TransCanada Pipelines 40-F 11 Feb 16 2015 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2015shares
Document and Entity Information
Entity Registrant Name	TRANSCANADA PIPELINES LTD
Entity Central Index Key	99,070
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	779,605,870
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENT OF INCOM

CONSOLIDATED STATEMENT OF INCOME - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Natural Gas Pipelines	CAD 5,383	CAD 4,913	CAD 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
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
Financial Charges
Interest expense (Note 16)	1,398	1,235	1,046
Interest income and other	(192)	(128)	(72)
Total Financial Charges/(Income)	1,206	1,107	974
(Loss)/Income before Income Taxes	(1,105)	2,824	2,499
Income Tax Expense/(Recovery) (Note 15)
Current	137	146	43
Deferred	(102)	684	562
Total Income Tax Expense/(Recovery)	35	830	605
Net (Loss)/Income	(1,140)	1,994	1,894
Net Income attributable to non-controlling interests (Note 18)	6	151	105
Net (Loss)/Income Attributable to Controlling Interests	(1,146)	1,843	1,789
Preferred share dividends		2	20
Net (Loss)/Income Attributable to Common Shares	CAD (1,146)	CAD 1,841	CAD 1,769

CONSOLIDATED STATEMENT OF COMPR

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net (Loss)/Income	CAD (1,140)	CAD 1,994	CAD 1,894
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)	1,823	2,474
Comprehensive income attributable to non-controlling interests	312	281	171
Comprehensive (Loss)/Income Attributable to Controlling Interests	(850)	1,542	2,303
Preferred share dividends		2	20
Comprehensive (Loss)/Income Attributable to Common Shares	CAD (850)	CAD 1,540	CAD 2,283

CONSOLIDATED STATEMENT OF CASH

CONSOLIDATED STATEMENT OF CASH FLOWS - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Generated from Operations
Net (Loss)/Income	CAD (1,140)	CAD 1,994	CAD 1,894
Depreciation and amortization	1,765	1,611	1,485
Asset impairment charges (Note 7)	3,745
Deferred income taxes (Note 15)	(102)	684	562
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)
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)	(359)	(189)	(334)
Net cash provided by operations	4,154	4,078	3,643
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)		196
Distributions in excess of equity earnings (Note 8)	226	159	128
Deferred amounts and other	324	335	(117)
Net cash used in investing activities	(4,608)	(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
Advances to affiliates, net	(189)	(694)	(297)
Dividends on common shares	(1,446)	(1,345)	(1,286)
Dividends on preferred shares		(4)	(22)
Distributions paid to non-controlling interests	(224)	(174)	(146)
Common shares issued		1,115	899
Partnership units of subsidiary issued, net of issue costs	55	79	384
Preferred shares redeemed (Note 20)		(200)	(200)
Net cash provided by/(used in) financing activities	671	(345)	1,807
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	112		28
Increase/(Decrease) in Cash and Cash Equivalents	329	(411)	358
Cash and Cash Equivalents, Beginning of year	484	895	537
Cash and Cash Equivalents, End of year	CAD 813	CAD 484	CAD 895

CONSOLIDATED BALANCE SHEET

CONSOLIDATED BALANCE SHEET - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	CAD 813	CAD 484
Accounts receivable (Note 28)	1,401	1,372
Due from affiliates (Note 28)	2,476	2,842
Inventories	323	292
Other (Note 5)	1,353	1,018
Total Current Assets	6,366	6,008
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)	3,185	2,641
Restricted Investments	351	63
Total Assets	66,929	61,415
Current Liabilities
Notes payable (Note 12)	1,218	2,467
Accounts payable and other (Note 13 and 28)	3,014	2,891
Due to affiliates (Note 28)	311	866
Accrued interest	520	425
Current portion of long-term debt (Note 16)	2,547	1,797
Total Current Liabilities	7,610	8,446
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	4,856
Long-Term Debt (Note 16)	29,037	22,960
Junior Subordinated Notes (Note 17)	2,422	1,160
Total Liabilities	46,632	38,737
EQUITY
Common shares, no par value (Note 19); Issued and outstanding: December 31, 2015 779 million shares; December 31, 2014 - 779 million shares	16,320	16,320
Additional paid-in capital	210	404
Retained earnings	2,989	5,606
Accumulated other comprehensive loss (Note 21)	(939)	(1,235)
Controlling interests	18,580	21,095
Non-controlling interests (Note 18)	1,717	1,583
Total Equity	20,297	22,678
Total Liabilities and Equity	CAD 66,929	CAD 61,415

CONSOLIDATED BALANCE SHEET (Par

CONSOLIDATED BALANCE SHEET (Parenthetical) - shares shares in Millions	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common shares issued (in shares)	779	779
Common shares outstanding (in shares)	779	779

CONSOLIDATED STATEMENT OF EQUIT

CONSOLIDATED STATEMENT OF EQUITY - CAD CAD in Millions	Total	Equity Attributable to Controlling Interests	Common Shares	Preferred Shares	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Equity Attributable to Non-Controlling Interests
Beginning balance at Dec. 31, 2012			CAD 14,306	CAD 389	CAD 400	CAD 4,657	CAD (1,448)
Increase (decrease) in equity
Proceeds from shares issued (Note 19)			899
Issuance of stock options, net of exercises					7
Dilution impact from TC PipeLines, LP units issued					29			CAD 384
Redemption of preferred shares				(195)	(5)
Net (loss)/income attributable to controlling interests	CAD 1,789					1,789
Common share dividends						(1,301)
Preferred share dividends						(20)
Other comprehensive income/(loss) (Note 21)	580						514
Ending balance at Dec. 31, 2013		CAD 20,021	15,205	194	431	5,125	(934)
Beginning balance at Dec. 31, 2012								1,036
Equity Attributable to Non-Controlling Interests
TC PipeLines, LP								93
Portland Natural Gas Transmission System	105							12
Other comprehensive income attributable to non-controlling interests								66
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					29			384
Decrease in TCPL's ownership of TC PipeLines, LP								(47)
Distributions declared to non-controlling interests								(146)
Other								19
Ending balance at Dec. 31, 2013								1,417
Issuance of TC PipeLines, LP units
Total Equity	21,438
Proceeds from shares issued (Note 19)			1,115
Issuance of stock options, net of exercises					7
Dilution impact from TC PipeLines, LP units issued					9			79
Redemption of preferred shares				CAD (194)	(6)
Impact of asset drop downs to TC PipeLines, LP (Note 25)					(37)
Net (loss)/income attributable to controlling interests	1,843					1,843
Common share dividends						(1,360)
Preferred share dividends						(2)
Other comprehensive income/(loss) (Note 21)	(171)						(301)
Ending balance at Dec. 31, 2014	21,095	21,095	16,320		404	5,606	(1,235)
Equity Attributable to Non-Controlling Interests
TC PipeLines, LP								136
Portland Natural Gas Transmission System	151							15
Other comprehensive income attributable to non-controlling interests								130
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					9			79
Decrease in TCPL's ownership of TC PipeLines, LP								(14)
Distributions declared to non-controlling interests								(180)
Ending balance at Dec. 31, 2014	1,583							1,583
Issuance of TC PipeLines, LP units
Total Equity	22,678
Issuance of stock options, net of exercises					13
Dilution impact from TC PipeLines, LP units issued					6			55
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)
Other comprehensive income/(loss) (Note 21)	602						296
Ending balance at Dec. 31, 2015	18,580	CAD 18,580	CAD 16,320		210	CAD 2,989	CAD (939)
Equity Attributable to Non-Controlling Interests
TC PipeLines, LP								(13)
Portland Natural Gas Transmission System	6							19
Other comprehensive income attributable to non-controlling interests								306
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					CAD 6			55
Decrease in TCPL's ownership of TC PipeLines, LP								(11)
Distributions declared to non-controlling interests								(222)
Ending balance at Dec. 31, 2015	1,717							CAD 1,717
Issuance of TC PipeLines, LP units
Total Equity	CAD 20,297

