions in prior years	2		3		3
Gross decreases – tax positions in prior years	(2	)	(8	)	(28	)
Gross increases – tax positions in current year	1		1		2
Lapses of statute of limitations	(2	)	(1	)	(3	)
Unrecognized Tax Benefit at End of Year	17		18		23

LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2015

Long-term Debt, Unclassified [Abstract]

Schedule of Long-Term Debt



		2015			2014
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate¹		Outstanding at December 31	Interest Rate¹
(millions of Canadian $, unless otherwise noted)	Maturity Dates	Outstanding at December 31	Interest Rate¹		Outstanding at December 31	Interest Rate¹

TRANSCANADA PIPELINES LIMITED
Debentures
Canadian	2017 to 2020	599	10.7	%	749	10.9	%
U.S. (2015 and 2014 – US$400)	2021	554	9.9	%	464	9.9	%
Medium-Term Notes
Canadian	2016 to 2041	5,192	5.3	%	4,048	5.7	%
Senior Unsecured Notes
U.S. (2015 – US$14,723; 2014 – US$13,526)	2016 to 2045	20,340	4.8	%	15,655	5.0	%
		26,685			20,916
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian²	2016 to 2024	325	11.5	%	325	11.5	%
U.S. (2015 and 2014 – US$200)	2023	277	7.9	%	232	7.9	%
Medium-Term Notes
Canadian	2025 to 2030	504	7.4	%	504	7.4	%
U.S. (2015 and 2014 – US$33)	2026	45	7.5	%	38	7.5	%
		1,151			1,099
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2015 and 2014 – US$432)	2021 to 2025	598	8.9	%	502	8.9	%
GAS TRANSMISSION NORTHWEST LLC
Unsecured Term Loan
U.S. (2015 – US$75)	2019	104	1.4	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$250; 2014 – US$325)	2020 to 2035	346	5.6	%	377	5.5	%
		450			377
TC PIPELINES, LP
Unsecured Loan
U.S. (2015 – US$200; 2014 – US$330)	2017	277	1.6	%	383	1.4	%
Unsecured Term Loan Facility
U.S. (2015 and 2014 – US$500)	2018	692	1.6	%	580	1.4	%
Unsecured Term Loan
U.S. (2015 – US$170)	2018	235	1.6	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$698; 2014 – US$350)	2021 to 2025	967	4.7	%	405	4.7	%
		2,171			1,368
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2015 – US$297; 2014 – US$316)	2018 to 2030	411	7.8	%	367	7.8	%




TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
U.S. (2015 – US$16; 2014 – US$20)	2017	22	4.0	%	23	4.0	%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes³
U.S. (2015 – US$69; 2014 – US$90)	2018	96	6.1	%	105	6.1	%
		31,584			24,757
Less: Current portion of Long-term debt		2,547			1,797
		29,037			22,960


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	Debentures issued by NGTL in the amount of $225 million have retraction provisions that entitle the holders to periodically require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions were made in 2015 or 2014.


³	Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

The Company issued Long-term debt over the three years ended December 31, 2015 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Issue date

Type

Maturity date

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

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

February 2014

Senior Unsecured Notes

March 2034

US 1,250

4.63

October 2013

Senior Unsecured Notes

October 2023

US 625

3.75

October 2013

Senior Unsecured Notes

October 2043

US 625

5.00

July 2013

Senior Unsecured Notes

June 2016

US 500

Floating

July 2013

Medium-Term Notes

July 2023

450

3.69

July 2013

Medium-Term Notes

November 2041

300

4.55

January 2013

Senior Unsecured Notes

January 2016

US 750

0.75

TC PIPELINES, LP

September 2015

Unsecured Term Loan

October 2018

US 170

Floating

March 2015

Senior Unsecured Notes

March 2025

US 350

4.375

July 2013

Unsecured Term Loan Facility

July 2018

US 500

Floating

GAS TRANSMISSION NORTHWEST LLC

June 2015

Unsecured Term Loan

June 2019

US 75

Floating

Schedule of Repayments of Long-Term Debt

At December 31, 2015, principal repayments on the Long-term debt of the Company for the next five years are approximately as follows:



(millions of Canadian $)	2016	2017	2018	2019	2020

Principal repayments on Long-term debt	2,547	2,150	3,379	1,228	1,801

Schedule of Retired Long-Term Debt

The Company retired Long-term debt over the three years ended December 31, 2015 as follows:



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

TRANSCANADA PIPELINES LIMITED
	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	%
	June 2014	Debentures	125	11.10	%
	February 2014	Medium-Term Notes	300	5.05	%
	January 2014	Medium-Term Notes	450	5.65	%
	August 2013	Senior Unsecured Notes	US 500	5.05	%
	June 2013	Senior Unsecured Notes	US 350	4.00	%
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Senior Unsecured Notes	US 75	5.09	%
NOVA GAS TRANSMISSION LTD.
	June 2014	Debentures	53	11.20	%

Schedule of Interest Expense

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



year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Interest on Long-term debt	1,487		1,317		1,216
Interest on Junior subordinated notes (Note 17)	116		70		65
Interest on short-term debt	16		15		12
Capitalized interest	(280	)	(259	)	(287	)
Amortization and other financial charges¹	31		55		(21	)
	1,370		1,198		985


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.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-SubTopic 30
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-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

JUNIOR SUBORDINATED NOTES (Tables)

12 Months Ended

Dec. 31, 2015

Junior Subordinated Notes [Abstract]

Schedule of Junior Subordinated Notes



		2015			2014
Outstanding loan amount	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
(millions of Canadian $, unless otherwise noted)	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate

TRANSCANADA PIPELINES LIMITED
U.S. (2015 and 2014 – US$1,000)¹	2067	1,384	6.4	%	1,160	6.5	%
U.S. (2015 – US$750)¹	2075	1,038	5.3	%	—	—
		2,422			1,160

NON-CONTROLLING INTERESTS (Tables)

12 Months Ended

Dec. 31, 2015

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	2015	2014
(millions of Canadian $)	2015	2014

Non-controlling interest in TC PipeLines, LP	1,590	1,479
Non-controlling interest in PNGTS	127	104
	1,717	1,583

The Company's Non-controlling interests included in the Consolidated statement of income are as follows:



year ended December 31	2015		2014	2013
(millions of Canadian $)	2015		2014	2013

Non-controlling interest in TC PipeLines, LP	(13	)	136	93
Non-controlling interest in PNGTS	19		15	12
Preferred shares of TCPL	—		2	20
	6		153	125

COMMON SHARES (Tables)

12 Months Ended

Dec. 31, 2015

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, 2013	705,461		12,069
Exercise of options	1,980		80
Outstanding at December 31, 2013	707,441		12,149
Exercise of options	1,221		53
Outstanding at December 31, 2014	708,662		12,202
Exercise of options	737		30
Repurchase of shares	(6,785	)	(130	)
Outstanding at December 31, 2015	702,614		12,102

Schedule of Weighted Average Shares



Weighted Average Common Shares Outstanding	2015	2014	2013
(millions)	2015	2014	2013

Basic	709	708	707
Diluted	709	710	708

Schedule of Stock Options Activity



	Number of Options		Weighted Average Exercise Price		Options Exercisable
	(thousands)				(thousands)

Outstanding at January 1, 2013	7,434			$37.69	4,568
Granted	1,939			$47.09
Exercised	(1,980	)		$36.12
Outstanding at December 31, 2013	7,393			$40.57	3,914
Granted	2,292			$49.03
Exercised	(1,221	)		$43.00
Outstanding at December 31, 2014	8,464			$43.17	4,556
Granted	2,214			$56.58
Exercised	(737	)		$36.14
Forfeited	(107	)		$50.74
Outstanding at December 31, 2015	9,834			$46.63	5,566

Schedule of Stock Options Outstanding and Exercisable by the Range of Exercise Price

Stock options outstanding at December 31, 2015 were as follows:



	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
	(thousands)			(years)	(thousands)			(years)

$31.93 to $36.26	970		$34.27	0.9	970		$34.27	0.9
$36.90 to $41.65	888		$37.91	2.1	888		$37.91	2.1
$41.95 to $45.29	1,759		$42.04	3.2	1,759		$42.04	3.2
$47.09	1,800		$47.09	4.1	1,195		$47.09	4.1
$49.03	2,242		$49.03	5.2	754		$49.03	5.2
$56.58	2,175		$56.58	6.2	—	—		0.0
	9,834		$46.63	4.1	5,566		$42.04	3.1

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	2015		2014		2013

Expected life (years)	5.8		6.0		6.0
Interest rate	1.1	%	1.8	%	1.7	%
Volatility¹	18	%	17	%	18	%
Dividend yield	3.7	%	3.8	%	3.7	%
Forfeiture rate	5	%	5	%	15	%


¹	Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.

Schedule of Additional Option Information

The following table summarizes additional stock option information:



year ended December 31	2015	2014	2013
(millions of Canadian $, unless otherwise noted)	2015	2014	2013

Total intrinsic value of options exercised	37	68	25
Fair value of options that have vested	91	95	64
Total options vested	2.0 million	1.7 million	1.3 million

PREFERRED SHARES (Tables)

12 Months Ended

Dec. 31, 2015

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

Schedule of Preferred Shares



at December 31	Number of Shares Authorized and Outstanding	Current Yield		Annual Dividend Per Share¹		Redemption Price Per Share²		Redemption and Conversion Option Date^2,3	Right to Convert Into^3,4	2015	2014
	(thousands)									(millions of Canadian $)⁶	(millions of Canadian $)⁶

Cumulative First Preferred Shares⁵
Series 1	9,498	3.266	%		$0.8165		$25.00	December 31, 2019	Series 2	233	233
Series 2	12,502	Floating⁷		Floating			$25.00	December 31, 2019	Series 1	306	306
Series 3	8,533	2.152	%		$0.538		$25.00	June 30, 2020	Series 4	209	343
Series 4	5,467	Floating⁷		Floating			$25.00	June 30, 2020	Series 3	134	—
Series 5	14,000	4.40	%		$1.10		$25.00	January 30, 2016	Series 6	342	342
Series 7	24,000	4.00	%		$1.00		$25.00	April 30, 2019	Series 8	589	589
Series 9	18,000	4.25	%		$1.0625		$25.00	October 30, 2019	Series 10	442	442
Series 11	10,000	3.80	%		$0.95		$25.00	November 30, 2020	Series 12	244	—
										2,499	2,255


¹	The holder is entitled to receive a fixed cumulative quarterly preferential dividend as and when declared by the Board with the exception of Series 2 and Series 4 preferred shares. The holders of Series 2 and Series 4 preferred shares are entitled to receive quarterly floating rate cumulative preferential dividends as and when declared by the Board.


³	The holder 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.

⁴

⁵


⁶	Net of underwriting commissions and deferred income taxes.


⁷	Commencing December 31, 2015, the floating quarterly dividend rate for the Series 2 preferred shares is 2.418 per cent and the Series 4 preferred shares is 1.778 per cent for the period starting December 31, 2015 to, but excluding, March 31, 2016. These rates will reset each quarter going forward.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21484-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21488-112644

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 30
-Article 5

+ Details

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

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Components of Other Comprehensive Income/(Loss)

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



year ended December 31, 2015	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount

Foreign currency translation gains on net investment in foreign operations	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 to net income of actuarial gains and losses and prior service costs 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



year ended December 31, 2014	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount

Foreign currency translation gains on net investment in foreign operations	462		55		517
Change in fair value of net investment hedges	(373	)	97		(276	)
Change in fair value of cash flow hedges	(118	)	49		(69	)
Reclassification to net income of gains and losses on cash flow hedges	(95	)	40		(55	)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(146	)	44		(102	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	25		(7	)	18
Other comprehensive loss on equity investments	(272	)	68		(204	)
Other Comprehensive Loss	(517	)	346		(171	)



year ended December 31, 2013	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
Foreign currency translation gains on net investment in foreign operations	269		114		383
Change in fair value of net investment hedges	(323	)	84		(239	)
Change in fair value of cash flow hedges	121		(50	)	71
Reclassification to net income of gains and losses on cash flow hedges	60		(19	)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	96		(29	)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	34		(11	)	23
Other comprehensive income on equity investments	313		(79	)	234
Other Comprehensive Income	570		10		580

Schedule of Changes in Accumulated Other Comprehensive Income

The changes in AOCI by component are as follows:



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

AOCI balance at January 1, 2013	(707	)	(116	)	(287	)	(338	)	(1,448	)
Other comprehensive income before reclassifications²	78		71		67		219		435
Amounts reclassified from accumulated other comprehensive loss	—		41		23		15		79
Net current period other comprehensive income	78		112		90		234		514
AOCI balance at December 31, 2013	(629	)	(4	)	(197	)	(104	)	(934	)
Other comprehensive income/(loss) before reclassifications²	111		(69	)	(102	)	(206	)	(266	)
Amounts reclassified from accumulated other comprehensive loss	—		(55	)	18		2		(35	)
Net current period other comprehensive income/(loss)	111		(124	)	(84	)	(204	)	(301	)
AOCI balance at December 31, 2014	(518	)	(128	)	(281	)	(308	)	(1,235	)
Other comprehensive income/(loss) before reclassifications²	135		(57	)	51		33		162
Amounts reclassified from accumulated other comprehensive loss³	—		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	)


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


²	Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $306 million in 2015 (2014 – $130 million gains; 2013 – $66 million gains).

Schedule of Reclassifications out of Accumulated Other Comprehensive Income

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



	Amounts Reclassified From Accumulated Other Comprehensive Loss¹						Affected Line Item in the Consolidated Statement of Income
year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Cash flow hedges
Commodities	(128	)	111		(44	)	Revenues (Energy)
Interest	(16	)	(16	)	(16	)	Interest expense
	(144	)	95		(60	)	Total before tax
	56		(40	)	19		Income tax expense/(recovery)
	(88	)	55		(41	)	Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial loss and past service cost	(41	)	(25	)	(34	)	²
	9		7		11		Income tax recovery
	(32	)	(18	)	(23	)	Net of tax
Equity investments
Equity income	(19	)	(2	)	(20	)	Income from equity investments
	5		—		5		Income tax recovery
	(14	)	(2	)	(15	)	Net of tax


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


²	These Accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 22 for further information.

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [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	2015	2014	2013
(millions of Canadian $)	2015	2014	2013

DB Plans	96	73	79
Other post-retirement benefit plans	6	6	6
Savings and DC Plans	41	37	29
	143	116	114

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

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



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014

Change in Benefit Obligation¹
Benefit obligation – beginning of year	2,658		2,224		216		191
Service cost	108		85		3		2
Interest cost	115		113		10		10
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Actuarial (gain)/loss	(57	)	302		(11	)	14
Foreign exchange rate changes	81		32		14		6
Benefit obligation – end of year	2,780		2,658		225		216
Change in Plan Assets
Plan assets at fair value – beginning of year	2,398		2,152		39		35
Actual return on plan assets	160		246		(1	)	2
Employer contributions²	96		73		6		6
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Foreign exchange rate changes	62		25		8		3
Plan assets at fair value – end of year	2,591		2,398		45		39
Funded Status – Plan Deficit	(189	)	(260	)	(180	)	(177	)


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 $214 million in letters of credit provided to the Canadian DB Plans for funding purposes (2014 – $181 million).

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

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



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014

Intangible and other assets (Note 11)	—		—		18		14
Accounts payable and other	—		—		(7	)	(7	)
Other long-term liabilities (Note 14)	(189	)	(260	)	(191	)	(184	)
	(189	)	(260	)	(180	)	(177	)

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

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



at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014

Projected benefit obligation¹	(2,780	)	(2,658	)	(198	)	(191	)
Plan assets at fair value	2,591		2,398		—		—
Funded Status – Plan Deficit	(189	)	(260	)	(198	)	(191	)


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	2015		2014
(millions of Canadian $)	2015		2014

Accumulated benefit obligation	(2,600	)	(2,437	)
Plan assets at fair value	2,591		2,398
Funded Status – Plan Deficit	(9	)	(39	)

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	2015		2014
(millions of Canadian $)	2015		2014

Accumulated benefit obligation	(807	)	(715	)
Plan assets at fair value	680		597
Funded Status – Plan Deficit	(127	)	(118	)

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

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



	Percentage of Plan Assets				Target Allocations
at December 31	2015		2014		2015

Debt securities	34	%	31	%	25% to 35%
Equity securities	66	%	69	%	50% to 70%
Alternatives	—		—		5 % to 15%
	100	%	100	%

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

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



at December 31			Percentage of Plan Assets
(millions of Canadian $)	2015	2014	2015		2014

Debt securities	2	1	0.1	%	0.1	%
Equity securities	4	1	0.1	%	0.1	%

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



at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $)	2015	2014	2015	2014	2015	2014	2015	2014	2015	2014

Asset Category
Cash and Cash Equivalents	44	20	2	—	—	—	46	20	2	1
Equity Securities:
Canadian	317	361	147	142	—	—	464	503	17	21
U.S.	589	516	40	35	—	—	629	551	24	23
International	38	218	300	147	—	—	338	365	13	15
Global	—	—	154	141	—	—	154	141	6	6
Emerging	7	7	143	80	—	—	150	87	6	3
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	206	218	—	—	206	218	8	9
Provincial	—	—	202	180	—	—	202	180	8	7
Municipal	—	—	7	7	—	—	7	7	—	—
Corporate	—	—	113	76	—	—	113	76	4	3
U.S. Bonds:
State	—	—	50	47	—	—	50	47	2	2
Corporate	—	—	57	59	—	—	57	59	2	2
International:
Corporate	—	—	25	14	—	—	25	14	1	1
Mortgage backed	—	—	58	39	—	—	58	39	2	2
Other Investments:
Private equity funds	—	—	—	—	14	13	14	13	—	—
Funds held on deposit	123	117	—	—	—	—	123	117	5	5
	1,118	1,239	1,504	1,185	14	13	2,636	2,437	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)	Private Equity Funds

Balance at December 31, 2013	18
Purchases and sales	(7	)
Realized and unrealized gains	2
Balance at December 31, 2014	13
Purchases and sales	(1	)
Realized and unrealized gains	2
Balance at December 31, 2015	14

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

2016	129	8
2017	133	9
2018	138	9
2019	142	9
2020	146	10
2021 to 2025	808	51

Schedule of Weighted Average Assumptions Used in Calculating Benefit Obligation

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



	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31	2015		2014		2015		2014

Discount rate	4.20	%	4.15	%	4.40	%	4.20	%
Rate of compensation increase	0.50	%	3.15	%	—	%	—	%

Schedule of Significant Weighted Average Actuarial Assumptions Adopted in Measuring Net Benefit Plan Costs

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



	Pension Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2015		2014		2013		2015		2014		2013

Discount rate	4.15	%	4.95	%	4.35	%	4.20	%	5.00	%	4.35	%
Expected long-term rate of return on plan assets	6.95	%	6.90	%	6.70	%	4.60	%	4.60	%	4.60	%
Rate of compensation increase	3.15	%	3.15	%	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	14	(12	)

Schedule of Net Benefit Costs

The Company's net benefit cost recognized is as follows:



at December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2013		2015		2014		2013

Service cost	108		85		84		3		2		2
Interest cost	115		113		96		10		10		7
Expected return on plan assets	(155	)	(139	)	(120	)	(2	)	(2	)	(2	)
Amortization of actuarial loss	35		21		30		3		2		2
Amortization of past service cost	2		2		2		1		—		—
Amortization of regulatory asset	23		18		30		1		1		1
Amortization of transitional obligation related to regulated business	—		—		—		2		2		2
Net Benefit Cost Recognized	128		100		122		18		15		12

Schedule of the Pre-Tax Amounts Recognized in AOCI

Pre-tax amounts recognized in AOCI were as follows:



	2015		2014		2013
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits

Net loss	247	28	348	39	236	32
Prior service cost	—	—	2	1	3	1
	247	28	350	40	239	33

Schedule of the Pre-Tax Amounts Recognized in OCI

Pre-tax amounts recognized in OCI were as follows:



	2015				2014				2013
at December 31	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits
(millions of Canadian $)	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits

Amortization of net loss from AOCI to OCI	(34	)	(4	)	(21	)	(2	)	(30	)	(2	)
Amortization of prior service costs from AOCI to OCI	(2	)	(1	)	(2	)	—		(2	)	—
Funded status adjustment	(67	)	(7	)	137		9		(96	)	—
	(103	)	(12	)	114		7		(128	)	(2	)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2015

Derivative financial instruments

Summary of Derivative Instruments

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



at December 31, 2015	Power	Natural Gas	Foreign Exchange	Interest

Purchases¹	70,331	133	—	—
Sales¹	54,382	70	—	—
Millions of dollars	—	—	US 1,476	US 1,100
Maturity dates	2016–2020	2016–2020	2016	2016–2019


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



at December 31, 2014	Power	Natural Gas	Foreign Exchange	Interest

Purchases¹	53,217	60	—	—
Sales¹	39,429	38	—	—
Millions of dollars	—	—	US 1,374	US 650
Maturity dates	2015–2019	2015–2020	2015	2015–2018


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

Schedule of Financial Instruments

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2015 is as follows:



at December 31, 2015	Cash Flow Hedges¹		Fair Value Hedges¹		Net Investment Hedges¹		Held for Trading¹		Total Fair Value of Derivative Instruments
(millions of Canadian $)	Cash Flow Hedges¹		Fair Value Hedges¹		Net Investment Hedges¹		Held for Trading¹		Total Fair Value of Derivative Instruments

Other current assets (Note 5)
Commodities²	46		—		—		326		372
Foreign exchange	—		—		65		2		67
Interest rate	—		1		—		2		3
	46		1		65		330		442
Intangible and other assets (Note 11)
Commodities²	11		—		—		126		137
Foreign exchange	—		—		29		—		29
Interest rate	—		2		—		—		2
	11		2		29		126		168
Total Derivative Assets	57		3		94		456		610

Accounts payable and other (Note 13)
Commodities²	(112	)	—		—		(443	)	(555	)
Foreign exchange	—		—		(313	)	(54	)	(367	)
Interest rate	(1	)	(1	)	—		(2	)	(4	)
	(113	)	(1	)	(313	)	(499	)	(926	)
Other long-term liabilities (Note 14)
Commodities²	(31	)	—		—		(131	)	(162	)
Foreign exchange	—		—		(461	)	—		(461	)
Interest rate	(1	)	(1	)	—		—		(2	)
	(32	)	(1	)	(461	)	(131	)	(625	)
Total Derivative Liabilities	(145	)	(2	)	(774	)	(630	)	(1,551	)


¹	Fair value equals carrying value.


²	Includes purchases and sales of power and natural gas.

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2014 is as follows:



at December 31, 2014	Cash Flow Hedges¹		Fair Value Hedges¹	Net Investment Hedges¹		Held for Trading¹		Total Fair Value of Derivative Instruments
(millions of Canadian $)	Cash Flow Hedges¹		Fair Value Hedges¹	Net Investment Hedges¹		Held for Trading¹		Total Fair Value of Derivative Instruments

Other current assets (Note 5)
Commodities²	39		—	—		359		398
Foreign exchange	—		—	5		1		6
Interest rate	—		2	—		3		5
	39		2	5		363		409
Intangible and other assets (Note 11)
Commodities²	18		—	—		72		90
Foreign exchange	—		—	1		—		1
Interest rate	—		1	—		1		2
	18		1	1		73		93
Total Derivative Assets	57		3	6		436		502

Accounts payable and other (Note 13)
Commodities²	(136	)	—	—		(422	)	(558	)
Foreign exchange	—		—	(155	)	(32	)	(187	)
Interest rate	(1	)	—	—		(3	)	(4	)
	(137	)	—	(155	)	(457	)	(749	)
Other long-term liabilities (Note 14)
Commodities²	(27	)	—	—		(72	)	(99	)
Foreign exchange	—		—	(310	)	—		(310	)
Interest rate	(1	)	—	—		(1	)	(2	)
	(28	)	—	(310	)	(73	)	(411	)
Total Derivative Liabilities	(165	)	—	(465	)	(530	)	(1,160	)


¹	Fair value equals carrying value.


²	Includes purchases and sales of power and natural gas.



	2015				2014
at December 31	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions of Canadian $)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Notes receivable¹	214		265		213		263
Current and Long-term debt^2,3 (Note 16)	(31,584	)	(34,309	)	(24,757	)	(28,713	)
Junior subordinated notes (Note 17)	(2,422	)	(2,011	)	(1,160	)	(1,157	)
	(33,792	)	(36,055	)	(25,704	)	(29,607	)


¹	Notes receivable are included in Other current assets and Intangible and other assets on the Consolidated balance sheet.


²	Long-term debt is recorded at amortized cost, except for US$850 million (2014 – US$400 million) that is attributed to hedged risk and recorded at fair value.

Available for Sale Assets Summary

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



	2015		2014
at December 31	LMCI Restricted Investments¹	Other Restricted Investments²	LMCI Restricted Investments¹	Other Restricted Investments²
(millions of Canadian $)	LMCI Restricted Investments¹	Other Restricted Investments²	LMCI Restricted Investments¹	Other Restricted Investments²

Fair values
Fixed income securities (maturing within 5 years)	—	90	—	75
Fixed income securities (maturing after 10 years)	261	—	—	—
	261	90	—	75


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 would record these gains and losses as regulatory assets or liabilities. In 2015 and 2014, there were no net realized or unrealized gains or losses on LMCI restricted investments.


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. In 2015 and 2014, there were no net realized or unrealized gains or losses on other restricted investments.

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	2015		2014
(millions of Canadian $)	2015		2014

Derivative instruments held for trading¹
Amount of unrealized losses in the year
Commodities	(37	)	(40	)
Foreign exchange	(21	)	(20	)
Amount of realized losses in the year
Commodities	(151	)	(28	)
Foreign exchange	(112	)	(28	)
Derivative instruments in hedging relationships^2,3
Amount of realized (losses)/gains in the year
Commodities	(179	)	130
Interest rate	8		4


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 2015, net realized gains on fair value hedges were $11 million (2014 – gains of $7 million) and were included in Interest expense.


³	In 2015 and 2014, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships

The components of OCI (Note 21) related to derivatives in cash flow hedging relationships are as follows:



year ended December 31	2015		2014
(millions of Canadian $, pre-tax)	2015		2014

Change in fair value of derivative instruments recognized in OCI (effective portion)¹
Commodities	(92	)	(128	)
Foreign exchange	—		10
	(92	)	(118	)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net income (effective portion)¹
Commodities²	128		(111	)
Interest rate³	16		16
	144		(95	)
Losses on derivative instruments recognized in Net income (ineffective portion)
Commodities²	—		(13	)


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


²	Reported within Revenues on the 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:



at December 31, 2015	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts

Derivative - Asset
Commodities	509		(418	)	91
Foreign exchange	96		(93	)	3
Interest rate	5		(1	)	4
	610		(512	)	98
Derivative - Liability
Commodities	(717	)	418		(299	)
Foreign exchange	(828	)	93		(735	)
Interest rate	(6	)	1		(5	)
	(1,551	)	512		(1,039	)


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



at December 31, 2014	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts

Derivative - Asset
Commodities	488		(387	)	101
Foreign exchange	7		(7	)	—
Interest rate	7		(1	)	6
	502		(395	)	107
Derivative - Liability
Commodities	(657	)	387		(270	)
Foreign exchange	(497	)	7		(490	)
Interest rate	(6	)	1		(5	)
	(1,160	)	395		(765	)


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:



at December 31, 2015	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts

Derivative - Asset
Commodities	509		(418	)	91
Foreign exchange	96		(93	)	3
Interest rate	5		(1	)	4
	610		(512	)	98
Derivative - Liability
Commodities	(717	)	418		(299	)
Foreign exchange	(828	)	93		(735	)
Interest rate	(6	)	1		(5	)
	(1,551	)	512		(1,039	)


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



at December 31, 2014	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts
(millions of Canadian $)	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset¹		Net Amounts

Derivative - Asset
Commodities	488		(387	)	101
Foreign exchange	7		(7	)	—
Interest rate	7		(1	)	6
	502		(395	)	107
Derivative - Liability
Commodities	(657	)	387		(270	)
Foreign exchange	(497	)	7		(490	)
Interest rate	(6	)	1		(5	)
	(1,160	)	395		(765	)


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 fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2015, are categorized as follows:



at December 31, 2015	Quoted Prices in Active Markets Level I¹		Significant Other Observable Inputs Level II¹		Significant Unobservable Inputs Level III¹		Total
(millions of Canadian $)	Quoted Prices in Active Markets Level I¹		Significant Other Observable Inputs Level II¹		Significant Unobservable Inputs Level III¹		Total

Derivative Instrument Assets:
Commodities	34		462		13		509
Foreign exchange	—		96		—		96
Interest rate	—		5		—		5
Derivative Instrument Liabilities:
Commodities	(102	)	(611	)	(4	)	(717	)
Foreign exchange	—		(828	)	—		(828	)
Interest rate	—		(6	)	—		(6	)
	(68	)	(882	)	9		(941	)


¹	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2015.

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2014, are categorized as follows:



at December 31, 2014	Quoted Prices in Active Markets Level I¹		Significant Other Observable Inputs Level II¹		Significant Unobservable Inputs Level III¹		Total
(millions of Canadian $)	Quoted Prices in Active Markets Level I¹		Significant Other Observable Inputs Level II¹		Significant Unobservable Inputs Level III¹		Total

Derivative Instrument Assets:
Commodities	40		441		7		488
Foreign exchange	—		7		—		7
Interest rate	—		7		—		7
Derivative Instrument Liabilities:
Commodities	(86	)	(568	)	(3	)	(657	)
Foreign exchange	—		(497	)	—		(497	)
Interest rate	—		(6	)	—		(6	)
	(46	)	(616	)	4		(658	)


¹	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2014.

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 as Level III of the fair value hierarchy:



(millions of Canadian $, pre-tax)	2015		2014

Balance at beginning of year	4		1
Transfers out of Level III	5		—
Total gains included in Net income	3		3
Sales	(2	)	—
Settlements	(1	)	—
Balance at end of year¹	9		4


¹	Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2015 of $7 million (2014 – $3 million).

Designated as a net investment hedge

Derivative financial instruments

Summary of Derivative Instruments

U.S. Dollar-Denominated Debt Designated as a Net Investment Hedge



at December 31	2015	2014
(millions of Canadian $, unless otherwise noted)	2015	2014

Carrying value	23,000 (US 16,600)	17,000 (US 14,700)
Fair value	23,800 (US 17,200)	19,000 (US 16,400)

Derivatives Designated as a Net Investment Hedge



	2015				2014
at December 31	Fair Value¹		Notional or Principal Amount		Fair Value¹		Notional or Principal Amount
(millions of Canadian $, unless otherwise noted)	Fair Value¹		Notional or Principal Amount		Fair Value¹		Notional or Principal Amount

U.S. dollar cross-currency interest rate swaps (maturing 2016 to 2019)²	(730	)	US	3,150	(431	)	US	2,900
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	50		US	1,800	(28	)	US	1,400
	(680	)	US	4,950	(459	)	US	4,300


¹	Fair values equal carrying values.


²	In 2015, net realized gains of $8 million (2014 – gains of $21 million) related to the interest component of cross-currency swap settlements are included in Interest expense.