DESCRIPTION OF TCPL'S BUSINESS

DESCRIPTION OF TCPL'S BUSINESS	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
DESCRIPTION OF TCPL'S BUSINESS	DESCRIPTION OF TCPL'S BUSINESS TransCanada PipeLines Limited (TCPL 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. The Company is a wholly-owned subsidiary of TransCanada Corporation (TransCanada). 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

ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
ACCOUNTING POLICIES	ACCOUNTING POLICIES The Company's consolidated financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles (GAAP). Amounts are stated in Canadian dollars unless otherwise indicated. Basis of Presentation The consolidated financial statements include the accounts of TCPL 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. TCPL 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. TCPL 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, TCPL 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 TCPL'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. TCPL'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 TCPL 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 TCPL 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 TCPL 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), TCPL 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 TCPL are not attributed a value for accounting purposes. When required, TCPL 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 The Company's Stock Option Plan permits options for the purchase of TransCanada 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. TCPL records the compensation expense associated with these stock options. 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

ACCOUNTING CHANGES	12 Months Ended
	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.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION year ended December 31, 2015 Natural Gas Liquids Energy Corporate Total (millions of Canadian $) 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 (1,398 ) Interest income and other 192 Loss before income taxes (1,105 ) Income tax expense (35 ) Net loss (1,140 ) Net income attributable to non-controlling interests (6 ) Net loss attributable to controlling interests (1,146 ) Preferred share dividends — Net loss attributable to common shares (1,146 ) 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 Liquids Energy Corporate Total (millions of Canadian $) 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 (1,235 ) Interest income and other 128 Income before income taxes 2,824 Income tax expense (830 ) Net income 1,994 Net income attributable to non-controlling interests (151 ) Net income attributable to controlling interests 1,843 Preferred share dividends (2 ) Net income attributable to common shares 1,841 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 Liquids Energy Corporate Total (millions of Canadian $) 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 (1,046 ) Interest income and other 72 Income before income taxes 2,499 Income tax expense (605 ) Net income 1,894 Net income attributable to non-controlling interests (105 ) Net income attributable to controlling interests 1,789 Preferred share dividends (20 ) Net income attributable to common shares 1,769 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 $) Total Assets Natural Gas Pipelines 31,072 27,103 Liquids Pipelines 16,046 16,116 Energy 15,558 14,197 Corporate 4,253 3,999 66,929 61,415 Geographic Information year ended December 31 2015 2014 2013 (millions of Canadian $) 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 $) 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

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2015
Other Assets [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS at December 31 2014 (millions of Canadian $) 2015 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 221 170 1,353 1,018

ASSETS HELD FOR SALE

ASSETS HELD FOR SALE	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
ASSETS HELD FOR SALE	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 $) 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

PLANT, PROPERTY AND EQUIPMENT	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
PLANT, PROPERTY AND EQUIPMENT	PLANT, PROPERTY AND EQUIPMENT 2015 2014 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) 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 ANR 1 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 Other 2 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 Solar 5 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. 3 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

EQUITY INVESTMENTS	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	EQUITY INVESTMENTS (millions of Canadian $) Ownership Income / (Loss) from Equity Investments Equity Investments year ended December 31 at December 31 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 1 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 , TCPL 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. 3 As a result of TCPL'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, TCPL has an ownership interest in Bruce Power of 48.5 per cent. Prior to the acquisition and merger, TCPL applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. TCPL 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 $) 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 TCPL 440 522 597 at December 31 2015 2014 (millions of Canadian $) 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

RATE-REGULATED BUSINESSES	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
RATE-REGULATED BUSINESSES	RATE-REGULATED BUSINESSES TCPL'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. TCPL'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, TCPL filed a compliance filing with the NEB in response to the RH-001-2014 Decision on TCPL'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 TCPL 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, TCPL 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 TCPL. 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 TCPL'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 TCPL's Mexican operations are regulated by the CRE and operate in accordance with CRE-approved tariffs. In 2014, TCPL 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 (millions of Canadian $) Regulatory Assets Deferred income taxes 1 848 1,001 n/a Operating and debt-service regulatory assets 2 47 4 1 Pensions and other post retirement benefits 3 210 236 n/a Foreign exchange on long-term debt 5 54 — 1-14 Other 4 110 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 debt 5 — 42 1-14 Operating and debt-service regulatory liabilities 2 32 21 1 ANR-related post-employment and retirement benefits other than pension 6 147 117 n/a Long term adjustment account 7 231 64 45 Pipeline abandonment costs 8 285 — n/a Bridging amortization account 9 456 — 15 Other 4 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. 2 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. 3 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from 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

GOODWILL	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL The Company has recorded the following Goodwill on its acquisitions in the U.S.: (millions of Canadian $) 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, TCPL’s Goodwill included US$573 million (2014 - US$573 million ) related to the Great Lakes natural gas transportation business. TCPL's share of this Goodwill (net of non-controlling interests) was US$ 386 million (2014 – US$ 243 million ). The increase in TCPL'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, TCPL’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 TCPL'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

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 $) Capital projects in development 1,814 1,286 PPAs 220 272 Fair value of derivative contracts (Note 23) 168 93 Loans and advances 1 159 167 Employee post-retirement benefits (Note 22) 18 14 Deferred income tax assets and charges (Note 15) 9 181 Other 797 628 3,185 2,641 1 TCPL 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 Cost Accumulated Amortization Net Book (millions of Canadian $) 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

NOTES PAYABLE	12 Months Ended
	Dec. 31, 2015
Short-term Debt [Abstract]
NOTES PAYABLE	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$800) 521 1.1 % 927 0.7 % 1,218 2,467 At December 31, 2015, Notes payable consists of commercial paper issued by TCPL, TransCanada American Investments Ltd. (TAIL), and TransCanada Power Marketing Ltd. (TCPM). In November 2015, the TAIL credit facility was increased to US$ 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 $3 billion TCPL Committed, syndicated, revolving, extendible TCPL credit facility December 2020 6 6 4 US$1 billion US$1 billion TCPL Committed, syndicated, revolving, extendible TCPL credit facility December 2016 — — — US$0.5 billion US$0.5 billion TCPL USA Committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL December 2016 3 2 1 US$1.5 billion US$1.5 billion TAIL/TCPM Committed, syndicated, revolving, extendible TAIL/TCPM credit facility, guaranteed by TCPL December 2016 2 1 — $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

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2015
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER at December 31 2015 2014 (millions of Canadian $) Trade payables 1,506 1,624 Fair value of derivative contracts (Note 23) 926 749 Dividends payable 370 345 Regulatory liabilities (Note 9) 44 30 Liabilities related to assets held for sale (Note 6) 39 — Other 129 143 3,014 2,891

OTHER LONG-TERM LIABILITIES

OTHER LONG-TERM LIABILITIES	12 Months Ended
	Dec. 31, 2015
Deferred Costs, Noncurrent [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES at December 31 2015 2014 (millions of Canadian $) 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