CHANGES IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2015

CHANGES IN OPERATING WORKING CAPITAL

Schedule of changes in operating working capital



year ended December 31	2015		2014		2013
(millions of Canadian $)	2015		2014		2013

Increase in Accounts receivable	(66	)	(189	)	(54	)
Increase in Inventories	(3	)	(28	)	(30	)
(Increase)/decrease in Other current assets	(267	)	(385	)	40
(Decrease)/increase in Accounts payable and other	(153	)	377		(290	)
Increase in Accrued interest	91		36		8
Increase in Operating Working Capital	(398	)	(189	)	(326	)

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Annual Payments



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

2016	354	46	308
2017	355	45	310
2018	270	26	244
2019	248	24	224
2020	185	20	165
2021 and thereafter	311	1	310
	1,723	162	1,561

Schedule of Generating Capacities and Expiry Dates of the PPAs

The generating capacities and expiry dates of the PPAs are as follows:



	MW	Expiry Date

Sundance A	560	December 31, 2017
Sheerness	756	December 31, 2020

Schedule of Guarantees

Information regarding the Company’s guarantees is as follows:



		2015		2014
year ended December 31	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value
(millions of Canadian $)	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value

Bruce Power	Ranging to 2018²	88	2	634	6
Other jointly owned entities	Ranging to 2040	139	24	104	14
		227	26	738	20


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


²	Except for one guarantee with no termination date.

DESCRIPTION OF TRANSCANADA'S BUSINESS (Details)	12 Months Ended
DESCRIPTION OF TRANSCANADA'S BUSINESS (Details)	Dec. 31, 2015 plant segment facility mi km Bcf
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of business segments in which the entity operates \| segment	3
Investments of regulated natural gas pipelines (in kilometers) \| km	67,300
Investments of regulated natural gas pipelines (in miles) \| mi	41,900
Investments of regulated natural gas storage facilities (in billion cubic feet) \| Bcf	250
Wholly owned and operated crude oil pipeline systems (in kilometers) \| km	4,247
Wholly owned and operated crude oil pipeline systems (in miles) \| mi	2,639
Number of electrical power generation plants \| plant	19
Number of non-regulated natural gas storage facilities \| facility	2

ACCOUNTING POLICIES (Details)	12 Months Ended
ACCOUNTING POLICIES (Details)	Dec. 31, 2015 level
Annual review for goodwill impairment
Number of levels below operating segments level considered for measuring reporting unit level	1
Employee Post-Retirement Benefits
Moving average period of basis used to determine expected return on plan assets	5 years
Corporate \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	3.00%
Corporate \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	20.00%
Natural Gas Pipelines \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	1.00%
Natural Gas Pipelines \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	6.00%
Natural Gas Pipelines \| Compression \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	1.00%
Natural Gas Pipelines \| Compression \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	6.00%
Liquids Pipelines \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.00%
Liquids Pipelines \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.50%
Liquids Pipelines \| Pumping equipment \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.00%
Liquids Pipelines \| Pumping equipment \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	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	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	20.00%

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	12 Months Ended
SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segmented information
Revenues	$ 11,300	$ 10,185	$ 8,797
Income from Equity Investments (Note 8)	440	522	597
Plant operating costs and other	(3,250)	(2,973)	(2,674)
Commodity purchases resold	(2,237)	(1,836)	(1,317)
Property taxes	(517)	(473)	(445)
Depreciation and amortization	(1,765)	(1,611)	(1,485)
Asset impairment charges	(3,745)	0	0
Gain (Loss) on assets held for sale	(125)	117	0
Segmented earnings/(losses)	101	3,931	3,473
Interest expense	(1,370)	(1,198)	(985)
Interest income and other	163	91	34
(Loss)/Income before Income Taxes	(1,106)	2,824	2,522
Income tax expense	(34)	(831)	(611)
Net (Loss)/Income	(1,140)	1,993	1,911
Net income attributable to non-controlling interests	(6)	(153)	(125)
Net (Loss)/Income Attributable to Controlling Interests	(1,146)	1,840	1,786
Preferred share dividends	(94)	(97)	(74)
Net (Loss)/Income Attributable to Common Shares	(1,240)	1,743	1,712
Capital spending
Capital expenditures	3,918	3,489	4,264
Capital projects in development	511	848	488
Payments to Acquire Productive Assets	4,429	4,337	4,752
Assets	64,483	58,525
GEOGRAPHIC INFORMATION
Revenues	11,300	10,185	8,797
Plant, Property and Equipment (Note 7)	44,817	41,774
Canada
GEOGRAPHIC INFORMATION
Plant, Property and Equipment (Note 7)	19,287	19,191
Canada - domestic
Segmented information
Revenues	3,877	3,956	4,659
GEOGRAPHIC INFORMATION
Revenues	3,877	3,956	4,659
Canada - export
Segmented information
Revenues	1,292	1,314	997
GEOGRAPHIC INFORMATION
Revenues	1,292	1,314	997
United States
Segmented information
Revenues	5,872	4,718	3,029
GEOGRAPHIC INFORMATION
Revenues	5,872	4,718	3,029
Plant, Property and Equipment (Note 7)	21,899	20,098
Mexico
Segmented information
Revenues	259	197	112
GEOGRAPHIC INFORMATION
Revenues	259	197	112
Plant, Property and Equipment (Note 7)	3,631	2,485
Corporate
Segmented information
Plant operating costs and other	(270)	(127)	(108)
Depreciation and amortization	(31)	(23)	(16)
Segmented earnings/(losses)	(301)	(150)	(124)
Capital spending
Capital expenditures	64	46	50
Payments to Acquire Productive Assets	64	46	50
Assets	1,807	1,109
GEOGRAPHIC INFORMATION
Plant, Property and Equipment (Note 7)	185	152
Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	5,383	4,913	4,497
Income from Equity Investments (Note 8)	179	163	145
Plant operating costs and other	(1,736)	(1,501)	(1,405)
Property taxes	(349)	(334)	(329)
Depreciation and amortization	(1,132)	(1,063)	(1,027)
Gain (Loss) on assets held for sale	(125)	9
Segmented earnings/(losses)	2,220	2,187	1,881
Capital spending
Capital expenditures	2,466	1,768	1,776
Capital projects in development	233	368	245
Payments to Acquire Productive Assets	2,699	2,136	2,021
Assets	31,072	27,103
GEOGRAPHIC INFORMATION
Revenues	5,383	4,913	4,497
Plant, Property and Equipment (Note 7)	23,317	20,204
Natural Gas Pipelines \| Operating segments \| Mexico
GEOGRAPHIC INFORMATION
Plant, Property and Equipment (Note 7)	3,623	2,486
Liquids Pipelines \| Operating segments
Segmented information
Revenues	1,879	1,547	1,124
Plant operating costs and other	(478)	(426)	(328)
Property taxes	(79)	(62)	(44)
Depreciation and amortization	(266)	(216)	(149)
Asset impairment charges	(3,686)
Segmented earnings/(losses)	(2,630)	843	603
Capital spending
Capital expenditures	1,012	1,469	2,286
Capital projects in development	278	480	243
Payments to Acquire Productive Assets	1,290	1,949	2,529
Assets	16,046	16,116
GEOGRAPHIC INFORMATION
Revenues	1,879	1,547	1,124
Plant, Property and Equipment (Note 7)	14,186	14,928
Energy \| Operating segments
Segmented information
Revenues	4,038	3,725	3,176
Income from Equity Investments (Note 8)	261	359	452
Plant operating costs and other	(766)	(919)	(833)
Commodity purchases resold	(2,237)	(1,836)	(1,317)
Property taxes	(89)	(77)	(72)
Depreciation and amortization	(336)	(309)	(293)
Asset impairment charges	(59)
Gain (Loss) on assets held for sale		108
Segmented earnings/(losses)	812	1,051	1,113
Capital spending
Capital expenditures	376	206	152
Payments to Acquire Productive Assets	376	206	152
Assets	15,558	14,197
GEOGRAPHIC INFORMATION
Revenues	4,038	3,725	$ 3,176
Plant, Property and Equipment (Note 7)	$ 7,129	$ 6,490

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Assets [Abstract]
Cash held as collateral	$ 585	$ 423
Fair value of derivative contracts (Note 23)	442	409
Regulatory assets (Note 9)	85	16
Assets held for sale (Note 6)	20	0
Other	221	171
Other current assets, total	$ 1,353	$ 1,019

ASSETS HELD FOR SALE (Details) - CAD ($) $ in Millions		12 Months Ended
ASSETS HELD FOR SALE (Details) - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assets Held for Sale
Accounts receivable	$ 4	$ 4
Inventories	1	1
Other current assets	1	1
Plant, property and equipment	14	14
Total Assets Held for Sale (included in Other current assets, Note 5)	20	20	$ 0
Liabilities Related to Assets Held for Sale
Accounts payable and other	38	38
Other long-term liabilities	1	1
Total Liabilities Related to Assets Held for Sale (included in Accounts payable and other, Note 13)	39	39	0
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal		$ (125)	$ 117	$ 0
TC Offshore LLC \| Disposal group, not discontinued operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal	$ (125)

PLANT, PROPERTY AND EQUIPMENT (Details) $ in Millions		12 Months Ended
PLANT, PROPERTY AND EQUIPMENT (Details) $ in Millions	Dec. 31, 2015 CAD ($)	Dec. 31, 2015 CAD ($)	Dec. 31, 2014 CAD ($) facility	Dec. 31, 2013 CAD ($)
Plant, property and equipment
Cost	$ 67,116	$ 67,116	$ 61,638
Accumulated Depreciation	22,299	22,299	19,864
Net Book Value	44,817	44,817	41,774
Energy Turbine
Plant, property and equipment
Impairment charge, Pre-tax	59
Impairment charge, After-tax	43
Keystone XL
Plant, property and equipment
Impairment charge, Pre-tax	3,686
Impairment charge, After-tax	2,891
Keystone XL \| Significant Unobservable Inputs (Level III)
Plant, property and equipment
Estimated Fair Value	621	621
Keystone XL \| Plant and equipment
Plant, property and equipment
Impairment charge, Pre-tax	1,460
Impairment charge, After-tax	1,391
Keystone XL \| Plant and equipment \| Market Approach Valuation Technique \| Significant Unobservable Inputs (Level III)
Plant, property and equipment
Estimated Fair Value	$ 463	463
Disposal period	2 years
Keystone XL \| Terminals, including KHT
Plant, property and equipment
Impairment charge, Pre-tax	$ 274
Impairment charge, After-tax	219
Keystone XL \| Terminals, including KHT \| Significant Unobservable Inputs (Level III)
Plant, property and equipment
Estimated Fair Value	158	158
Keystone XL \| Intangible assets
Plant, property and equipment
Impairment charge, Pre-tax	1,150
Impairment charge, After-tax	737
Keystone XL \| Capitalized interest
Plant, property and equipment
Impairment charge, Pre-tax	725
Impairment charge, After-tax	488
Keystone XL \| Future cancellation costs
Plant, property and equipment
Impairment charge, Pre-tax	77
Impairment charge, After-tax	56
Mexico
Plant, property and equipment
Net Book Value	3,631	3,631	2,485
Energy \| Facilities under PPAs
Plant, property and equipment
Cost	813	813	695
Accumulated Depreciation	142	142	103
Revenues recognized through the sale of electricity		93	81	$ 78
Operating segments \| Natural Gas Pipelines
Plant, property and equipment
Cost	42,054	42,054	37,377
Accumulated Depreciation	18,737	18,737	17,173
Net Book Value	23,317	23,317	20,204
Operating segments \| Natural Gas Pipelines \| Mexico
Plant, property and equipment
Cost	3,826	3,826	2,616
Accumulated Depreciation	203	203	130
Net Book Value	3,623	3,623	2,486
Operating segments \| Natural Gas Pipelines \| Pipeline \| Mexico
Plant, property and equipment
Cost	1,296	1,296	1,053
Accumulated Depreciation	162	162	104
Net Book Value	1,134	1,134	949
Operating segments \| Natural Gas Pipelines \| Compression \| Mexico
Plant, property and equipment
Cost	183	183	151
Accumulated Depreciation	14	14	6
Net Book Value	169	169	145
Operating segments \| Natural Gas Pipelines \| Metering and other \| Mexico
Plant, property and equipment
Cost	388	388	314
Accumulated Depreciation	27	27	20
Net Book Value	361	361	294
Operating segments \| Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Mexico
Plant, property and equipment
Cost	1,867	1,867	1,518
Accumulated Depreciation	203	203	130
Net Book Value	1,664	1,664	1,388
Operating segments \| Natural Gas Pipelines \| Under construction \| Mexico
Plant, property and equipment
Cost	1,959	1,959	1,098
Net Book Value	1,959	1,959	1,098
Operating segments \| Natural Gas Pipelines \| Canadian Mainline
Plant, property and equipment
Cost	13,353	13,353	13,061
Accumulated Depreciation	8,378	8,378	7,992
Net Book Value	4,975	4,975	5,069
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Pipeline
Plant, property and equipment
Cost	9,164	9,164	9,045
Accumulated Depreciation	5,966	5,966	5,712
Net Book Value	3,198	3,198	3,333
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Compression
Plant, property and equipment
Cost	3,433	3,433	3,423
Accumulated Depreciation	2,220	2,220	2,100
Net Book Value	1,213	1,213	1,323
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Metering and other
Plant, property and equipment
Cost	499	499	458
Accumulated Depreciation	192	192	180
Net Book Value	307	307	278
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	13,096	13,096	12,926
Accumulated Depreciation	8,378	8,378	7,992
Net Book Value	4,718	4,718	4,934
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Under construction
Plant, property and equipment
Cost	257	257	135
Net Book Value	257	257	135
Operating segments \| Natural Gas Pipelines \| NGTL System
Plant, property and equipment
Cost	12,709	12,709	11,685
Accumulated Depreciation	5,713	5,713	5,383
Net Book Value	6,996	6,996	6,302
Operating segments \| Natural Gas Pipelines \| NGTL System \| Pipeline
Plant, property and equipment
Cost	8,456	8,456	8,185
Accumulated Depreciation	3,820	3,820	3,619
Net Book Value	4,636	4,636	4,566
Operating segments \| Natural Gas Pipelines \| NGTL System \| Compression
Plant, property and equipment
Cost	2,188	2,188	2,055
Accumulated Depreciation	1,404	1,404	1,318
Net Book Value	784	784	737
Operating segments \| Natural Gas Pipelines \| NGTL System \| Metering and other
Plant, property and equipment
Cost	1,096	1,096	1,032
Accumulated Depreciation	489	489	446
Net Book Value	607	607	586
Operating segments \| Natural Gas Pipelines \| NGTL System \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	11,740	11,740	11,272
Accumulated Depreciation	5,713	5,713	5,383
Net Book Value	6,027	6,027	5,889
Operating segments \| Natural Gas Pipelines \| NGTL System \| Under construction
Plant, property and equipment
Cost	969	969	413
Net Book Value	969	969	413
Operating segments \| Natural Gas Pipelines \| ANR
Plant, property and equipment
Cost	3,831	3,831	2,861
Accumulated Depreciation	789	789	598
Net Book Value	3,042	3,042	2,263
Operating segments \| Natural Gas Pipelines \| ANR \| Pipeline
Plant, property and equipment
Cost	1,449	1,449	1,217
Accumulated Depreciation	350	350	227
Net Book Value	1,099	1,099	990
Operating segments \| Natural Gas Pipelines \| ANR \| Compression
Plant, property and equipment
Cost	1,101	1,101	780
Accumulated Depreciation	187	187	140
Net Book Value	914	914	640
Operating segments \| Natural Gas Pipelines \| ANR \| Metering and other
Plant, property and equipment
Cost	977	977	737
Accumulated Depreciation	252	252	231
Net Book Value	725	725	506
Operating segments \| Natural Gas Pipelines \| ANR \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	3,527	3,527	2,734
Accumulated Depreciation	789	789	598
Net Book Value	2,738	2,738	2,136
Operating segments \| Natural Gas Pipelines \| ANR \| Under construction
Plant, property and equipment
Cost	304	304	127
Net Book Value	304	304	127
Operating segments \| Natural Gas Pipelines \| Other Natural Gas Pipelines
Plant, property and equipment
Cost	8,335	8,335	7,154
Accumulated Depreciation	3,654	3,654	3,070
Net Book Value	4,681	4,681	4,084
Operating segments \| Natural Gas Pipelines \| Other Natural Gas Pipelines \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	8,264	8,264	7,120
Accumulated Depreciation	3,654	3,654	3,070
Net Book Value	4,610	4,610	4,050
Operating segments \| Natural Gas Pipelines \| Other Natural Gas Pipelines \| Under construction
Plant, property and equipment
Cost	71	71	34
Net Book Value	71	71	34
Operating segments \| Natural Gas Pipelines \| GTN \| Pipeline
Plant, property and equipment
Cost	2,278	2,278	1,842
Accumulated Depreciation	765	765	588
Net Book Value	1,513	1,513	1,254
Operating segments \| Natural Gas Pipelines \| Great Lakes \| Pipeline
Plant, property and equipment
Cost	2,157	2,157	1,807
Accumulated Depreciation	1,155	1,155	939
Net Book Value	1,002	1,002	868
Operating segments \| Natural Gas Pipelines \| Foothills \| Pipeline
Plant, property and equipment
Cost	1,606	1,606	1,671
Accumulated Depreciation	1,162	1,162	1,180
Net Book Value	444	444	491
Operating segments \| Natural Gas Pipelines \| Other \| Pipeline
Plant, property and equipment
Cost	2,223	2,223	1,800
Accumulated Depreciation	572	572	363
Net Book Value	1,651	1,651	1,437
Operating segments \| Liquids Pipelines
Plant, property and equipment
Cost	15,240	15,240	15,615
Accumulated Depreciation	1,054	1,054	687
Net Book Value	14,186	14,186	14,928
Operating segments \| Liquids Pipelines \| Under construction
Plant, property and equipment
Cost	1,826	1,826	4,438
Net Book Value	1,826	1,826	4,438
Operating segments \| Liquids Pipelines \| Keystone \| Pipeline
Plant, property and equipment
Cost	9,288	9,288	7,931
Accumulated Depreciation	718	718	463
Net Book Value	8,570	8,570	7,468
Operating segments \| Liquids Pipelines \| Keystone \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	13,414	13,414	11,177
Accumulated Depreciation	1,054	1,054	687
Net Book Value	12,360	12,360	10,490
Operating segments \| Liquids Pipelines \| Keystone \| Pumping equipment
Plant, property and equipment
Cost	1,092	1,092	964
Accumulated Depreciation	108	108	80
Net Book Value	984	984	884
Operating segments \| Liquids Pipelines \| Keystone \| Tanks and other
Plant, property and equipment
Cost	3,034	3,034	2,282
Accumulated Depreciation	228	228	144
Net Book Value	2,806	2,806	2,138
Operating segments \| Energy
Plant, property and equipment
Cost	9,555	9,555	8,414
Accumulated Depreciation	2,426	2,426	1,924
Net Book Value	7,129	7,129	6,490
Operating segments \| Energy \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	9,125	9,125	8,265
Accumulated Depreciation	2,426	2,426	1,924
Net Book Value	6,699	6,699	6,341
Operating segments \| Energy \| Under construction
Plant, property and equipment
Cost	430	430	149
Net Book Value	430	430	149
Operating segments \| Energy \| Natural Gas – Ravenswood
Plant, property and equipment
Cost	2,607	2,607	2,140
Accumulated Depreciation	654	654	476
Net Book Value	1,953	1,953	1,664
Operating segments \| Energy \| Natural Gas - Other
Plant, property and equipment
Cost	3,361	3,361	3,214
Accumulated Depreciation	1,164	1,164	971
Net Book Value	2,197	2,197	2,243
Operating segments \| Energy \| Hydro, Wind and Solar
Plant, property and equipment
Cost	2,417	2,417	2,194
Accumulated Depreciation	476	476	359
Net Book Value	1,941	1,941	1,835
Operating segments \| Energy \| Natural Gas Storage and Other
Plant, property and equipment
Cost	740	740	717
Accumulated Depreciation	132	132	118
Net Book Value	608	608	$ 599
Operating segments \| Energy \| Solar
Plant, property and equipment
Number of facilities acquired \| facility			4
Corporate
Plant, property and equipment
Cost	267	267	$ 232
Accumulated Depreciation	82	82	80
Net Book Value	$ 185	$ 185	$ 152