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Provision for Income Taxes year ended December 31 2015 2014 2013 (millions of Canadian $) Current Canada 45 104 27 Foreign 92 42 16 137 146 43 Deferred Canada 33 307 239 Foreign (135 ) 377 323 (102 ) 684 562 Income Tax Expense 35 830 605 Geographic Components of Income year ended December 31 2015 2014 2013 (millions of Canadian $) Canada (623 ) 1,146 1,201 Foreign (482 ) 1,678 1,298 (Loss)/Income Before Income Taxes (1,105 ) 2,824 2,499 Reconciliation of Income Tax Expense year ended December 31 2015 2014 2013 (millions of Canadian $) (Loss)/Income before income taxes (1,105 ) 2,824 2,499 Federal and provincial statutory tax rate 26.0 % 25.0 % 25.0 % Expected income tax (recovery)/expense (287 ) 706 625 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 charges 1 170 — — Other 1 8 13 Actual Income Tax Expense 35 830 605 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 $) Deferred Income Tax Assets Difference in accounting and tax bases of impaired assets 916 — Tax loss and credit carryforwards 1,325 1,344 Regulatory and other deferred amounts 231 236 Unrealized foreign exchange losses on long-term debt 589 140 Financial instruments 111 104 Other 132 146 3,304 1,970 Less: Valuation allowance 1 1,060 125 2,244 1,845 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 5,135 4,675 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 2014 1 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 11) 9 181 Deferred Income Tax Liabilities Deferred income tax liabilities 5,144 4,856 Net Deferred Income Tax Liabilities 5,135 4,675 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 $ 1,276 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 $ 164 million , net of refunds, were made in 2015 ( 2014 – payments, net of refunds, of $ 109 million ; 2013 – payments, net of refunds, of $ 206 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 $) Unrecognized tax benefit at beginning of year 13 19 45 Gross increases – tax positions in prior years 2 2 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 (1 ) (1 ) (3 ) Unrecognized Tax Benefit at End of Year 13 13 19 TCPL 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, TCPL 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. TCPL 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. TCPL'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 – nil for Interest expense and nil for penalties; 2013 – nil 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

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT 2015 2014 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Debentures Canadian 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 Canadian 2 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 Notes 3 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 $) 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 44 52 73 Capitalized interest (280 ) (259 ) (287 ) Amortization and other financial charges 1 31 55 (21 ) 1,398 1,235 1,046 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 $ 1,295 million in 2015 ( 2014 – $ 1,160 million ; 2013 – $ 1,047 million ) on Long-term debt, Junior subordinated notes and Notes payable, net of interest capitalized.

JUNIOR SUBORDINATED NOTES

JUNIOR SUBORDINATED NOTES	12 Months Ended
	Dec. 31, 2015
Junior Subordinated Notes [Abstract]
JUNIOR SUBORDINATED NOTES	JUNIOR SUBORDINATED NOTES 2015 2014 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED U.S. (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 TCPL'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

NON-CONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2015
Noncontrolling Interest [Abstract]
NON-CONTROLLING INTERESTS	NON-CONTROLLING INTERESTS The Company's Non-controlling interests included in the Consolidated balance sheet are as follows: at December 31 2015 2014 (millions of Canadian $) 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 $) Non-controlling interest in TC PipeLines, LP (13 ) 136 93 Non-controlling interest in PNGTS 19 15 12 6 151 105 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 , TCPL 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 .

COMMON SHARES

COMMON SHARES	12 Months Ended
	Dec. 31, 2015
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
COMMON SHARES	COMMON SHARES Number of Shares Amount (thousands) (millions of Canadian $) Outstanding at January 1, 2013 738,381 14,306 Issuance of common shares for cash 18,733 899 Outstanding at December 31, 2013 757,114 15,205 Issuance of common shares for cash 22,365 1,115 Outstanding at December 31, 2014 779,479 16,320 Outstanding at December 31, 2015 779,479 16,320 Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares without par value. Restrictions on Dividends Certain terms of the Company's debt instruments can limit the amount of dividends the Company can pay on preferred and common shares. At December 31, 2015 these terms limit the company from paying dividends in excess of $4.1 billion (2014 – $8.7 billion ; 2013 – $1.3 billion ). Under the agreements, TCPL can adjust this limit throughout the year if required, at is sole discretion, without incurring significant costs. Stock Option Plan Certain key employees, including officers, are granted stock options from TransCanada to purchase common shares at the market price on the grant date. Stock options vest equally over three years , beginning on the first anniversary of the grant date, and expire after seven years . 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 % Volatility 1 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) 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 .

PREFERRED SHARES

PREFERRED SHARES	12 Months Ended
	Dec. 31, 2015
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
PREFERRED SHARES	PREFERRED SHARES In March 2014, TCPL redeemed all of the 4 million outstanding Series Y preferred shares at a redemption price of $50 per share for a gross payment of $200 million . In October 2013, TCPL redeemed all of the 4 million outstanding Series U preferred shares at a redemption price of $50 per share for a gross payment of $200 million .

OTHER COMPREHENSIVE INCOME_(LOS

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 $) 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 Net of Tax Amount (millions of Canadian $) 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 $) 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 Total 1 AOCI balance at January 1, 2013 (707 ) (116 ) (287 ) (338 ) (1,448 ) Other comprehensive income before reclassifications 2 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 reclassifications 2 111 (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 reclassifications 2 135 (57 ) 51 33 162 Amounts reclassified from accumulated other comprehensive loss 3 — 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). 3 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months are estimated to be $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 1 Affected Line Item year ended December 31 2015 2014 2013 (millions of Canadian $) 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 BENEFI

EMPLOYEE POST-RETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE POST-RETIREMENT BENEFITS	EMPLOYEE POST-RETIREMENT BENEFITS The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining service life of employees, which is approximately nine years at December 31, 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 $) 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 Other (millions of Canadian $) 2015 2014 2015 2014 Change in Benefit Obligation 1 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 contributions 2 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 Other (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 Other (millions of Canadian $) 2015 2014 2015 2014 Projected benefit obligation 1 (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 $) 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 $) 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 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 (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 Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (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 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 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 (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 $) 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 $) 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 I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
Risk Management and Financial Instruments [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TCPL 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 TCPL'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. TCPL 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 TCPL 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. TCPL 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 TCPL'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 TCPL'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. TCPL 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) 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 1 Notional or Fair 1 Notional or (millions of Canadian $, unless otherwise noted) 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 TCPL 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. TCPL'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. TCPL 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, Due from affiliates, Intangible and other assets, Notes payable, Accounts payable and other, Due to affiliates, 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 Fair Carrying Fair (millions of Canadian $) Notes receivable 1 214 265 213 263 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. 3 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 Investments 1 Other Restricted Investments 2 LMCI Restricted Investments 1 Other Restricted Investments 2 (millions of Canadian $) 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 Hedges 1 Fair Value Hedges 1 Net Investment Hedges 1 Held for Trading 1 Total Fair Value of Derivative Instruments (millions of Canadian $) Other current assets (Note 5) Commodities 2 46 — — 326 372 Foreign exchange — — 65 2 67 Interest rate — 1 — 2 3 46 1 65 330 442 Intangible and other assets (Note 11) Commodities 2 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) Commodities 2 (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) Commodities 2 (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 Hedges 1 Fair Value Hedges 1 Net Investment Hedges 1 Held for Trading 1 Total Fair Value of Derivative Instruments (millions of Canadian $) Other current assets (Note 5) Commodities 2 39 — — 359 398 Foreign exchange — — 5 1 6 Interest rate — 2 — 3 5 39 2 5 363 409 Intangible and other assets (Note 11) Commodities 2 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) Commodities 2 (136 ) — — (422 ) (558 ) Foreign exchange — — (155 ) (32 ) (187 ) Interest rate (1 ) — — (3 ) (4 ) (137 ) — (155 ) (457 ) (749 ) Other long-term liabilities (Note 14) Commodities 2 (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 Purchases 1 70,331 133 — — Sales 1 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 Purchases 1 53,217 60 — — Sales 1 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 $) Derivative instruments held for trading 1 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) 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 Commodities 2 128 (111 ) Interest rate 3 16 16 144 (95 ) Losses on derivative instruments recognized in Net income (ineffective portion) Commodities 2 — (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. TCPL 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 Offset 1 Net Amounts (millions of Canadian $) 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 Offset 1 Net Amounts (millions of Canadian $) 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 1 Significant Other Observable Inputs Level II 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) 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 1 Significant Other Observable Inputs Level II 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) 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 year 1 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 CA