EQUITY INVESTMENTS - Schedule and Narrative (Details) $ in Millions, $ in Millions		12 Months Ended
	Dec. 03, 2015 CAD ($)	Dec. 31, 2015 CAD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2013 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 30, 2015	Dec. 04, 2015	Dec. 02, 2015	Dec. 31, 2014 USD ($)	May 31, 2013	Apr. 30, 2013
Equity Investments
Income / (Loss) from Equity Investments		$ 440	$ 522	$ 597
Equity Investments		6,214	5,598
Distributions received from equity investments		802	738	733
Returns of capital		226	159	128
Undistributed earnings		198	551	754
Contributions made to equity investments		$ 493	$ 256	$ 163
TC PipeLines, LP
Equity Investments
Ownership interest in subsidiary		28.00%	28.30%	28.90%	28.00%				28.30%	28.90%	33.30%
Northern Border
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets					$ 117				$ 117
Bruce Power
Equity Investments
Ownership interest		48.50%			48.50%		48.50%
Difference between the carrying value of the investment and the underlying equity in the net assets		$ 973	$ 776
Bruce A
Equity Investments
Ownership interest						48.90%		48.90%
Bruce B
Equity Investments
Ownership interest	46.50%					31.60%		31.60%
Contributions made to equity investments	$ 236
Natural Gas Pipelines \| Northern Border
Equity Investments
Ownership interest		14.00%	14.20%	14.50%	14.00%				14.20%
Income / (Loss) from Equity Investments		$ 85	$ 76	$ 66
Equity Investments		$ 664	587
Natural Gas Pipelines \| Northern Border \| TC PipeLines, LP
Equity Investments
Ownership interest		50.00%			50.00%
Natural Gas Pipelines \| Iroquois
Equity Investments
Ownership interest		44.50%			44.50%
Income / (Loss) from Equity Investments		$ 51	43	41
Equity Investments		$ 238	210
Natural Gas Pipelines \| TQM
Equity Investments
Ownership interest		50.00%			50.00%
Income / (Loss) from Equity Investments		$ 12	12	13
Equity Investments		72	73
Natural Gas Pipelines \| Other
Equity Investments
Income / (Loss) from Equity Investments		31	32	25
Equity Investments		$ 73	68
Liquids Pipelines \| Grand Rapids
Equity Investments
Ownership interest		50.00%			50.00%
Equity Investments		$ 542	240
Liquids Pipelines \| Canaport Energy East Marine Terminal
Equity Investments
Ownership interest		50.00%			50.00%
Equity Investments		$ 16
Energy \| Other
Equity Investments
Income / (Loss) from Equity Investments		5	1	1
Equity Investments		$ 67	61
Energy \| Bruce Power
Equity Investments
Ownership interest		48.50%			48.50%
Income / (Loss) from Equity Investments		$ 249	314	310
Equity Investments		$ 4,200	3,995
Energy \| ASTC Power Partnership
Equity Investments
Ownership interest		50.00%			50.00%
Income / (Loss) from Equity Investments		$ (23)	8	110
Equity Investments		$ 21	29
Energy \| Portlands Energy
Equity Investments
Ownership interest		50.00%			50.00%
Income / (Loss) from Equity Investments		$ 30	36	$ 31
Equity Investments		$ 321	$ 335

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income
Revenues	$ 4,337	$ 4,814	$ 4,989
Operating and other expenses	(3,254)	(3,489)	(3,536)
Net income	1,046	1,264	1,390
Net income attributable to TransCanada	440	522	$ 597
Balance Sheet
Current assets	1,530	1,412
Non-current assets	13,190	12,260
Current liabilities	(1,370)	(1,067)
Non-current liabilities	$ (3,116)	$ (3,255)

RATE-REGULATED BUSINESSES - Narrative (Details) - CAD ($) $ in Millions			1 Months Ended			12 Months Ended			24 Months Ended	48 Months Ended
	Jul. 01, 2015	Nov. 28, 2014	Feb. 28, 2015	Nov. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2021	Dec. 31, 2019
Rate-regulated business
After-tax annual contribution to reduce revenue requirement		$ 20
Fixed toll term		6 years
Settlement, reduction in rates	(3.00%)
Allowance for funds used during construction						$ 295	$ 136	$ 37
Scenario, forecast
Rate-regulated business
Settlement, reduction in rates									(8.00%)	(10.00%)
National Energy Board \| 2015 Revenue Requirement Settlement \| NGTL System
Rate-regulated business
Approved ROE on deemed common equity			10.10%
Deemed common equity			40.00%
Period of settlement			1 year
Composite depreciation rate							3.12%
Canadian Regulated Operations \| National Energy Board \| 2015 Revenue Requirement Settlement \| NGTL System
Rate-regulated business
Approved ROE on deemed common equity				10.10%
Deemed common equity				40.00%
Canadian Mainline \| Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity		10.10%			11.50%
Deemed common equity		40.00%			40.00%
Term of regulatory decision					5 years			5 years

RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets
Total regulatory assets	$ 1,269	$ 1,313
Less: Current portion included in Other current assets (Note 5)	85	16
Regulatory assets, noncurrent	1,184	1,297
Regulatory Liabilities
Total regulatory liabilities	1,203	293
Less: Current portion included in Accounts payable and other (Note 13)	44	30
Regulated liabilities, noncurrent	$ 1,159	263
Foreign exchange on long-term debt
Regulatory Liabilities
Total regulatory liabilities		42
Foreign exchange on long-term debt \| Minimum
Regulatory Liabilities
Remaining Recovery/ Settlement Period (years)	1 year
Foreign exchange on long-term debt \| Maximum
Regulatory Liabilities
Remaining Recovery/ Settlement Period (years)	14 years
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Total regulatory liabilities	$ 32	21
Remaining Recovery/ Settlement Period (years)	1 year
Pensions and other post retirement benefits
Regulatory Liabilities
Total regulatory liabilities	$ 147	117
Long term adjustment account
Regulatory Liabilities
Total regulatory liabilities	$ 231	64
Remaining Recovery/ Settlement Period (years)	45 years
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	$ 167	418	$ (247)
Pipeline abandonment costs
Regulatory Liabilities
Total regulatory liabilities	285
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	285
Bridging amortization account
Regulatory Liabilities
Total regulatory liabilities	$ 456
Remaining Recovery/ Settlement Period (years)	15 years
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	$ 456
Other
Regulatory Liabilities
Total regulatory liabilities	52	49
Deferred income taxes
Regulatory Assets
Total regulatory assets	848	1,001
Operating and debt-service regulatory assets
Regulatory Assets
Total regulatory assets	$ 47	4
Remaining Recovery/ Settlement Period (years)	1 year
Operating and debt-service regulatory assets \| Operating and debt-service regulatory liabilities
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	$ (32)	28	(76)
Pensions and other post retirement benefits
Regulatory Assets
Total regulatory assets	210	236
Pensions and other post retirement benefits \| Pensions and other post retirement benefits
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	26	(46)	171
Foreign exchange on long-term debt
Regulatory Assets
Total regulatory assets	$ 54
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)	14 years
Other
Regulatory Assets
Total regulatory assets	$ 110	72
Other \| Other
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	(35)	2	2
Postretirement benefit costs \| Postretirement benefit costs
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	$ 30	$ 13	$ 16

GOODWILL (Details) $ in Millions, $ in Millions	12 Months Ended
GOODWILL (Details) $ in Millions, $ in Millions	Dec. 31, 2015 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2015 CAD ($)	Dec. 31, 2015 USD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 4,034		$ 3,696	$ 4,812
Goodwill
Balance at the beginning of the period	4,034		3,696
Foreign exchange rate changes	778		338
Balance at the end of the period	$ 4,812		4,034
Great Lakes
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill		$ 573			$ 573
Estimated fair value exceeds carrying value by less than				10.00%	10.00%
Reduced forecasted cash flows, number of years	10 years	10 years
Goodwill
Balance at the beginning of the period		$ 573
Balance at the end of the period		573
Great Lakes \| TRANSCANADA PIPELINES LIMITED
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill, impairment loss		199
Ownership interest				46.45%	46.45%
Great Lakes \| Net of non-controlling interest
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill		243			$ 386
Goodwill
Balance at the beginning of the period		243
Balance at the end of the period		$ 386
Natural Gas Pipelines
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 3,074		2,816	$ 3,667
Goodwill
Balance at the beginning of the period	3,074		2,816
Foreign exchange rate changes	593		258
Balance at the end of the period	3,667		3,074
Energy
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	960		880	$ 1,145
Goodwill
Balance at the beginning of the period	960		880
Foreign exchange rate changes	185		80
Balance at the end of the period	$ 1,145		$ 960

INTANGIBLE AND OTHER ASSETS (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2013 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
Capital projects in development	$ 1,814	$ 1,286
PPAs	220	272
Fair value of derivative contracts (Note 23)	168	93
Loans and advances	159	167
Employee post-retirement benefits (Note 22)	18	14
Deferred income tax assets and charges (Note 15)	15	185
Other	797	629
Intangible and other assets	3,191	2,646
Note receivable
Notes receivable	$ 213	213		$ 154	$ 184
Interest rate on notes receivable	6.75%
Current portion of note receivable	$ 55	46		$ 40	$ 40
Amount related to PPAs which are included in intangibles and other assets
Cost	810	810
Accumulated Amortization	590	538
Net Book Value	220	272
Amortization expense	52	52	$ 52
Expected annual amortization expense
2016	52
2017	52
2018	39
2019	39
2020	39
Sheerness (expires 2020)
Goodwill and Intangible Assets Disclosure [Abstract]
PPAs	195	234
Amount related to PPAs which are included in intangibles and other assets
Cost	585	585
Accumulated Amortization	390	351
Net Book Value	195	234
Sundance A (expires 2017)
Goodwill and Intangible Assets Disclosure [Abstract]
PPAs	25	38
Amount related to PPAs which are included in intangibles and other assets
Cost	225	225
Accumulated Amortization	200	187
Net Book Value	$ 25	$ 38

NOTES PAYABLE (Details)	12 Months Ended
NOTES PAYABLE (Details)	Dec. 31, 2015 CAD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2013 CAD ($)	Dec. 31, 2015 USD ($)	Nov. 01, 2015 USD ($)	Oct. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Notes payable
Outstanding at December 31	$ 1,218,000,000	$ 2,467,000,000
Operated affiliates
Notes payable
Unused Capacity	600,000,000	400,000,000
Notes payable \| U.S. dollars
Notes payable
Outstanding at December 31				$ 376,000,000			$ 800,000,000
Revolving and demand credit facilities
Notes payable
Unused Capacity	8,900,000,000	6,700,000,000
TRANSCANADA PIPELINES LIMITED \| Revolving credit facility \| Maturing December 2016
Notes payable
Amount				1,000,000,000
Unused Capacity				1,000,000,000
TRANSCANADA PIPELINES LIMITED \| Revolving credit facility \| Maturing December 2020
Notes payable
Amount	3,000,000,000
Unused Capacity	3,000,000,000
Cost to maintain	6,000,000	6,000,000	$ 4,000,000
TRANSCANADA PIPELINES LIMITED \| Revolving credit facility \| U.S. dollars
Notes payable
Amount				$ 1,000,000,000
TRANSCANADA PIPELINES LIMITED \| Notes payable
Notes payable
Outstanding at December 31	$ 697,000,000	$ 1,540,000,000
Weighted Average Interest Rate per Annum at December 31	0.80%	1.20%		0.80%			1.20%
TAIL/TCPM \| Revolving credit facility
Notes payable
Amount				$ 1,500,000,000.0
Unused Capacity				$ 1,500,000,000
Cost to maintain	$ 2,000,000	$ 1,000,000
TAIL/TCPM \| Notes payable
Notes payable
Outstanding at December 31	$ 521,000,000	$ 927,000,000
Weighted Average Interest Rate per Annum at December 31	1.10%	0.70%		1.10%			0.70%
TAIL \| Revolving credit facility \| U.S. dollars
Notes payable
Amount					$ 1,500,000,000.0	$ 1,000,000,000
TCPL USA \| Revolving credit facility
Notes payable
Amount				$ 500,000,000.0
Unused Capacity				$ 500,000,000
Cost to maintain	$ 3,000,000	$ 2,000,000	$ 1,000,000
TCPL USA \| Revolving credit facility \| U.S. dollars
Notes payable
Amount					$ 500,000,000.0	$ 1,000,000,000
TCPL/TCPL USA \| Revolving credit facility
Notes payable
Amount	1,700,000,000.0
Unused Capacity	$ 700,000,000

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Payables and Accruals [Abstract]
Trade payables	$ 1,506	$ 1,624
Fair value of derivative contracts (Note 23)	926	749
Dividends payable	385	359
Regulatory liabilities (Note 9)	44	30
Liabilities related to assets held for sale (Note 6)	39	0
Other	121	130
Accounts payable and other	$ 3,021	$ 2,892

- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset, expected to be settled within one year or normal operating cycle, if longer. Includes assets not subject to a master netting arrangement and not elected to be offset.