CHANGES IN OPERATING WORKING CAPITAL	12 Months Ended
	Dec. 31, 2015
CHANGES IN OPERATING WORKING CAPITAL
CHANGES IN OPERATING WORKING CAPITAL	CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2015 2014 2013 (millions of Canadian $) Increase in Accounts receivable (20 ) (205 ) (60 ) Increase in Inventories (3 ) (27 ) (30 ) (Increase)/decrease in Other current assets (268 ) (386 ) 40 (Decrease)/increase in Accounts payable and other (159 ) 393 (291 ) Increase in Accrued interest 91 36 7 Increase in Operating Working Capital (359 ) (189 ) (334 )

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS Natural Gas Pipelines TC PipeLines, LP On April 1, 2015 , TCPL 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, TCPL 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. TCPL 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, TCPL'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, TCPL 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, TCPL 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, TCPL 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 oper ating 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, TCPL applied equity accounting to its 48.5 per cent ownership interest in Bruce Power. Prior to the acquisition, TCPL 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, TCPL completed the acquisition of four Ontario solar facilities for $241 million in 2014. In 2013, TCPL 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, TCPL 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

COMMITMENTS, CONTINGENCIES AND GUARANTEES	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, CONTINGENCIES AND GUARANTEES	COMMITMENTS, CONTINGENCIES AND GUARANTEES Commitments Operating Leases Future annual payments under the Company's operating leases for various premises, services and equipment as well as fixed payments on Alberta PPAs, net of sublease receipts, are approximately as follows: year ended December 31 Minimum Amounts Net (millions of Canadian $) 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 ). TCPL'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. TCPL'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 TCPL 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 , TCPL 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 TCPL 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. TCPL 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 29, will not have a material impact on the Company's consolidated financial position or results of operations. Guarantees TCPL 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 TCPL 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 Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Bruce Power Ranging to 2018 2 88 2 634 6 Other jointly owned entities Ranging to 2040 139 24 104 14 227 26 738 20 1 TCPL's share of the potential estimated current or contingent exposure. 2 Except for one guarantee with no termination date.

CORPORATE RESTRUCTURING COSTS

CORPORATE RESTRUCTURING COSTS	12 Months Ended
	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.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS The following amounts are included in Due from affiliates: 2015 2014 (millions of Canadian $) Maturity Date Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate Discount Notes 1 2016 2,376 0.9 % 2,597 1.3 % Credit Facility 2 100 2.7 % 245 3.0 % 2,476 2,842 1 Issued to TransCanada. Interest on the discount notes is equivalent to current commercial paper rates . 2 Issued to TransCanada. This facility is repayable on demand and bears interest at the Royal Bank of Canada prime rate per annum . In 2015, Interest income included $29 million as a result of inter-corporate lending to TransCanada (2014 – $37 million ; 2013 – $38 million ). At December 31, 2015, Accounts receivable included $13 million due from TransCanada (December 31, 2014 – $59 million ). The following amounts are included in Due to affiliates: 2015 2014 (millions of Canadian $) Maturity Date Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate Credit Facility 1 2016 311 3.5 % 866 3.8 % 311 866 1 TransCanada has an unsecured $3.5 billion credit facility with a subsidiary of TCPL. Interest on this facility is charged at Reuters prime rate plus 75 basis points. In 2015, Interest expense included $28 million of interest charges as a result of inter-corporate borrowing (2014 – $37 million ; 2013 - $62 million ). At December 31, 2015, Accounts payable and other included $12 million due to TransCanada (December 31, 2014 – $16 million ). At December 31, 2015, Accrued interest included nil of interest payable to TransCanada (December 31, 2014 – $1 million ). In 2015, the Company made interest payments of $29 million to TransCanada (2014 – $37 million ; 2013 – $62 million ).

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Portland Natural Gas Transmission System On January 1, 2016, TCPL 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, TCPL 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, TCPL 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)

ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The consolidated financial statements include the accounts of TCPL 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. TCPL 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. TCPL records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.
Use of Estimates and Judgments	Use of Estimates and Judgments In preparing these financial statements, TCPL 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	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 TCPL'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. TCPL'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	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	Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.
Inventories	Inventories Inventories primarily consist of 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 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 and Impairment of Long-Lived Assets	Impairment of Long-Lived Assets The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows or the estimated 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. 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.
Acquisitions and Goodwill	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 TCPL 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	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 TCPL 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 TCPL records the margin earned from the subleases as a component of Revenues.
Restricted Investments	Restricted Investments The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are classified as available for sale and are recorded at fair value on the Consolidated balance sheet. As a result of the NEB’s Land Matters Consultation Initiative (LMCI), TCPL 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	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	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	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 TCPL are not attributed a value for accounting purposes. When required, TCPL accrues emission liabilities on the Consolidated balance sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues.
Stock Options and Other Compensation Programs	Stock Options and Other Compensation Programs The Company's Stock Option Plan permits options for the purchase of TransCanada 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. TCPL records the compensation expense associated with these stock options. The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.
Employee Post-Retirement Benefits	Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five -year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service life of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income/(loss) (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated other comprehensive income/(loss) (AOCI) over the average remaining service life of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.
Foreign Currency Transactions and Translation	Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the company or reporting subsidiary operates, 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	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	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	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.

SEGMENTED INFORMATION (Tables)

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 Liquids Energy Corporate Total (millions of Canadian $) 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 (1,398 ) Interest income and other 192 Loss before income taxes (1,105 ) Income tax expense (35 ) Net loss (1,140 ) Net income attributable to non-controlling interests (6 ) Net loss attributable to controlling interests (1,146 ) Preferred share dividends — Net loss attributable to common shares (1,146 ) 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 Liquids Energy Corporate Total (millions of Canadian $) 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 (1,235 ) Interest income and other 128 Income before income taxes 2,824 Income tax expense (830 ) Net income 1,994 Net income attributable to non-controlling interests (151 ) Net income attributable to controlling interests 1,843 Preferred share dividends (2 ) Net income attributable to common shares 1,841 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 Liquids Energy Corporate Total (millions of Canadian $) 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 (1,046 ) Interest income and other 72 Income before income taxes 2,499 Income tax expense (605 ) Net income 1,894 Net income attributable to non-controlling interests (105 ) Net income attributable to controlling interests 1,789 Preferred share dividends (20 ) Net income attributable to common shares 1,769 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 $) Total Assets Natural Gas Pipelines 31,072 27,103 Liquids Pipelines 16,046 16,116 Energy 15,558 14,197 Corporate 4,253 3,999 66,929 61,415
Revenue from External Customers by Geographic Areas	year ended December 31 2015 2014 2013 (millions of Canadian $) 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 $) 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)

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 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 221 170 1,353 1,018

ASSETS HELD FOR SALE (Tables)

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 $) 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 (

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 Cost Accumulated Depreciation Net (millions of Canadian $) 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 ANR 1 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 Other 2 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 Solar 5 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. 3 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 .
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)

EQUITY INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Investments	(millions of Canadian $) Ownership Income / (Loss) from Equity Investments Equity Investments year ended December 31 at December 31 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 1 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 , TCPL 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. 3 As a result of TCPL'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, TCPL has an ownership interest in Bruce Power of 48.5 per cent. Prior to the acquisition and merger, TCPL applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. TCPL 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.
Summary of Financial Information of Equity Investments	year ended December 31 2015 2014 2013 (millions of Canadian $) 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 TCPL 440 522 597 at December 31 2015 2014 (millions of Canadian $) 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 (Tabl

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 (millions of Canadian $) Regulatory Assets Deferred income taxes 1 848 1,001 n/a Operating and debt-service regulatory assets 2 47 4 1 Pensions and other post retirement benefits 3 210 236 n/a Foreign exchange on long-term debt 5 54 — 1-14 Other 4 110 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 debt 5 — 42 1-14 Operating and debt-service regulatory liabilities 2 32 21 1 ANR-related post-employment and retirement benefits other than pension 6 147 117 n/a Long term adjustment account 7 231 64 45 Pipeline abandonment costs 8 285 — n/a Bridging amortization account 9 456 — 15 Other 4 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. 2 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. 3 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from 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.

GOODWILL (Tables)

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 (Ta

INTANGIBLE AND OTHER ASSETS (Tables)	12 Months Ended
	Dec. 31, 2015
INTANGIBLES AND OTHER ASSETS
Schedule of Finite-Lived Intangible Assets	at December 31 2015 2014 (millions of Canadian $) Capital projects in development 1,814 1,286 PPAs 220 272 Fair value of derivative contracts (Note 23) 168 93 Loans and advances 1 159 167 Employee post-retirement benefits (Note 22) 18 14 Deferred income tax assets and charges (Note 15) 9 181 Other 797 628 3,185 2,641 1 TCPL 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 Cost Accumulated Amortization Net Book (millions of Canadian $) 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 $) Capital projects in development 1,814 1,286 PPAs 220 272 Fair value of derivative contracts (Note 23) 168 93 Loans and advances 1 159 167 Employee post-retirement benefits (Note 22) 18 14 Deferred income tax assets and charges (Note 15) 9 181 Other 797 628 3,185 2,641 1 TCPL 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 .

NOTES PAYABLE (Tables)

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 $3 billion TCPL Committed, syndicated, revolving, extendible TCPL credit facility December 2020 6 6 4 US$1 billion US$1 billion TCPL Committed, syndicated, revolving, extendible TCPL credit facility December 2016 — — — US$0.5 billion US$0.5 billion TCPL USA Committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL December 2016 3 2 1 US$1.5 billion US$1.5 billion TAIL/TCPM Committed, syndicated, revolving, extendible TAIL/TCPM credit facility, guaranteed by TCPL December 2016 2 1 — $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 (Tab

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 $) Trade payables 1,506 1,624 Fair value of derivative contracts (Note 23) 926 749 Dividends payable 370 345 Regulatory liabilities (Note 9) 44 30 Liabilities related to assets held for sale (Note 6) 39 — Other 129 143 3,014 2,891

OTHER LONG-TERM LIABILITIES (Ta

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 $) 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)

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 $) Current Canada 45 104 27 Foreign 92 42 16 137 146 43 Deferred Canada 33 307 239 Foreign (135 ) 377 323 (102 ) 684 562 Income Tax Expense 35 830 605
Schedule of Geographic Components of Income	year ended December 31 2015 2014 2013 (millions of Canadian $) Canada (623 ) 1,146 1,201 Foreign (482 ) 1,678 1,298 (Loss)/Income Before Income Taxes (1,105 ) 2,824 2,499
Reconciliation of Income Tax Expense	year ended December 31 2015 2014 2013 (millions of Canadian $) (Loss)/Income before income taxes (1,105 ) 2,824 2,499 Federal and provincial statutory tax rate 26.0 % 25.0 % 25.0 % Expected income tax (recovery)/expense (287 ) 706 625 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 charges 1 170 — — Other 1 8 13 Actual Income Tax Expense 35 830 605 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 $) Deferred Income Tax Assets Difference in accounting and tax bases of impaired assets 916 — Tax loss and credit carryforwards 1,325 1,344 Regulatory and other deferred amounts 231 236 Unrealized foreign exchange losses on long-term debt 589 140 Financial instruments 111 104 Other 132 146 3,304 1,970 Less: Valuation allowance 1 1,060 125 2,244 1,845 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 5,135 4,675 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 2014 1 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 11) 9 181 Deferred Income Tax Liabilities Deferred income tax liabilities 5,144 4,856 Net Deferred Income Tax Liabilities 5,135 4,675 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 $) Unrecognized tax benefit at beginning of year 13 19 45 Gross increases – tax positions in prior years 2 2 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 (1 ) (1 ) (3 ) Unrecognized Tax Benefit at End of Year 13 13 19

LONG-TERM DEBT (Tables)

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 Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) 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 Canadian 2 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 Notes 3 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 $) 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 44 52 73 Capitalized interest (280 ) (259 ) (287 ) Amortization and other financial charges 1 31 55 (21 ) 1,398 1,235 1,046 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.

JUNIOR SUBORDINATED NOTES (Tabl

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 Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED U.S. (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 (Tabl

NON-CONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2015
Noncontrolling Interest [Abstract]
Schedule of the Company's non-controlling interests included in the Consolidated Financial Statements	The Company's Non-controlling interests included in the Consolidated balance sheet are as follows: at December 31 2015 2014 (millions of Canadian $) 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 $) Non-controlling interest in TC PipeLines, LP (13 ) 136 93 Non-controlling interest in PNGTS 19 15 12 6 151 105

COMMON SHARES (Tables)

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 738,381 14,306 Issuance of common shares for cash 18,733 899 Outstanding at December 31, 2013 757,114 15,205 Issuance of common shares for cash 22,365 1,115 Outstanding at December 31, 2014 779,479 16,320 Outstanding at December 31, 2015 779,479 16,320
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 % Volatility 1 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) 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

OTHER COMPREHENSIVE INCOME_(L54

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 $) 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 Net of Tax Amount (millions of Canadian $) 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 $) 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 Total 1 AOCI balance at January 1, 2013 (707 ) (116 ) (287 ) (338 ) (1,448 ) Other comprehensive income before reclassifications 2 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 reclassifications 2 111 (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 reclassifications 2 135 (57 ) 51 33 162 Amounts reclassified from accumulated other comprehensive loss 3 — 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). 3 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months are estimated to be $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.
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 1 Affected Line Item year ended December 31 2015 2014 2013 (millions of Canadian $) 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 BENE55

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 $) 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 Other (millions of Canadian $) 2015 2014 2015 2014 Change in Benefit Obligation 1 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 contributions 2 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 for its DB Plans and Other Post-Retirement Benefits Plans	The amounts recognized in the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans are as follows: at December 31 Pension Other (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 Other (millions of Canadian $) 2015 2014 2015 2014 Projected benefit obligation 1 (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 $) 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 $) 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 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 (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	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 Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (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 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 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 (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 $) 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 $) 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 FINANCIAL56