+ References + Details

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred Costs, Noncurrent [Abstract]
Fair value of derivative contracts (Note 23)	$ 625	$ 411
Employee post-retirement benefits (Note 22)	380	444
Asset retirement obligations	109	98
Guarantees (Note 26)	26	20
Other	120	79
Other Long-Term Liabilities	$ 1,260	$ 1,052

INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	12 Months Ended
INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current
Canada	$ 44	$ 103	$ 27
Foreign	92	42	16
Total	136	145	43
Deferred
Canada	33	309	245
Foreign	(135)	377	323
Total	(102)	686	568
Total Income Tax Expense/(Recovery)	$ 34	$ 831	$ 611

INCOME TAXES - Geographic Components of Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Canada	$ (624)	$ 1,146	$ 1,224
Foreign	(482)	1,678	1,298
(Loss)/Income before Income Taxes	$ (1,106)	$ 2,824	$ 2,522

INCOME TAXES - Reconciliation of Expense (Details) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
(Loss)/Income before income taxes		$ (1,106)	$ 2,824	$ 2,522
Federal and provincial statutory tax rate		26.00%	25.00%	25.00%
Expected income tax (recovery)/expense		$ (288)	$ 706	$ 631
Income tax differential related to regulated operations		159	129	(13)
Higher effective foreign tax rates		14	25	33
Income from equity investments and non-controlling interests		(56)	(38)	(28)
Tax rate and legislative changes	$ (25)	34	0	(25)
Asset impairment charges		170	0	0
Other		1	9	13
Total Income Tax Expense/(Recovery)		34	$ 831	$ 611
Foreign income tax rate different netted against impairment losses		$ 311

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Increase (decrease) to the valuation allowance	$ 935
Deferred Tax Assets, Net [Abstract]
Difference in accounting and tax bases of impaired assets	916	$ 0
Tax loss and credit carryforwards	1,327	1,344
Regulatory and other deferred amounts	231	236
Unrealized foreign exchange losses on long-term debt	589	140
Financial instruments	111	104
Other	136	149
Deferred tax assets, gross	3,310	1,973
Less: Valuation allowance	1,060	125
Deferred Tax Assets, Net of Valuation Allowance	2,250	1,848
Deferred Tax Liabilities, Net [Abstract]
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,441	5,548
Equity investments	656	648
Taxes on future revenue requirement	227	253
Other	55	71
Deferred tax liabilities, gross	7,379	6,520
Net Deferred Income Tax Liabilities	5,129	4,672
Deferred Income Tax Assets
Intangible and other assets (Note 11)	15	185
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,144	4,857
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred noncurrent tax liabilities, post accounting pronouncement adoption	$ 5,144	4,857
New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred current income tax assets, prior to accounting pronouncement		427
Deferred current income tax liabilities, prior to accounting pronouncement		4
Deferred noncurrent tax assets, post accounting pronouncement adoption		427
Deferred noncurrent tax liabilities, post accounting pronouncement adoption		$ 4

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefit at beginning of year	$ 18	$ 23	$ 49
Gross increases – tax positions in prior years	2	3	3
Gross decreases – tax positions in prior years	(2)	(8)	(28)
Gross increases – tax positions in current year	1	1	2
Lapses of statute of limitations	(2)	(1)	(3)
Unrecognized Tax Benefit at End of Year	$ 17	$ 18	$ 23

INCOME TAXES - Narrative (Details) $ in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2013 CAD ($)	Dec. 31, 2015 CAD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2013 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Net operating loss carryforwards
Deferred income tax liabilities on the unremitted earnings of foreign investments		$ 308	$ 236
Income tax payments, net of refunds		162	109	$ 202
(Favourable) income tax adjustment	$ (25)	34	0	(25)
Interest expense (reversal) reflected within net tax expense		(1)	1	$ (1)
Accrued interest expense		4	5
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards		1,283	1,131
Canada federal and provincial \| Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits		$ 57	$ 50
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards					$ 1,617	$ 2,267
U.S. federal \| Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits					$ 41	$ 26

LONG-TERM DEBT - Schedule of Activity and Summary of Principal Repayments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2014 USD ($)
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 31,584		$ 24,757
Less: Current portion of Long-term debt	2,547		1,797
Long-term Debt, Excluding Current Maturities	29,037		22,960
Repayments of Long-term Debt [Abstract]
2016	2,547
2017	2,150
2018	3,379
2019	1,228
2020	1,801
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	26,685		20,916
TRANSCANADA PIPELINES LIMITED \| Debentures, Maturity Dates Between 2017 and 2020
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 599		$ 749
Interest Rate	10.70%	10.70%	10.90%	10.90%
TRANSCANADA PIPELINES LIMITED \| Debentures, Maturity Date of 2021
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 554	$ 400	$ 464	$ 400
Interest Rate	9.90%	9.90%	9.90%	9.90%
TRANSCANADA PIPELINES LIMITED \| Medium-Term Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 5,192		$ 4,048
Interest Rate	5.30%	5.30%	5.70%	5.70%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 20,340	$ 14,723	$ 15,655	$ 13,526
Interest Rate	4.80%	4.80%	5.00%	5.00%
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 1,151		$ 1,099
NOVA GAS TRANSMISSION LTD. \| Debentures and Notes, Maturity Dates between 2016 and 2024
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 325		$ 325
Interest Rate	11.50%	11.50%	11.50%	11.50%
NOVA GAS TRANSMISSION LTD. \| Debentures and Notes, Maturity Date of 2023
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 277	$ 200	$ 232	$ 200
Interest Rate	7.90%	7.90%	7.90%	7.90%
NOVA GAS TRANSMISSION LTD. \| Medium-Term Notes, Maturity between 2025 and 2030
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 504		$ 504
Interest Rate	7.40%	7.40%	7.40%	7.40%
NOVA GAS TRANSMISSION LTD. \| Medium-Term Notes, Maturity Date of 2026
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 45	$ 33	$ 38	$ 33
Interest Rate	7.50%	7.50%	7.50%	7.50%
NOVA GAS TRANSMISSION LTD. \| Debentures
Debt Instrument [Line Items]
Long-term debt issued with retraction provision	$ 225
NOVA GAS TRANSMISSION LTD. \| Debentures \| Maximum
Debt Instrument [Line Items]
Redemption price, percentage	8.00%
ANR PIPELINE COMPANY \| Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 598	$ 432	$ 502	$ 432
Interest Rate	8.90%	8.90%	8.90%	8.90%
GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 450		$ 377
GAS TRANSMISSION NORTHWEST LLC \| Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 346	$ 250	$ 377	$ 325
Interest Rate	5.60%	5.60%	5.50%	5.50%
GAS TRANSMISSION NORTHWEST LLC \| Unsecured Term Loan
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 104	$ 75
Interest Rate	1.40%	1.40%
TC PIPELINES, LP
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 2,171		$ 1,368
TC PIPELINES, LP \| Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 967	$ 698	$ 405	$ 350
Interest Rate	4.70%	4.70%	4.70%	4.70%
TC PIPELINES, LP \| Unsecured Term Loan
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 235	$ 170
Interest Rate	1.60%	1.60%
TC PIPELINES, LP \| Unsecured Loan
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 277	$ 200	$ 383	$ 330
Interest Rate	1.60%	1.60%	1.40%	1.40%
TC PIPELINES, LP \| Unsecured Term Loan Facility
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 692	$ 500	$ 580	$ 500
Interest Rate	1.60%	1.60%	1.40%	1.40%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP \| Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 411	$ 297	$ 367	$ 316
Interest Rate	7.80%	7.80%	7.80%	7.80%
TUSCARORA GAS TRANSMISSION COMPANY \| Secured Debt
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 22	$ 16	$ 23	$ 20
Interest Rate	4.00%	4.00%	4.00%	4.00%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Secured Debt
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	$ 96	$ 69	$ 105	$ 90
Interest Rate	6.10%	6.10%	6.10%	6.10%

LONG-TERM DEBT - Long-Term Debt Issued (Details) $ in Millions, $ in Millions	1 Months Ended
	Nov. 30, 2015 USD ($)	Oct. 31, 2015 CAD ($)	Sep. 30, 2015 USD ($)	Jul. 31, 2015 CAD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Jan. 31, 2015 USD ($)	Feb. 28, 2014 USD ($)	Oct. 31, 2013 USD ($)	Jul. 31, 2013 CAD ($)	Jul. 31, 2013 USD ($)	Jan. 31, 2013 USD ($)
TRANSCANADA PIPELINES LIMITED \| 1.625% senior unsecured notes, due November 2017
Debt Instrument [Line Items]
Amount	$ 1,000
Interest Rate	1.625%
TRANSCANADA PIPELINES LIMITED \| 4.55% medium-term notes, due November 2041
Debt Instrument [Line Items]
Amount		$ 400
Interest Rate		4.55%
TRANSCANADA PIPELINES LIMITED \| 3.30% medium-term notes, due July 2025
Debt Instrument [Line Items]
Amount				$ 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
TRANSCANADA PIPELINES LIMITED \| 4.63% senior unsecured notes, due March 2034
Debt Instrument [Line Items]
Amount								$ 1,250
Interest Rate								4.63%
TRANSCANADA PIPELINES LIMITED \| 3.75% senior unsecured notes, due October 2023
Debt Instrument [Line Items]
Amount									$ 625
Interest Rate									3.75%
TRANSCANADA PIPELINES LIMITED \| 5.00% senior unsecured notes, due October 2043
Debt Instrument [Line Items]
Amount									$ 625
Interest Rate									5.00%
TRANSCANADA PIPELINES LIMITED \| 0.95% floating rate notes, maturing June 2016
Debt Instrument [Line Items]
Amount											$ 500
TRANSCANADA PIPELINES LIMITED \| 3.69% medium term notes, due July 2023
Debt Instrument [Line Items]
Amount										$ 450
Interest Rate										3.69%	3.69%
TRANSCANADA PIPELINES LIMITED \| 4.55% medium term notes, due November 2041
Debt Instrument [Line Items]
Amount										$ 300
Interest Rate										4.55%	4.55%
TRANSCANADA PIPELINES LIMITED \| 0.75% senior notes, due January 2016
Debt Instrument [Line Items]
Amount												$ 750
Interest Rate												0.75%
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%
TC PIPELINES, LP \| Medium-term loan, floating rate, due July 2018
Debt Instrument [Line Items]
Amount											$ 500
GAS TRANSMISSION NORTHWEST LLC \| Unsecured term loan, floating interest rate, due June 2019
Debt Instrument [Line Items]
Amount					$ 75

LONG-TERM DEBT - Retired (Details) $ in Millions, $ in Millions	1 Months Ended
	Aug. 31, 2015 CAD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Jan. 31, 2015 USD ($)	Jun. 30, 2014 CAD ($)	Feb. 28, 2014 CAD ($)	Jan. 31, 2014 CAD ($)	Aug. 31, 2013 USD ($)	Jun. 30, 2013 USD ($)
TRANSCANADA PIPELINES LIMITED \| Debentures, 11.90%
Debt Instrument [Line Items]
Amount	$ 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%
TRANSCANADA PIPELINES LIMITED \| Debentures, 11.10%
Debt Instrument [Line Items]
Amount					$ 125
Interest Rate					11.10%
TRANSCANADA PIPELINES LIMITED \| Medium-Term Notes at 5.05%
Debt Instrument [Line Items]
Amount						$ 300
Interest Rate						5.05%
TRANSCANADA PIPELINES LIMITED \| Medium-Term Notes, 5.65%
Debt Instrument [Line Items]
Amount							$ 450
Interest Rate							5.65%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes 5.05%
Debt Instrument [Line Items]
Amount								$ 500
Interest Rate								5.05%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes, 4.00%
Debt Instrument [Line Items]
Amount									$ 350
Interest Rate									4.00%
GAS TRANSMISSION NORTHWEST LLC \| Senior Unsecured Notes, 5.09%
Debt Instrument [Line Items]
Amount		$ 75
Interest Rate		5.09%
NOVA GAS TRANSMISSION LTD. \| Debentures, 11.20%
Debt Instrument [Line Items]
Amount					$ 53
Interest Rate					11.20%

LONG-TERM DEBT - Interest Expense and Payments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Interest Expense [Abstract]
Capitalized interest	$ (280)	$ (259)	$ (287)
Amortization and other financial charges	31	55	(21)
Interest expense	1,370	1,198	985
Interest payments on long-term debt and junior subordinated notes, net of interest capitalized on construction projects	1,266	1,123	985
Short-term debt
Interest Expense [Abstract]
Interest on debt	16	15	12
Total long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest on debt	1,487	1,317	1,216
Junior subordinated notes
Interest Expense [Abstract]
Interest on debt	$ 116	$ 70	$ 65

JUNIOR SUBORDINATED NOTES (Details) $ in Millions	1 Months Ended	12 Months Ended	240 Months Ended	360 Months Ended
JUNIOR SUBORDINATED NOTES (Details) $ in Millions	May 31, 2015 USD ($)	Dec. 31, 2015 CAD ($)	Apr. 30, 2045	Apr. 30, 2075	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2014 USD ($)
Debt Instrument [Line Items]
Outstanding at December 31		$ 2,422				$ 1,160
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding at December 31		$ 2,422				1,160
TRANSCANADA PIPELINES LIMITED \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding at December 31					$ 1,000,000,000.0
Stated interest rate		6.35%			6.35%
Optional period for which payment of interest can be deferred		10 years
Redemption price as a percentage of principal amount plus accrued and unpaid interest		100.00%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Basis points		2.21%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2067
Debt Instrument [Line Items]
Outstanding at December 31		$ 1,384			$ 1,000,000,000	$ 1,160	$ 1,000,000,000
Effective Interest Rate		6.40%			6.40%	6.50%	6.50%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2075
Debt Instrument [Line Items]
Outstanding at December 31		$ 1,038			$ 750,000,000
Effective Interest Rate		5.30%			5.30%
TRANSCANADA PIPELINES LIMITED \| TransCanada Trust loan, due in May 2075 \| Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate	5.875%
Redemption price as a percentage of principal amount plus accrued and unpaid interest	100.00%
Debt	$ 750,000,000
Administrative charge	0.25%
TRANSCANADA PIPELINES LIMITED \| TransCanada Trust loan, due in May 2075 \| Junior subordinated notes \| LIBOR \| Scenario, forecast
Debt Instrument [Line Items]
Basis points			3.778%	4.528%
TransCanada Trust \| Trust Notes - Series 2015-A \| Notes payable
Debt Instrument [Line Items]
Stated interest rate	5.625%
Debt	$ 750,000,000
Stated interest rate, period of time	10 years

NON-CONTROLLING INTERESTS (Details) $ / shares in Units, shares in Millions, $ in Millions, $ in Millions			12 Months Ended
	Mar. 05, 2014 $ / shares shares	Oct. 15, 2013 $ / shares shares	Dec. 31, 2015 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2013 CAD ($)	Jan. 01, 2015	Jan. 01, 2014	May 01, 2013	Dec. 31, 2012 CAD ($)
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest			$ 1,717		$ 1,583
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest			6		153	$ 125
Additional information
Impairment charge			3,745		0	0
TC PipeLines, LP
Additional information
Impairment charge				$ 199
Fees received for services provided			4		3	3
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Additional information
Fees received for services provided			11		8	7
TRANSCANADA PIPELINES LIMITED \| Series Y
Preferred Shares of TCPL
Number of shares outstanding (in shares) \| shares	4
Preferred stock dividend rate	5.60%
Redemption price per share (in Canadian dollars per share) \| $ / shares	$ 50
Accrued and unpaid dividends (in Canadian dollars per share) \| $ / shares	$ 0.2455
TRANSCANADA PIPELINES LIMITED \| Series U
Preferred Shares of TCPL
Number of shares outstanding (in shares) \| shares		4
Preferred stock dividend rate		5.60%
Redemption price per share (in Canadian dollars per share) \| $ / shares		$ 50
Accrued and unpaid dividends (in Canadian dollars per share) \| $ / shares		$ 0.5907
Noncontrolling Interest
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest			1,717		1,583	1,611				$ 1,425
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest			19		15	12
Noncontrolling Interest \| TC PipeLines, LP
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest			1,590		1,479
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest			$ (13)		136	93
Additional information
Percentage of non-controlling interests			72.00%				71.70%	71.10%	66.70%
Impairment charge			$ 13	$ 143
Noncontrolling Interest \| PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest			127		104
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest			$ 19		$ 15	$ 12
Additional information
Percentage of non-controlling interests			38.30%		38.30%	38.30%
Noncontrolling Interest \| TRANSCANADA PIPELINES LIMITED
Non-controlling interests included in the Consolidated Statement of Income
Preferred shares of TCPL			$ 0		$ 2	$ 20

COMMON SHARES - Reconciliation (Details) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)		709,000,000
Outstanding at the beginning of the period		$ 12,202
Exercise of options (in shares)		737,000	1,221,000	1,980,000
Repurchase of shares (in shares)	(6,784,738)
Repurchase of shares	$ (294)
Outstanding at the end of the period (in shares)	703,000,000	703,000,000	709,000,000
Outstanding at the end of the period	$ 12,102	$ 12,102	$ 12,202
Weighted Average Common Shares Outstanding
Basic (in shares)		709,000,000	708,000,000	707,000,000
Diluted (in shares)		709,000,000	710,000,000	708,000,000
Common Shares
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)		708,662,000	707,441,000	705,461,000
Outstanding at the beginning of the period		$ 12,202	$ 12,149	$ 12,069
Exercise of options (in shares)		737,000	1,221,000	1,980,000
Exercise of options		$ 30	$ 53	$ 80
Repurchase of shares (in shares)		(6,785,000)
Repurchase of shares		$ (130)	$ 0	$ 0
Outstanding at the end of the period (in shares)	702,614,000	702,614,000	708,662,000	707,441,000
Outstanding at the end of the period	$ 12,102	$ 12,102	$ 12,202	$ 12,149
Weighted Average Common Shares Outstanding
Basic (in shares)		709,000,000	708,000,000	707,000,000
Diluted (in shares)		709,000,000	710,000,000	708,000,000

COMMON SHARES - Options (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Number of Options
Outstanding at the beginning of the period (in shares)	8,464	7,393	7,434
Granted (in shares)	2,214	2,292	1,939
Exercised (in shares)	(737)	(1,221)	(1,980)
Forfeited (in shares)	(107)
Outstanding at the end of the period (in shares)	9,834	8,464	7,393
Weighted Average Exercise Price
Outstanding at the beginning of the period (in Canadian dollars per share)	$ 43.17	$ 40.57	$ 37.69
Granted (in Canadian dollars per share)	56.58	49.03	47.09
Exercised (in Canadian dollars per share)	36.14	43.00	36.12
Forfeited (in Canadian dollars per share)	50.74
Outstanding at the end of the period (in Canadian dollars per share)	$ 46.63	$ 43.17	$ 40.57
Options Exercisable
Options Exercisable (in shares)	5,566	4,556	3,914	4,568

COMMON SHARES - Options by Range of Prices and Additional Disclosures (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Options Outstanding
Number of Options (in shares)	9,834,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 46.63
Weighted Average Remaining Contractual Life	4 years 1 month
Options Exercisable
Number of Options (in shares)	5,566,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 42.04
Weighted Average Remaining Contractual Life	3 years 1 month
Additional disclosure
Common shares reserved for future issuance under stock option plan (in shares)	6,123,649
Weighted average fair value of options granted (in Canadian dollars per share)	$ 6.45	$ 5.54	$ 5.74
Contractual life of options granted	7 years
Award vesting right percentage	33.30%
Award vesting period	3 years
Weighted average assumptions used in binomial model for determining the fair value of awards granted
Expected life (years)	5 years 9 months	6 years	6 years
Interest rate	1.10%	1.80%	1.70%
Volatility	18.00%	17.00%	18.00%
Dividend yield	3.70%	3.80%	3.70%
Forfeiture rate	5.00%	5.00%	15.00%
Additional Stock Option Information
Total intrinsic value of options exercised	$ 37	$ 68	$ 25
Fair value of options that have vested	$ 91	$ 95	$ 64
Total options vested (in shares)	2,000,000	1,700,000	1,300,000
Amount expensed for stock awards, with a corresponding increase in additional paid-in capital	$ 11	$ 9	$ 6
Aggregate intrinsic value of total options exercisable	23
Total intrinsic value of options outstanding	$ 23
$31.93 to $36.26
Range of Exercise Prices
Lower range limit (in Canadian dollars per share)	$ 31.93
Upper range limit (in Canadian dollars per share)	$ 36.26
Options Outstanding
Number of Options (in shares)	970,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 34.27
Weighted Average Remaining Contractual Life	11 months
Options Exercisable
Number of Options (in shares)	970,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 34.27
Weighted Average Remaining Contractual Life	11 months
$36.90 to $41.65
Range of Exercise Prices
Lower range limit (in Canadian dollars per share)	$ 36.90
Upper range limit (in Canadian dollars per share)	$ 41.65
Options Outstanding
Number of Options (in shares)	888,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 37.91
Weighted Average Remaining Contractual Life	2 years 1 month
Options Exercisable
Number of Options (in shares)	888,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 37.91
Weighted Average Remaining Contractual Life	2 years 1 month
$41.95 to $45.29
Range of Exercise Prices
Lower range limit (in Canadian dollars per share)	$ 41.95
Upper range limit (in Canadian dollars per share)	$ 45.29
Options Outstanding
Number of Options (in shares)	1,759,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 42.04
Weighted Average Remaining Contractual Life	3 years 2 months
Options Exercisable
Number of Options (in shares)	1,759,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 42.04
Weighted Average Remaining Contractual Life	3 years 2 months
$47.09
Range of Exercise Prices
Upper range limit (in Canadian dollars per share)	$ 47.09
Options Outstanding
Number of Options (in shares)	1,800,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 47.09
Weighted Average Remaining Contractual Life	4 years 1 month
Options Exercisable
Number of Options (in shares)	1,195,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 47.09
Weighted Average Remaining Contractual Life	4 years 1 month
$49.03
Range of Exercise Prices
Upper range limit (in Canadian dollars per share)	$ 49.03
Options Outstanding
Number of Options (in shares)	2,242,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 49.03
Weighted Average Remaining Contractual Life	5 years 2 months
Options Exercisable
Number of Options (in shares)	754,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 49.03
Weighted Average Remaining Contractual Life	5 years 2 months
$56.58
Range of Exercise Prices
Upper range limit (in Canadian dollars per share)	$ 56.58
Options Outstanding
Number of Options (in shares)	2,175,000
Weighted Average Exercise Price (in Canadian dollars per share)	$ 56.58
Weighted Average Remaining Contractual Life	6 years 2 months
Options Exercisable
Number of Options (in shares)	0
Weighted Average Exercise Price (in Canadian dollars per share)	$ 0.00
Weighted Average Remaining Contractual Life	0 years

COMMON SHARES - Repurchased (Details) - CAD ($) $ / shares in Units, $ in Millions		1 Months Ended	12 Months Ended
	Nov. 19, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Number of shares approved to be repurchased and canceled from the Toronto Stock Exchange (in shares)	21,270,257
Number of common shares repurchased (in shares)		6,784,738
Average price per share of common shares repurchased (in Canadian dollars per share)		$ 43.29
Value recorded for common stock repurchased		$ 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)			6,785,000
Value recorded for common stock repurchased			$ 130	$ 0	$ 0
Additional Paid-In Capital
Class of Stock [Line Items]
Value recorded for common stock repurchased			$ 164	$ 0	$ 0

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2015 shares
Shareholder Rights Plan
Number of rights entitled to each common share	1
Number of common shares entitled to be purchased under each right	2

PREFERRED SHARES (Details) - CAD ($) $ / shares in Units, $ in Millions		1 Months Ended		12 Months Ended
	Dec. 31, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Preferred Shares [Line Items]
Preferred Shares	$ 2,499			$ 2,499	$ 2,255
Series 1
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)	9,498,000			9,498,000
Preferred shares, outstanding (in shares)	9,498,000			9,498,000
Current Yield				3.266%
Annual Dividend Rate per Share (in Canadian dollars per share)				$ 0.8165
Redemption Price Per Share (in Canadian dollars per share)	$ 25.00			$ 25.00
Preferred Shares	$ 233			$ 233	233
Series 1 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	1.92%			1.92%
Series 2
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)	12,502,000			12,502,000
Preferred shares, outstanding (in shares)	12,502,000			12,502,000
Current Yield	2.418%
Redemption Price Per Share (in Canadian dollars per share)	$ 25			$ 25
Preferred Shares	$ 306			$ 306	306
Series 2 \| Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	1.92%			1.92%
Series 3
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)	8,533,405			8,533,405
Preferred shares, outstanding (in shares)	8,533,000			8,533,000
Current Yield				2.152%
Annual Dividend Rate per Share (in Canadian dollars per share)				$ 0.538
Redemption Price Per Share (in Canadian dollars per share)	$ 25.00			$ 25.00
Preferred Shares	$ 209			$ 209	343
Number of shares converted		5,466,595
Period of time shares will pay dividends on a quarterly basis		5 years
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%			1.28%
Series 4
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)	5,467,000			5,467,000
Preferred shares, outstanding (in shares)	5,467,000			5,467,000
Current Yield	1.778%
Redemption Price Per Share (in Canadian dollars per share)	$ 25			$ 25
Preferred Shares	$ 134			$ 134
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum				90 days
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%			1.28%
Series 5
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)	14,000,000			14,000,000
Preferred shares, outstanding (in shares)	14,000,000			14,000,000
Current Yield				4.40%
Annual Dividend Rate per Share (in Canadian dollars per share)				$ 1.10
Redemption Price Per Share (in Canadian dollars per share)	$ 25.00			$ 25.00
Preferred Shares	$ 342			$ 342	342
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%			1.54%
Series 7
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)	24,000,000			24,000,000
Preferred shares, outstanding (in shares)	24,000,000			24,000,000
Current Yield				4.00%
Annual Dividend Rate per Share (in Canadian dollars per share)				$ 1.00
Redemption Price Per Share (in Canadian dollars per share)	$ 25			$ 25
Preferred Shares	$ 589			$ 589	589
Series 7 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	2.38%			2.38%
Series 9
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)	18,000,000			18,000,000
Preferred shares, outstanding (in shares)	18,000,000			18,000,000
Current Yield				4.25%
Annual Dividend Rate per Share (in Canadian dollars per share)				$ 1.0625
Redemption Price Per Share (in Canadian dollars per share)	$ 25			$ 25
Preferred Shares	$ 442			$ 442	$ 442
Series 9 \| Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	2.35%			2.35%
Series 11
Preferred Shares [Line Items]
Preferred shares, authorized (in shares)	10,000,000			10,000,000
Preferred shares, outstanding (in shares)	10,000,000			10,000,000
Current Yield				3.80%
Annual Dividend Rate per Share (in Canadian dollars per share)				$ 0.95
Redemption Price Per Share (in Canadian dollars per share)	$ 25			$ 25
Preferred Shares	$ 244			$ 244
Number of shares issued			10,000,000
Price per share (in Canadian dollars per share)			$ 25
Gross proceeds from public offering of preferred shares			$ 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%			2.96%
Series 2 and Series 4
Preferred Shares [Line Items]
Redemption Price Per Share (in Canadian dollars per share)	$ 25.50			$ 25.50
Redeemed on designated conversion date (in Canadian dollars per share)	$ 25.00			$ 25.00
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 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%			1.54%
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%			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%			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%			2.96%
Series 1, Series 3, Series 5, Series 7, Series 9 and Series 11
Preferred Shares [Line Items]
Period of time preferred stock or bond is considered for dividend yield calculation				5 years

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components - (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Before Tax Amount
Foreign currency translation gains on net investment in foreign operations	$ 798	$ 462	$ 269
Change in fair value of net investment hedges	(505)	(373)	(323)
Change in fair value of cash flow hedges	(92)	(118)	121
Reclassification to net income of gains and losses on cash flow hedges	144	(95)	60
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	74	(146)	96
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	41	25	34
Other comprehensive income on equity investments	62	(272)	313
Other comprehensive income (loss)	522	(517)	570
Income Tax Recovery/(Expense)
Foreign currency translation gains on net investment in foreign operations	15	55	114
Change in fair value of net investment hedges	133	97	84
Change in fair value of cash flow hedges	35	49	(50)
Reclassification to net income of gains and losses on cash flow hedges	(56)	40	(19)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(23)	44	(29)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	(9)	(7)	(11)
Other comprehensive income on equity investments	(15)	68	(79)
Other comprehensive income (loss)	80	346	10
Net of Tax Amount
Foreign currency translation gains on net investment in foreign operations	813	517	383
Change in fair value of net investment hedges	(372)	(276)	(239)
Change in fair value of cash flow hedges	(57)	(69)	71
Reclassification to net income of gains and losses on cash flow hedges	88	(55)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	51	(102)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	32	18	23
Other comprehensive income on equity investments	47	(204)	234
Other comprehensive income/(loss) (Note 21)	$ 602	$ (171)	$ 580

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	$ (1,235)	$ (934)	$ (1,448)
Other comprehensive income/(loss) before reclassifications	162	(266)	435
Amounts reclassified from accumulated other comprehensive loss	134	(35)	79
Net current period other comprehensive income	296	(301)	514
AOCI Balance	(939)	(1,235)	(934)
Other comprehensive income/(loss) before reclassifications attributable to noncontrolling interest	306	130	66
Cash flow hedge losses expected to be reclassified within the next twelve months, before tax	83
Cash flow hedge losses expected to be reclassified within the next twelve months, net of tax	51
Currency translation adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	(518)	(629)	(707)
Other comprehensive income/(loss) before reclassifications	135	111	78
Amounts reclassified from accumulated other comprehensive loss	0	0	0
Net current period other comprehensive income	135	111	78
AOCI Balance	(383)	(518)	(629)
Cash flow hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	(128)	(4)	(116)
Other comprehensive income/(loss) before reclassifications	(57)	(69)	71
Amounts reclassified from accumulated other comprehensive loss	88	(55)	41
Net current period other comprehensive income	31	(124)	112
AOCI Balance	(97)	(128)	(4)
Pension and OPEB plan adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	(281)	(197)	(287)
Other comprehensive income/(loss) before reclassifications	51	(102)	67
Amounts reclassified from accumulated other comprehensive loss	32	18	23
Net current period other comprehensive income	83	(84)	90
AOCI Balance	(198)	(281)	(197)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	(308)	(104)	(338)
Other comprehensive income/(loss) before reclassifications	33	(206)	219
Amounts reclassified from accumulated other comprehensive loss	14	2	15
Net current period other comprehensive income	47	(204)	234
AOCI Balance	$ (261)	$ (308)	$ (104)