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative financial instruments
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 Hedges 1 Fair Value Hedges 1 Net Investment Hedges 1 Held for Trading 1 Total Fair Value of Derivative Instruments (millions of Canadian $) Other current assets (Note 5) Commodities 2 46 — — 326 372 Foreign exchange — — 65 2 67 Interest rate — 1 — 2 3 46 1 65 330 442 Intangible and other assets (Note 11) Commodities 2 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) Commodities 2 (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) Commodities 2 (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 Hedges 1 Fair Value Hedges 1 Net Investment Hedges 1 Held for Trading 1 Total Fair Value of Derivative Instruments (millions of Canadian $) Other current assets (Note 5) Commodities 2 39 — — 359 398 Foreign exchange — — 5 1 6 Interest rate — 2 — 3 5 39 2 5 363 409 Intangible and other assets (Note 11) Commodities 2 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) Commodities 2 (136 ) — — (422 ) (558 ) Foreign exchange — — (155 ) (32 ) (187 ) Interest rate (1 ) — — (3 ) (4 ) (137 ) — (155 ) (457 ) (749 ) Other long-term liabilities (Note 14) Commodities 2 (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 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 Fair Carrying Fair (millions of Canadian $) Notes receivable 1 214 265 213 263 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. 3 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 Investments 1 Other Restricted Investments 2 LMCI Restricted Investments 1 Other Restricted Investments 2 (millions of Canadian $) 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 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 Purchases 1 70,331 133 — — Sales 1 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 Purchases 1 53,217 60 — — Sales 1 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 .
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 $) Derivative instruments held for trading 1 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) 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 Commodities 2 128 (111 ) Interest rate 3 16 16 144 (95 ) Losses on derivative instruments recognized in Net income (ineffective portion) Commodities 2 — (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 Offset 1 Net Amounts (millions of Canadian $) 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 Offset 1 Net Amounts (millions of Canadian $) 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 Offset 1 Net Amounts (millions of Canadian $) 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 Offset 1 Net Amounts (millions of Canadian $) 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 1 Significant Other Observable Inputs Level II 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) 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 1 Significant Other Observable Inputs Level II 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) 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 year 1 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) 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 1 Notional or Fair 1 Notional or (millions of Canadian $, unless otherwise noted) 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 57

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 $) Increase in Accounts receivable (20 ) (205 ) (60 ) Increase in Inventories (3 ) (27 ) (30 ) (Increase)/decrease in Other current assets (268 ) (386 ) 40 (Decrease)/increase in Accounts payable and other (159 ) 393 (291 ) Increase in Accrued interest 91 36 7 Increase in Operating Working Capital (359 ) (189 ) (334 )

COMMITMENTS, CONTINGENCIES AN58

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Annual Payments	Future annual payments under the Company's operating leases for various premises, services and equipment as well as fixed payments on Alberta PPAs, net of sublease receipts, are approximately as follows: year ended December 31 Minimum Amounts Net (millions of Canadian $) 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 Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Bruce Power Ranging to 2018 2 88 2 634 6 Other jointly owned entities Ranging to 2040 139 24 104 14 227 26 738 20 1 TCPL's share of the potential estimated current or contingent exposure. 2 Except for one guarantee with no termination date.

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Amounts included in due from/to affiliates	The following amounts are included in Due from affiliates: 2015 2014 (millions of Canadian $) Maturity Date Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate Discount Notes 1 2016 2,376 0.9 % 2,597 1.3 % Credit Facility 2 100 2.7 % 245 3.0 % 2,476 2,842 1 Issued to TransCanada. Interest on the discount notes is equivalent to current commercial paper rates . 2 Issued to TransCanada. This facility is repayable on demand and bears interest at the Royal Bank of Canada prime rate per annum . The following amounts are included in Due to affiliates: 2015 2014 (millions of Canadian $) Maturity Date Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate Credit Facility 1 2016 311 3.5 % 866 3.8 % 311 866 1 TransCanada has an unsecured $3.5 billion credit facility with a subsidiary of TCPL. Interest on this facility is charged at Reuters prime rate plus 75 basis points.

DESCRIPTION OF TCPL'S BUSINESS

DESCRIPTION OF TCPL'S BUSINESS (Details)	12 Months Ended
	Dec. 31, 2015plantsegmentBcffacilitymikm
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)

ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2015level
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)

SEGMENTED INFORMATION (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segmented information
Revenues	CAD 11,300	CAD 10,185	CAD 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)
Loss on assets held for sale	(125)	117
Segmented earnings/(losses)	101	3,931	3,473
Interest expense	(1,398)	(1,235)	(1,046)
Interest income and other	192	128	72
(Loss)/Income before Income Taxes	(1,105)	2,824	2,499
Income tax expense	(35)	(830)	(605)
Net (Loss)/Income	(1,140)	1,994	1,894
Net income attributable to non-controlling interests	(6)	(151)	(105)
Net (Loss)/Income Attributable to Controlling Interests	(1,146)	1,843	1,789
Preferred share dividends		(2)	(20)
Net (Loss)/Income Attributable to Common Shares	(1,146)	1,841	1,769
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	66,929	61,415
GEOGRAPHIC INFORMATION
Revenues	11,300	10,185	8,797
Plant, Property and Equipment	44,817	41,774
Canada
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	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	21,899	20,098
Mexico
Segmented information
Revenues	259	197	112
GEOGRAPHIC INFORMATION
Revenues	259	197	112
Plant, Property and Equipment	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	4,253	3,999
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	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)
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	23,317	20,204
Natural Gas Pipelines | Operating segments | Mexico
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	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	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)
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	CAD 3,176
Plant, Property and Equipment	CAD 7,129	CAD 6,490

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Assets [Abstract]
Cash held as collateral	CAD 585	CAD 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	170
Other current assets, total	CAD 1,353	CAD 1,018

ASSETS HELD FOR SALE (Details)

ASSETS HELD FOR SALE (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Assets Held for Sale
Accounts receivable	CAD 4	CAD 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
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
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal		CAD (125)	CAD 117
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	CAD (125)

PLANT, PROPERTY AND EQUIPMENT65

PLANT, PROPERTY AND EQUIPMENT (Details) CAD in Millions	Dec. 31, 2015CAD	Dec. 31, 2015CAD	Dec. 31, 2014CADfacility	Dec. 31, 2013CAD
Plant, property and equipment
Cost	CAD 67,116	CAD 67,116	CAD 61,638
Accumulated Depreciation	22,299	22,299	19,864
Net Book Value	44,817	44,817	41,774
Plant and equipment
Plant, property and equipment
Estimated fair value	463	463
Energy Turbine
Plant, property and equipment
Impairment charge, Pre-tax	59
Impairment charge, After-tax	43
Mexico
Plant, property and equipment
Net Book Value	3,631	3,631	2,485
Keystone XL
Plant, property and equipment
Estimated Fair Value	621	621
Impairment charge, Pre-tax	3,686
Impairment charge, After-tax	2,891
Estimated fair value	621	621
Keystone XL | Plant and equipment
Plant, property and equipment
Estimated Fair Value	463	463
Impairment charge, Pre-tax	1,460
Impairment charge, After-tax	CAD 1,391
Keystone XL | Plant and equipment | Market Approach Valuation Technique
Plant, property and equipment
Disposal period	2 years
Keystone XL | Terminals, including KHT
Plant, property and equipment
Estimated Fair Value	CAD 158	158
Impairment charge, Pre-tax	274
Impairment charge, After-tax	219
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
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	CAD 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	CAD 599
Operating segments | Energy | Solar
Plant, property and equipment
Number of facilities acquired | facility			4
Corporate
Plant, property and equipment
Cost	267	267	CAD 232
Accumulated Depreciation	82	82	80
Net Book Value	CAD 185	CAD 185	CAD 152