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Energy)	$ 4,038	$ 3,725	$ 3,176
Interest expense	(1,370)	(1,198)	(985)
Income / (Loss) from Equity Investments	440	522	597
(Loss)/Income before income taxes	(1,106)	2,824	2,522
Income tax expense	(34)	(831)	(611)
Net (Loss)/Income Attributable to Controlling Interests	(1,146)	1,840	1,786
Amounts reclassified from accumulated other comprehensive loss \| Cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
(Loss)/Income before income taxes	(144)	95	(60)
Income tax expense	56	(40)	19
Net (Loss)/Income Attributable to Controlling Interests	(88)	55	(41)
Amounts reclassified from accumulated other comprehensive loss \| Cash flow hedges \| Commodities
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Energy)	(128)	111	(44)
Amounts reclassified from accumulated other comprehensive loss \| Cash flow hedges \| Interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(16)	(16)	(16)
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]
Amortization of actuarial loss and past service cost	(41)	(25)	(34)
(Loss)/Income before income taxes	9	7	11
Net (Loss)/Income Attributable to Controlling Interests	(32)	(18)	(23)
Amounts reclassified from accumulated other comprehensive loss \| Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income / (Loss) from Equity Investments	(19)	(2)	(20)
Income tax expense	5	0	5
Net (Loss)/Income Attributable to Controlling Interests	$ (14)	$ (2)	$ (15)

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments and Changes (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized	12 years	12 years	11 years
Expense for savings plan and DC Plans	$ 41	$ 37	$ 29
Cash Payments for Employee Post-Retirement Benefits [Abstract]
Savings and DC Plans	41	37	29
Total cash contributions	143	116	$ 114
Change in Plan Assets
Plan assets at fair value – beginning of year	2,437
Plan assets at fair value – end of year	2,636	2,437
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 11)	18	14
Other long-term liabilities (Note 14)	$ (380)	$ (444)
Pension Benefit Plans
Employee post-retirement benefits
Consecutive period of employment for highest average earnings	3 years
Expected average remaining service life of employees over which past service costs are amortized	9 years	9 years	9 years
Cash Payments for Employee Post-Retirement Benefits [Abstract]
DB Plans and Other post-retirement benefit plans	$ 96	$ 73	$ 79
Change in Benefit Obligation
Benefit obligation – beginning of year	2,658	2,224
Service cost	108	85	84
Interest cost	115	113	96
Employee contributions	4	4
Benefits paid	(129)	(102)
Actuarial (gain)/loss	(57)	302
Foreign exchange rate changes	81	32
Benefit obligation – end of year	2,780	2,658	2,224
Change in Plan Assets
Plan assets at fair value – beginning of year	2,398	2,152
Actual return on plan assets	160	246
Employer contributions	96	73	79
Employee contributions	4	4
Benefits paid	(129)	(102)
Foreign exchange rate changes	62	25
Plan assets at fair value – end of year	2,591	2,398	2,152
Funded Status – Plan Deficit	(189)	(260)
Amounts recognized in the Balance Sheet
Other long-term liabilities (Note 14)	(189)	(260)
Net	(189)	(260)
Pension Benefit Plans \| Canada
Employee post-retirement benefits
Letter of credit to the DB Plan	33	47	59
Total amount outstanding under letters of credit	214	181
Other Post-Retirement Benefit Plans
Cash Payments for Employee Post-Retirement Benefits [Abstract]
DB Plans and Other post-retirement benefit plans	6	6	6
Change in Benefit Obligation
Benefit obligation – beginning of year	216	191
Service cost	3	2	2
Interest cost	10	10	7
Benefits paid	(7)	(7)
Actuarial (gain)/loss	(11)	14
Foreign exchange rate changes	14	6
Benefit obligation – end of year	225	216	191
Change in Plan Assets
Plan assets at fair value – beginning of year	39	35
Actual return on plan assets	(1)	2
Employer contributions	6	6	6
Benefits paid	(7)	(7)
Foreign exchange rate changes	8	3
Plan assets at fair value – end of year	45	39	$ 35
Funded Status – Plan Deficit	(180)	(177)
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 11)	18	14
Accounts payable and other	(7)	(7)
Other long-term liabilities (Note 14)	(191)	(184)
Net	$ (180)	$ (177)

EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Funded status based on accumulated benefit obligation
Plan assets at fair value	$ 2,636	$ 2,437
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	$ (2,780)	$ (2,658)
Plan assets at fair value	2,591	2,398
Funded Status – Plan Deficit	(189)	(260)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(2,600)	(2,437)
Plan assets at fair value	2,591	2,398	$ 2,152
Funded Status – Plan Deficit	(9)	(39)
Accumulated benefit obligation and fair value of plan assets for plans that are not fully funded
Accumulated benefit obligation	(807)	(715)
Plan assets at fair value	680	597
Funded Status – Plan Deficit	$ (127)	$ (118)
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	34.00%	31.00%
Amount of debt or common shares included in plan assets	$ 2	$ 1
Percentage of Plan Assets	0.10%	0.10%
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	35.00%
Pension Benefit Plans \| Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	66.00%	69.00%
Amount of debt or common shares included in plan assets	$ 4	$ 1
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	50.00%
Pension Benefit Plans \| Equity securities \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	70.00%
Pension Benefit Plans \| Alternatives \| 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	$ (198)	$ (191)
Plan assets at fair value	0	0
Funded Status – Plan Deficit	(198)	(191)
Funded status based on accumulated benefit obligation
Plan assets at fair value	$ 45	$ 39	$ 35

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee post-retirement benefits
Fair value of plan assets	$ 2,636	$ 2,437
Percentage of Total Portfolio	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 1,118	$ 1,239
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1,504	1,185
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	14	13
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	$ 46	$ 20
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	$ 44	$ 20
Cash and Cash Equivalents \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	2	0
Equity securities \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 464	$ 503
Percentage of Total Portfolio	17.00%	21.00%
Equity securities \| U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 629	$ 551
Percentage of Total Portfolio	24.00%	23.00%
Equity securities \| International
Employee post-retirement benefits
Fair value of plan assets	$ 338	$ 365
Percentage of Total Portfolio	13.00%	15.00%
Equity securities \| Global
Employee post-retirement benefits
Fair value of plan assets	$ 154	$ 141
Percentage of Total Portfolio	6.00%	6.00%
Equity securities \| Emerging
Employee post-retirement benefits
Fair value of plan assets	$ 150	$ 87
Percentage of Total Portfolio	6.00%	3.00%
Equity securities \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 317	$ 361
Equity securities \| Quoted Prices in Active Markets (Level I) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	589	516
Equity securities \| Quoted Prices in Active Markets (Level I) \| International
Employee post-retirement benefits
Fair value of plan assets	38	218
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	7	7
Equity securities \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	147	142
Equity securities \| Significant Other Observable Inputs (Level II) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	40	35
Equity securities \| Significant Other Observable Inputs (Level II) \| International
Employee post-retirement benefits
Fair value of plan assets	300	147
Equity securities \| Significant Other Observable Inputs (Level II) \| Global
Employee post-retirement benefits
Fair value of plan assets	154	141
Equity securities \| Significant Other Observable Inputs (Level II) \| Emerging
Employee post-retirement benefits
Fair value of plan assets	143	80
Federal \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 206	$ 218
Percentage of Total Portfolio	8.00%	9.00%
Federal \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Federal \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	206	218
Provincial \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 202	$ 180
Percentage of Total Portfolio	8.00%	7.00%
Provincial \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Provincial \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	202	180
Municipal \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 7	$ 7
Percentage of Total Portfolio	0.00%	0.00%
Municipal \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Municipal \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	7	7
Corporate \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 113	$ 76
Percentage of Total Portfolio	4.00%	3.00%
Corporate \| U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 57	$ 59
Percentage of Total Portfolio	2.00%	2.00%
Corporate \| International
Employee post-retirement benefits
Fair value of plan assets	$ 25	$ 14
Percentage of Total Portfolio	1.00%	1.00%
Corporate \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Corporate \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	113	76
Corporate \| Significant Other Observable Inputs (Level II) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	57	59
Corporate \| Significant Other Observable Inputs (Level II) \| International
Employee post-retirement benefits
Fair value of plan assets	25	14
State \| U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 50	$ 47
Percentage of Total Portfolio	2.00%	2.00%
State \| Significant Other Observable Inputs (Level II) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 50	$ 47
Mortgage Backed \| International
Employee post-retirement benefits
Fair value of plan assets	$ 58	$ 39
Percentage of Total Portfolio	2.00%	2.00%
Mortgage Backed \| Significant Other Observable Inputs (Level II) \| International
Employee post-retirement benefits
Fair value of plan assets	$ 58	$ 39
Other Investments: Private Equity Funds
Employee post-retirement benefits
Fair value of plan assets	$ 14	$ 13
Percentage of Total Portfolio	0.00%	0.00%
Other Investments: Private Equity Funds \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Other Investments: Private Equity Funds \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Other Investments: Private Equity Funds \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	14	13	$ 18
Other Investments: Funds Held on Deposit
Employee post-retirement benefits
Fair value of plan assets	$ 123	$ 117
Percentage of Total Portfolio	5.00%	5.00%
Other Investments: Funds Held on Deposit \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 123	$ 117
Other Investments: Funds Held on Deposit \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0

EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	$ 2,437
Plan assets at fair value – end of year	2,636	$ 2,437
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	13
Plan assets at fair value – end of year	14	13
Private Equity Funds
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	13
Plan assets at fair value – end of year	14	13
Private Equity Funds \| Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	13	18
Purchases and sales	(1)	(7)
Realized and unrealized gains	2	2
Plan assets at fair value – end of year	$ 14	$ 13

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	$ 37
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	$ 1
Effect on total of service and interest cost components, Decrease	(1)
Effect on post-retirement benefit obligation, Increase	14
Effect on post-retirement benefit obligation, Decrease	(12)
Pension Benefit Plans
DB Plans
Company's expected funding contributions	70
Estimated future benefit payments, which reflect expected future service
2016	129
2017	133
2018	138
2019	142
2020	146
2021 to 2025	$ 808
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.20%	4.15%
Rate of compensation increase	0.50%	3.15%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	4.15%	4.95%	4.35%
Expected long-term rate of return on plan assets	6.95%	6.90%	6.70%
Rate of compensation increase	3.15%	3.15%	3.15%
Net benefit cost
Service cost	$ 108	$ 85	$ 84
Interest cost	115	113	96
Expected return on plan assets	(155)	(139)	(120)
Amortization of actuarial loss	35	21	30
Amortization of past service cost	2	2	2
Amortization of regulatory asset	23	18	30
Amortization of transitional obligation related to regulated business	0	0	0
Net Benefit Cost Recognized	128	100	122
Pre-tax amounts recognized in AOCI
Net loss	247	348	236
Prior service cost	0	2	3
Total pre-tax amounts recognized in AOCI	247	350	239
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	21
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to OCI	(34)	(21)	(30)
Amortization of prior service costs from AOCI to OCI	(2)	(2)	(2)
Funded status adjustment	(67)	137	(96)
Total pre-tax amounts recognized in OCI	(103)	114	$ (128)
Pension Benefit Plans \| Canada
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	214	$ 181
Pension Benefit Plans \| Canada \| Scenario, Plan
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	33
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	7
Estimated future benefit payments, which reflect expected future service
2016	8
2017	9
2018	9
2019	9
2020	10
2021 to 2025	$ 51
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.40%	4.20%
Rate of compensation increase	0.00%	0.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	4.20%	5.00%	4.35%
Expected long-term rate of return on plan assets	4.60%	4.60%	4.60%
Rate of compensation increase	0.00%	0.00%	0.00%
Net benefit cost
Service cost	$ 3	$ 2	$ 2
Interest cost	10	10	7
Expected return on plan assets	(2)	(2)	(2)
Amortization of actuarial loss	3	2	2
Amortization of past service cost	1	0	0
Amortization of regulatory asset	1	1	1
Amortization of transitional obligation related to regulated business	2	2	2
Net Benefit Cost Recognized	18	15	12
Pre-tax amounts recognized in AOCI
Net loss	28	39	32
Prior service cost	0	1	1
Total pre-tax amounts recognized in AOCI	28	40	33
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	3
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to OCI	(4)	(2)	(2)
Amortization of prior service costs from AOCI to OCI	(1)	0	0
Funded status adjustment	(7)	9	0
Total pre-tax amounts recognized in OCI	$ (12)	$ 7	$ (2)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge $ in Millions, $ in Millions	Dec. 31, 2015 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Debt carrying value	$ 23,000		$ 17,000
Debt fair value	$ 23,800		$ 19,000
US$ denominated
Derivative [Line Items]
Debt carrying value		$ 16,600		$ 14,700
Debt fair value		$ 17,200		$ 16,400

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) - Designated as a net investment hedge $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Fair value	$ (680)	$ (459)
US$ denominated
Derivative [Line Items]
Notional or Principal Amount			$ 4,950	$ 4,300
Cross-currency interest rate swaps
Derivative [Line Items]
Fair value	(730)	(431)
Cross-currency interest rate swaps \| US$ denominated
Derivative [Line Items]
Notional or Principal Amount			3,150	2,900
Net realized gains related to the interest component	8	21
Forward foreign exchange contracts
Derivative [Line Items]
Fair value	$ 50	$ (28)
Forward foreign exchange contracts \| US$ denominated
Derivative [Line Items]
Notional or Principal Amount			$ 1,800	$ 1,400

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Carrying and fair values of non-derivative financial instruments
Current and Long-Term Debt	$ (31,584)	$ (24,757)
Junior subordinated notes (Note 17)	(2,422)	(1,160)
Long-term Debt			$ 850	$ 400
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Fair value adjustments - gains (losses)	2	(3)
Long-term debt hedged			$ 850	$ 400
Level II \| Carrying Amount
Carrying and fair values of non-derivative financial instruments
Notes receivable	214	213
Current and Long-Term Debt	(31,584)	(24,757)
Junior subordinated notes (Note 17)	(2,422)	(1,160)
Total liabilities	(33,792)	(25,704)
Level II \| Fair Value
Carrying and fair values of non-derivative financial instruments
Notes receivable	265	263
Current and Long-Term Debt	(34,309)	(28,713)
Junior subordinated notes (Note 17)	(2,011)	(1,157)
Total liabilities	$ (36,055)	$ (29,607)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD ($) GWh Bcf	Dec. 31, 2014 CAD ($) GWh Bcf	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	$ 610	$ 502
Gross derivative liabilities presented on the balance sheet	(1,551)	(1,160)
Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	456	436
Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	57	57
Gross derivative liabilities presented on the balance sheet	(145)	(165)
Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	3	3
Gross derivative liabilities presented on the balance sheet	(2)
Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	94	6
Gross derivative liabilities presented on the balance sheet	(774)	(465)
Commodities \| Power
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	509	488
Gross derivative liabilities presented on the balance sheet	$ (717)	$ (657)
Commodities \| Power \| Not designated as hedging instrument \| Purchases
Derivatives, Fair Value [Line Items]
Power \| GWh	70,331	53,217
Commodities \| Power \| Not designated as hedging instrument \| Sales
Derivatives, Fair Value [Line Items]
Power \| GWh	54,382	39,429
Commodities \| Natural Gas \| Not designated as hedging instrument \| Purchases
Derivatives, Fair Value [Line Items]
Natural gas \| Bcf	133	60
Commodities \| Natural Gas \| Not designated as hedging instrument \| Sales
Derivatives, Fair Value [Line Items]
Natural gas \| Bcf	70	38
Commodities \| Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	$ (630)	$ (530)
Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	96	7
Gross derivative liabilities presented on the balance sheet	(828)	(497)
Notional or Principal Amount			$ 1,476	$ 1,374
Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	5	7
Gross derivative liabilities presented on the balance sheet	(6)	(6)
Notional or Principal Amount			$ 1,100	$ 650
Other current assets
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	442	409
Other current assets \| Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	330	363
Other current assets \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	46	39
Other current assets \| Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	1	2
Other current assets \| Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	65	5
Other current assets \| Commodities
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	372	398
Other current assets \| Commodities \| Commodities
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	326	359
Other current assets \| Commodities \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	46	39
Other current assets \| Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	67	6
Other current assets \| Foreign exchange \| Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	1
Other current assets \| Foreign exchange \| Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	65	5
Other current assets \| Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	3	5
Other current assets \| Interest rate \| Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	3
Other current assets \| Interest rate \| Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	1	2
Intangible and other assets
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	168	93
Intangible and other assets \| Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	126	73
Intangible and other assets \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	11	18
Intangible and other assets \| Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	1
Intangible and other assets \| Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	29	1
Intangible and other assets \| Commodities
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	137	90
Intangible and other assets \| Commodities \| Commodities
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	126	72
Intangible and other assets \| Commodities \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	11	18
Intangible and other assets \| Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	29	1
Intangible and other assets \| Foreign exchange \| Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	29	1
Intangible and other assets \| Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	2
Intangible and other assets \| Interest rate \| Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet		1
Intangible and other assets \| Interest rate \| Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	1
Accounts payable and other
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(926)	(749)
Accounts payable and other \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(113)	(137)
Accounts payable and other \| Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)
Accounts payable and other \| Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(313)	(155)
Accounts payable and other \| Commodities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(555)	(558)
Accounts payable and other \| Commodities \| Commodities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(443)	(422)
Accounts payable and other \| Commodities \| Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(54)	(32)
Accounts payable and other \| Commodities \| Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(2)	(3)
Accounts payable and other \| Commodities \| Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(499)	(457)
Accounts payable and other \| Commodities \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(112)	(136)
Accounts payable and other \| Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(367)	(187)
Accounts payable and other \| Foreign exchange \| Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(313)	(155)
Accounts payable and other \| Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(4)	(4)
Accounts payable and other \| Interest rate \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)	(1)
Accounts payable and other \| Interest rate \| Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)
Other long-term liabilities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(625)	(411)
Other long-term liabilities \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(32)	(28)
Other long-term liabilities \| Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)
Other long-term liabilities \| Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(461)	(310)
Other long-term liabilities \| Commodities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(162)	(99)
Other long-term liabilities \| Commodities \| Commodities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(131)	(72)
Other long-term liabilities \| Commodities \| Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet		(1)
Other long-term liabilities \| Commodities \| Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(131)	(73)
Other long-term liabilities \| Commodities \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(31)	(27)
Other long-term liabilities \| Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(461)	(310)
Other long-term liabilities \| Foreign exchange \| Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(461)	(310)
Other long-term liabilities \| Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(2)	(2)
Other long-term liabilities \| Interest rate \| Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)	(1)
Other long-term liabilities \| Interest rate \| Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)
Fixed income securities \| LMCI Restricted Investments
Derivatives, Fair Value [Line Items]
Fixed income securities (maturing after 10 years)	261
Fixed income securities	261
Fixed income securities \| Other Restricted Investments
Derivatives, Fair Value [Line Items]
Fixed income securities (maturing within 5 years)	90	75
Fixed income securities	$ 90	$ 75

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses)/Gains (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value Hedges \| Interest expense
Derivative [Line Items]
Amount of realized (losses)/gains in the year	$ 11	$ 7
Commodity contract
Derivative [Line Items]
Unrealized losses on derivative instruments held for trading	(37)	(40)
Realized losses on derivative instruments held for trading	(151)	(28)
Commodity contract \| Derivative Financial Instruments in Hedging Relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	(179)	130
Foreign exchange
Derivative [Line Items]
Unrealized losses on derivative instruments held for trading	(21)	(20)
Realized losses on derivative instruments held for trading	(112)	(28)
Interest rate \| Derivative Financial Instruments in Hedging Relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	$ 8	$ 4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - Cash Flow Hedges - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	$ (92)	$ (118)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion)	144	(95)
Commodities \| Power
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	(92)	(128)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion)	128	(111)
Losses on derivative instruments recognized in Net income (ineffective portion)		(13)
Foreign exchange
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)		10
Interest rate
Components of OCI related to derivatives
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion)	$ 16	$ 16

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative - Asset
Gross derivative assets presented on the balance sheet	$ 610	$ 502
Amounts available for offset	(512)	(395)
Net Amounts	98	107
Derivative - Liability
Gross derivative liabilities presented on the balance sheet	(1,551)	(1,160)
Amounts available for offset	512	395
Net Amounts	(1,039)	(765)
Cash collateral provided by the Company	482	459
Letters of credit provided by the Company	41	26
Cash collateral received by the Company		1
Letters of credit received by the Company	2	1
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	32	15
Additional collateral required if credit-risk-related contingent features were triggered	32	15
Foreign exchange
Derivative - Asset
Gross derivative assets presented on the balance sheet	96	7
Amounts available for offset	(93)	(7)
Net Amounts	3	0
Derivative - Liability
Gross derivative liabilities presented on the balance sheet	(828)	(497)
Amounts available for offset	93	7
Net Amounts	(735)	(490)
Interest rate
Derivative - Asset
Gross derivative assets presented on the balance sheet	5	7
Amounts available for offset	(1)	(1)
Net Amounts	4	6
Derivative - Liability
Gross derivative liabilities presented on the balance sheet	(6)	(6)
Amounts available for offset	1	1
Net Amounts	(5)	(5)
Power \| Commodities
Derivative - Asset
Gross derivative assets presented on the balance sheet	509	488
Amounts available for offset	(418)	(387)
Net Amounts	91	101
Derivative - Liability
Gross derivative liabilities presented on the balance sheet	(717)	(657)
Amounts available for offset	418	387
Net Amounts	$ (299)	$ (270)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Hierarchy
Derivative Instrument Assets	$ 610	$ 502
Derivative Instrument Liabilities	(1,551)	(1,160)
Commodity contract \| Power
Fair Value Hierarchy
Derivative Instrument Assets	509	488
Derivative Instrument Liabilities	(717)	(657)
Foreign exchange contracts
Fair Value Hierarchy
Derivative Instrument Assets	96	7
Derivative Instrument Liabilities	(828)	(497)
Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	5	7
Derivative Instrument Liabilities	(6)	(6)
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	(941)	(658)
Recurring basis \| Commodity contract \| Power
Fair Value Hierarchy
Derivative Instrument Assets	509	488
Derivative Instrument Liabilities	(717)	(657)
Recurring basis \| Foreign exchange contracts
Fair Value Hierarchy
Derivative Instrument Assets	96	7
Derivative Instrument Liabilities	(828)	(497)
Recurring basis \| Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	5	7
Derivative Instrument Liabilities	(6)	(6)
Recurring basis \| Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	(68)	(46)
Recurring basis \| Quoted Prices in Active Markets (Level I) \| Commodity contract \| Power
Fair Value Hierarchy
Derivative Instrument Assets	34	40
Derivative Instrument Liabilities	(102)	(86)
Recurring basis \| Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Assets and (liabilities), net	(882)	(616)
Recurring basis \| Significant Other Observable Inputs (Level II) \| Commodity contract \| Power
Fair Value Hierarchy
Derivative Instrument Assets	462	441
Derivative Instrument Liabilities	(611)	(568)
Recurring basis \| Significant Other Observable Inputs (Level II) \| Foreign exchange contracts
Fair Value Hierarchy
Derivative Instrument Assets	96	7
Derivative Instrument Liabilities	(828)	(497)
Recurring basis \| Significant Other Observable Inputs (Level II) \| Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	5	7
Derivative Instrument Liabilities	(6)	(6)
Recurring basis \| Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	9	4
Recurring basis \| Significant Unobservable Inputs (Level III) \| Commodity contract \| Power
Fair Value Hierarchy
Derivative Instrument Assets	13	7
Derivative Instrument Liabilities	$ (4)	$ (3)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Energy Revenue
Net change in the Level III fair value category
Revenues include unrealized gains attributed to derivatives in the Level III category	$ 7	$ 3
Commodity contract \| Power
Net change in the Level III fair value category
Balance at beginning of year	4	1
Transfers out of Level III	5	0
Total gains included in Net income	3	3
Sales	(2)	0
Settlements	(1)	0
Balance at end of year	9	$ 4
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	$ 2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2014 USD ($)
Risk Management and Financial Instruments [Abstract]
Credit risk concentration	$ 248	$ 179	$ 258	$ 222

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CHANGES IN OPERATING WORKING CAPITAL
Increase in Accounts receivable	$ (66)	$ (189)	$ (54)
Increase in Inventories	(3)	(28)	(30)
(Increase)/decrease in Other current assets	(267)	(385)	40
(Decrease)/increase in Accounts payable and other	(153)	377	(290)
Increase in Accrued interest	91	36	8
Increase in Operating Working Capital	$ (398)	$ (189)	$ (326)

ACQUISITIONS AND DISPOSITIONS (Details) $ / shares in Units, $ in Millions, $ in Millions						1 Months Ended			12 Months Ended			24 Months Ended
	Dec. 03, 2015 CAD ($)	Apr. 01, 2015 USD ($)	Nov. 26, 2014 CAD ($)	Oct. 01, 2014 USD ($)	Apr. 15, 2014 CAD ($)	Jul. 31, 2013 USD ($)	May 31, 2013 CAD ($) shares	May 31, 2013 USD ($) $ / shares shares	Dec. 31, 2015 CAD ($)	Dec. 31, 2014 CAD ($) facility	Dec. 31, 2013 CAD ($) facility	Dec. 31, 2014 facility	Dec. 30, 2015	Dec. 04, 2015	Dec. 02, 2015	Apr. 30, 2013
ACQUISITIONS AND DISPOSITIONS
Proceeds from sale of assets, net of transaction costs (Note 25)									$ 0	$ 196	$ 0
Gain (loss) on disposal									(125)	117	0
Contributions made to equity investments									493	256	163
Purchase price									236	$ 241	$ 216
Gas Pacifico and INNERGY \| Disposal group, not discontinued operations
ACQUISITIONS AND DISPOSITIONS
Ownership interest			30.00%
Proceeds from sale of assets, net of transaction costs (Note 25)			$ 9
Gain (loss) on disposal			9
Proceeds from sale of assets, net of tax			$ 8
Cancarb Limited \| Disposal group, not discontinued operations
ACQUISITIONS AND DISPOSITIONS
Proceeds from sale of assets, net of transaction costs (Note 25)					$ 190
Gain (loss) on disposition, gross					108
Gain (loss) on disposition, net of tax					$ 99
Gas Transmission Northwest LLC \| Natural Gas
ACQUISITIONS AND DISPOSITIONS
Ownership interest before transaction						45.00%
Ontario solar projects \| Energy
ACQUISITIONS AND DISPOSITIONS
Number of facilities acquired \| facility										4	4	8
Purchase price									$ 457	$ 241	$ 216
Term of contract to sell solar power									20 years
TC PipeLines, LP
ACQUISITIONS AND DISPOSITIONS
Number of common units sold in an underwritten public offering (in shares) \| shares							8,855,000	8,855,000
Price per common unit issued (in dollars per unit) \| $ / shares								$ 43.85
Gross proceeds from public offering								$ 388
Net proceeds from issuance of common units								373
Capital contribution made to maintain general partnership interest								$ 8
General partnership interest							2.00%	2.00%
Ownership interest in subsidiary							28.90%	28.90%	28.00%	28.30%	28.90%	28.30%				33.30%
After-tax dilution gain recorded in additional paid-in capital							$ 29
Pre-tax dilution gain recorded in additional paid-in capital as a result of decrease in ownership interest							$ 47
Gas Transmission Northwest \| Disposal group, disposed of by sale, not discontinued operations \| Natural Gas
ACQUISITIONS AND DISPOSITIONS
Ownership interest before transaction		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
ACQUISITIONS AND DISPOSITIONS
Receipt of new units		$ 95
Bison LLC \| Natural Gas
ACQUISITIONS AND DISPOSITIONS
Ownership interest before transaction				30.00%
Cash received				$ 215
GTN LLC and Bison LLC \| Natural Gas
ACQUISITIONS AND DISPOSITIONS
Cash received						$ 1,050
Long-term debt included in aggregate purchase price						$ 146
Percentage of acquired long-term debt						45.00%
Bruce Power
ACQUISITIONS AND DISPOSITIONS
Ownership interest									48.50%					48.50%
Bruce Power \| Energy
ACQUISITIONS AND DISPOSITIONS
Ownership interest									48.50%
Bruce B
ACQUISITIONS AND DISPOSITIONS
Ownership interest	46.50%												31.60%		31.60%
Additional ownership acquired	14.89%
Contributions made to equity investments	$ 236
Bruce A
ACQUISITIONS AND DISPOSITIONS
Ownership interest													48.90%		48.90%

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Operating Leases (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Minimum Lease Payments
2016	$ 354
2017	355
2018	270
2019	248
2020	185
2021 and thereafter	311
Minimum Lease Payments	1,723
Amounts Recoverable under Sub-leases
2016	46
2017	45
2018	26
2019	24
2020	20
2021 and thereafter	1
Amounts Recoverable under Sub-leases	162
Net Payments
2016	308
2017	310
2018	244
2019	224
2020	165
2021 and thereafter	310
Net Payments	1,561
Rent Expense
Net rental expense on operating leases	$ 131	$ 114	$ 98
Minimum
Rent Expense
Operating leases optional renewable terms, low end of range	1 year
Maximum
Rent Expense
Operating leases optional renewable terms, low end of range	25 years

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Power Purchase Arrangements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD ($) MW	Dec. 31, 2014 CAD ($)	Dec. 31, 2013 CAD ($)
Alberta PPAs
Commitments under operating leases
Share of payments under PPAs \| $	$ 348	$ 391	$ 242
Sundance A (expires 2017)
Commitments under operating leases
Power generating capacities under PPAs (in megawatts)	560
Sheerness (expires 2020)
Commitments under operating leases
Power generating capacities under PPAs (in megawatts)	756

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Other Commitments and Contingencies (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2013 CAD ($)
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites	$ 32		$ 31	$ 32
Ironwood
Other Commitments
Purchase price		$ 657
Natural Gas Pipelines \| Capital expenditures
Other Commitments
Commitment for capital expenditures	900		900
Liquids Pipelines \| Capital expenditures
Other Commitments
Commitment for capital expenditures	800		1,800
Energy \| Capital expenditures
Other Commitments
Commitment for capital expenditures	$ 600		$ 200

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) $ in Millions	Dec. 31, 2015 CAD ($) guarantee	Dec. 31, 2014 CAD ($) guarantee
Guarantees
Number of guarantees without a termination date \| guarantee	1	1
Contingent financial obligation
Guarantees
Potential Exposure	$ 227	$ 738
Carrying Value	26	20
Contingent financial obligation \| Bruce Power
Guarantees
Potential Exposure	88	634
Carrying Value	2	6
Contingent financial obligation \| Other
Guarantees
Potential Exposure	139	104
Carrying Value	$ 24	$ 14

CORPORATE RESTRUCTURING COSTS (Details) - Employee severance $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD ($)
Restructuring Cost and Reserve [Line Items]
Corporate restructuring costs incurred	$ 122
Provision recorded for restructuring charges	87
Total corporate restructuring charges	209
Restructuring costs recoverable through regulatory and tolling structures	58
Restructuring costs capitalized	8
Regulatory asset
Restructuring Cost and Reserve [Line Items]
Total corporate restructuring charges	44
Plant operating cost and other
Restructuring Cost and Reserve [Line Items]
Total corporate restructuring charges	$ 157

SUBSEQUENT EVENTS (Details)				12 Months Ended
SUBSEQUENT EVENTS (Details)	Feb. 01, 2016 USD ($) MW	Jan. 06, 2016 USD ($)	Jan. 01, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jan. 27, 2016 USD ($)
Ironwood
Subsequent Event [Line Items]
Purchase price				$ 657,000,000
Subsequent event \| Ironwood
Subsequent Event [Line Items]
Power plant capacity (in megawatts) \| MW	778
Purchase price	$ 657,000,000
Subsequent event \| PNGTS
Subsequent Event [Line Items]
Ownership interest before transaction			49.90%
Total consideration			$ 223,000,000
Subsequent event \| TCPL \| Senior notes \| Senior notes, due January 22, 2026, 4.875%
Subsequent Event [Line Items]
Debt					$ 850,000,000
Stated interest rate					4.875%
Subsequent event \| TCPL \| Senior notes \| Senior notes, due January 22, 2019, 3.125%
Subsequent Event [Line Items]
Debt					$ 400,000,000
Stated interest rate					3.125%
Subsequent event \| Claim under Chapter 11 of North American Free Trade Agreement \| Pending litigation
Subsequent Event [Line Items]
Costs and damages sought (more than)		$ 15,000,000,000