EQUITY INVESTMENTS - Schedule a

EQUITY INVESTMENTS - Schedule and Narrative (Details) CAD in Millions, $ in Millions	Dec. 03, 2015CAD	Dec. 31, 2015CAD	Dec. 31, 2014CAD	Dec. 31, 2013CAD	Dec. 31, 2015USD ($)	Dec. 30, 2015	Dec. 04, 2015	Dec. 02, 2015	Dec. 31, 2014USD ($)	May. 31, 2013	Apr. 30, 2013
Equity Investments
Income / (Loss) from Equity Investments		CAD 440	CAD 522	CAD 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		CAD 493	CAD 256	CAD 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		CAD 973	CAD 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	CAD 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		CAD 85	CAD 76	CAD 66
Equity Investments		CAD 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		CAD 51	43	41
Equity Investments		CAD 238	210
Natural Gas Pipelines | TQM
Equity Investments
Ownership interest		50.00%			50.00%
Income / (Loss) from Equity Investments		CAD 12	12	13
Equity Investments		72	73
Natural Gas Pipelines | Other
Equity Investments
Income / (Loss) from Equity Investments		31	32	25
Equity Investments		CAD 73	68
Liquids Pipelines | Grand Rapids
Equity Investments
Ownership interest		50.00%			50.00%
Equity Investments		CAD 542	240
Liquids Pipelines | Canaport Energy East Marine Terminal
Equity Investments
Ownership interest		50.00%			50.00%
Equity Investments		CAD 16
Energy | Other
Equity Investments
Income / (Loss) from Equity Investments		5	1	1
Equity Investments		CAD 67	61
Energy | Bruce Power
Equity Investments
Ownership interest		48.50%			48.50%
Income / (Loss) from Equity Investments		CAD 249	314	310
Equity Investments		CAD 4,200	3,995
Energy | ASTC Power Partnership
Equity Investments
Ownership interest		50.00%			50.00%
Income / (Loss) from Equity Investments		CAD (23)	8	110
Equity Investments		CAD 21	29
Energy | Portlands Energy
Equity Investments
Ownership interest		50.00%			50.00%
Income / (Loss) from Equity Investments		CAD 30	36	CAD 31
Equity Investments		CAD 321	CAD 335

EQUITY INVESTMENTS - Summarized

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income
Revenues	CAD 4,337	CAD 4,814	CAD 4,989
Operating and other expenses	(3,254)	(3,489)	(3,536)
Net income	1,046	1,264	1,390
Net income attributable to TCPL	440	522	CAD 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	CAD (3,116)	CAD (3,255)

RATE-REGULATED BUSINESSES - Nar

RATE-REGULATED BUSINESSES - Narrative (Details) - CAD CAD in Millions	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
Allowance for funds used during construction						CAD 295	CAD 136	CAD 37
Settlement, reduction in rates	3.00%
Scenario, forecast
Rate-regulated business
Settlement, reduction in rates									8.00%	10.00%
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
After-tax annual contribution to reduce revenue requirement		CAD 20
Fixed toll term		6 years
NGTL System | National Energy Board | 2015 Revenue Requirement Settlement
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%
NGTL System | National Energy Board | 2015 Revenue Requirement Settlement | Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity				10.10%
Deemed common equity				40.00%

RATE-REGULATED BUSINESSES - Ass

RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets
Total regulatory assets	CAD 1,269	CAD 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	CAD 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	CAD 32	21
Remaining Recovery/ Settlement Period (years)	1 year
Pensions and other post retirement benefits
Regulatory Liabilities
Total regulatory liabilities	CAD 147	117
Long term adjustment account
Regulatory Liabilities
Total regulatory liabilities	CAD 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	CAD 167	418	CAD (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	CAD 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	CAD 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	CAD 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	CAD (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	CAD 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	CAD 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	CAD 30	CAD 13	CAD 16

GOODWILL (Details)

GOODWILL (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014CAD	Dec. 31, 2015CAD	Dec. 31, 2015USD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	CAD 4,034		CAD 3,696	CAD 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	CAD 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				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 | TC PipeLines, LP
Goodwill recorded on Company's acquisitions in the U.S.
Impairment charge	CAD 199
Ownership interest (as a percentage)				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	CAD 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	CAD 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	CAD 1,145		CAD 960

INTANGIBLE AND OTHER ASSETS (De

INTANGIBLE AND OTHER ASSETS (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015CAD	Dec. 31, 2014CAD	Dec. 31, 2013CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
Capital projects in development	CAD 1,814	CAD 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)	9	181
Other	797	628
Intangible and other assets	3,185	2,641
Note receivable
Notes receivable	CAD 213	213		$ 154	$ 184
Interest rate on notes receivable	6.75%
Current portion of note receivable	CAD 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	CAD 52
Expected annual amortization expense
2,016	52
2,017	52
2,018	39
2,019	39
2,020	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	CAD 25	CAD 38

NOTES PAYABLE (Details)

NOTES PAYABLE (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015CAD	Dec. 31, 2014CAD	Dec. 31, 2013CAD	Dec. 31, 2015USD ($)	Nov. 01, 2015USD ($)	Oct. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Notes payable
Outstanding at December 31	CAD 1,218	CAD 2,467
Affiliates
Notes payable
Amount	3,500
Unused Capacity	600	400
Notes payable | U.S. dollars
Notes payable
Outstanding at December 31 | $				$ 376			$ 800
Revolving and demand credit facilities
Notes payable
Unused Capacity	8,900	6,700
TCPL | Revolving Credit Facility | Maturing December 2020
Notes payable
Amount	3,000
Unused Capacity	3,000
Cost to maintain	6	6	CAD 4
TCPL | Revolving Credit Facility | Maturing December 2016
Notes payable
Amount | $				1,000
Unused Capacity | $				1,000
TCPL | Revolving Credit Facility | U.S. dollars
Notes payable
Amount | $				$ 1,000
TCPL | Notes payable
Notes payable
Outstanding at December 31	CAD 697	CAD 1,540
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
Unused Capacity | $				$ 1,500
Cost to maintain	CAD 2	CAD 1
TAIL/TCPM | Notes payable
Notes payable
Outstanding at December 31	CAD 521	CAD 927
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	$ 1,000
TCPL USA | Revolving Credit Facility
Notes payable
Amount | $				$ 500
Unused Capacity | $				$ 500
Cost to maintain	CAD 3	CAD 2	CAD 1
TCPL USA | Revolving Credit Facility | U.S. dollars
Notes payable
Amount | $					$ 500	$ 1,000
TCPL/TCPL USA | Revolving Credit Facility
Notes payable
Amount	1,700
Unused Capacity	CAD 700

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Payables and Accruals [Abstract]
Trade payables	CAD 1,506	CAD 1,624
Fair value of derivative contracts (Note 23)	926	749
Dividends payable	370	345
Regulatory liabilities (Note 9)	44	30
Liabilities related to assets held for sale (Note 6)	39
Other	129	143
Accounts payable and other	CAD 3,014	CAD 2,891

OTHER LONG-TERM LIABILITIES (De

OTHER LONG-TERM LIABILITIES (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred Costs, Noncurrent [Abstract]
Fair value of derivative contracts (Note 23)	CAD 625	CAD 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	CAD 1,260	CAD 1,052

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current
Canada	CAD 45	CAD 104	CAD 27
Foreign	92	42	16
Total	137	146	43
Deferred
Canada	33	307	239
Foreign	(135)	377	323
Total	(102)	684	562
Total Income Tax Expense/(Recovery)	CAD 35	CAD 830	CAD 605

INCOME TAXES - Geographic Compo

INCOME TAXES - Geographic Components of Income (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Canada	CAD (623)	CAD 1,146	CAD 1,201
Foreign	(482)	1,678	1,298
(Loss)/Income before Income Taxes	CAD (1,105)	CAD 2,824	CAD 2,499

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Expense (Details) - CAD 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		CAD (1,105)	CAD 2,824	CAD 2,499
Federal and provincial statutory tax rate		26.01%	25.00%	25.00%
Expected income tax (recovery)/expense		CAD (287)	CAD 706	CAD 625
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	CAD 25	34		(25)
Asset impairment charges		170
Other		1	8	13
Total Income Tax Expense/(Recovery)		35	CAD 830	CAD 605
Asset impairment charges		CAD 311

INCOME TAXES - Deferred Assets

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Deferred Tax Assets, Net [Abstract]
Difference in accounting and tax bases of impaired assets	CAD 916
Tax loss and credit carryforwards	1,325	CAD 1,344
Regulatory and other deferred amounts	231	236
Unrealized foreign exchange losses on long-term debt	589	140
Financial instruments	111	104
Other	132	146
Deferred tax assets, gross	3,304	1,970
Less: Valuation allowance	1,060	125
Deferred Tax Assets, Net of Valuation Allowance	2,244	1,845
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	5,135	4,675
Increase (decrease) to the valuation allowance	935
Deferred Income Tax Assets
Intangible and other assets (Note 11)	9	181
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,144	4,856
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred noncurrent income tax liabilities, post accounting pronouncement	CAD 5,144	4,856
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 noncurrent income tax assets, post accounting pronouncement		427
Deferred current income tax liabilities, prior to accounting pronouncement		4
Deferred noncurrent income tax liabilities, post accounting pronouncement		CAD 4

INCOME TAXES - Reconciliation79

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD 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	CAD 13	CAD 19	CAD 45
Gross increases – tax positions in prior years	2	2	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	(1)	(1)	(3)
Unrecognized Tax Benefit at End of Year	CAD 13	CAD 13	CAD 19

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) CAD in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2013CAD	Dec. 31, 2015CAD	Dec. 31, 2014CAD	Dec. 31, 2013CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Net operating loss carryforwards
Deferred income tax liabilities on the unremitted earnings of foreign investments		CAD 308	CAD 236
Income tax payments, net of refunds		164	109	CAD 206
Favourable income tax adjustment	CAD 25	34		CAD (25)
Interest expense (reversal) reflected within net tax expense		(1)
Accrued interest expense		4	5
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards		1,276	1,131
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards | $					$ 1,617	$ 2,267
Alternative Minimum Tax [Member] | Canada federal and provincial
Net operating loss carryforwards
Minimum tax credits		CAD 57	CAD 50
Alternative Minimum Tax [Member] | U.S. federal
Net operating loss carryforwards
Minimum tax credits | $					$ 41	$ 26

LONG-TERM DEBT - Schedule of Ac

LONG-TERM DEBT - Schedule of Activity and Summary of Principal Repayments (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014CAD	Dec. 31, 2014USD ($)
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 31,584		CAD 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]
2,016	2,547
2,017	2,150
2,018	3,379
2,019	1,228
2,020	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 2015 and 2020
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 599		CAD 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	CAD 554	$ 400	CAD 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	CAD 5,192		CAD 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	CAD 20,340	$ 14,723	CAD 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	CAD 1,151		CAD 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	CAD 325		CAD 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	CAD 277	$ 200	CAD 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	CAD 504		CAD 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	CAD 45	$ 33	CAD 38	$ 33
Interest Rate	7.50%	7.50%	7.50%	7.50%
NOVA GAS TRANSMISSION LTD. | Debentures and Notes
Debt Instrument [Line Items]
Long-term debt issued with retraction provision	CAD 225
NOVA GAS TRANSMISSION LTD. | Debentures and Notes | 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	CAD 598	$ 432	CAD 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	CAD 450		CAD 377
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 346	$ 250	CAD 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	CAD 104	$ 75
Interest Rate	1.40%	1.40%
TC PIPELINES, LP
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 2,171		CAD 1,368
TC PIPELINES, LP | Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 967	$ 698	CAD 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	CAD 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	CAD 277	$ 200	CAD 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	CAD 692	$ 500	CAD 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	CAD 411	$ 297	CAD 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	CAD 22	$ 16	CAD 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	CAD 96	$ 69	CAD 105	$ 90
Interest Rate	6.10%	6.10%	6.10%	6.10%

LONG-TERM DEBT - Long-Term Debt

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

1 Months Ended

Nov. 30, 2015USD ($)

Oct. 31, 2015CAD

Sep. 30, 2015USD ($)

Jul. 31, 2015CAD

Jun. 30, 2015USD ($)

Mar. 31, 2015USD ($)

Jan. 31, 2015USD ($)

Feb. 28, 2014USD ($)

Oct. 31, 2013USD ($)

Jul. 31, 2013CAD

Jul. 31, 2013USD ($)

Jan. 31, 2013USD ($)

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 | CAD

CAD 400

Interest Rate

4.55%

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

Debt Instrument [Line Items]

Amount | CAD

CAD 750

Interest Rate

3.30%

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

Debt Instrument [Line Items]

Amount

$ 750

Interest Rate

4.60%

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

Debt Instrument [Line Items]

Amount

$ 500

Interest Rate

1.875%

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

Debt Instrument [Line Items]

Amount

$ 250

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 16, 2023

Debt Instrument [Line Items]

Amount

$ 625

Interest Rate

3.75%

TRANSCANADA PIPELINES LIMITED | 5.00% senior unsecured notes, due October 16, 2043

Debt Instrument [Line Items]

Amount

$ 625

Interest Rate

5.00%

TRANSCANADA PIPELINES LIMITED | 0.95% floating rate notes, maturing June 30, 2016

Debt Instrument [Line Items]

Amount

$ 500

TRANSCANADA PIPELINES LIMITED | 3.69% medium term notes, due July 19, 2023

Debt Instrument [Line Items]

Amount | CAD

CAD 450

Interest Rate

3.69%

3.69%

TRANSCANADA PIPELINES LIMITED | 4.55% medium term notes, due November 15, 2041

Debt Instrument [Line Items]

Amount | CAD

CAD 300

Interest Rate

4.55%

4.55%

TRANSCANADA PIPELINES LIMITED | 0.75 % senior notes, due January 15, 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 (Detai

LONG-TERM DEBT - Retired (Details) CAD in Millions, $ in Millions	1 Months Ended
	Aug. 31, 2015CAD	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Jan. 31, 2015USD ($)	Jun. 30, 2014CAD	Feb. 28, 2014CAD	Jan. 31, 2014CAD	Aug. 31, 2013USD ($)	Jun. 30, 2013USD ($)
TRANSCANADA PIPELINES LIMITED | Debentures, 11.90%
Debt Instrument [Line Items]
Amount | CAD	CAD 150
Interest Rate	11.90%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 3.40%
Debt Instrument [Line Items]
Amount		$ 500
Interest Rate		3.40%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 0.875%
Debt Instrument [Line Items]
Amount			$ 500
Interest Rate			0.875%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 4.875%
Debt Instrument [Line Items]
Amount				$ 300
Interest Rate				4.875%
TRANSCANADA PIPELINES LIMITED | Debentures, 11.10%
Debt Instrument [Line Items]
Amount | CAD					CAD 125
Interest Rate					11.10%
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes at 5.05%
Debt Instrument [Line Items]
Amount | CAD						CAD 300
Interest Rate						5.05%
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes, 5.65%
Debt Instrument [Line Items]
Amount | CAD							CAD 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 | CAD					CAD 53
Interest Rate					11.20%

LONG-TERM DEBT - Interest Expe

LONG-TERM DEBT - Interest Expense and Payments (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Interest Expense [Abstract]
Capitalized interest	CAD (280)	CAD (259)	CAD (287)
Amortization and other financial charges	31	55	(21)
Interest expense	1,398	1,235	1,046
Interest payments on long-term debt and junior subordinated notes, net of interest capitalized on construction projects	1,295	1,160	1,047
Short-term debt
Interest Expense [Abstract]
Interest on debt	44	52	73
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	CAD 116	CAD 70	CAD 65

JUNIOR SUBORDINATED NOTES (Deta

JUNIOR SUBORDINATED NOTES (Details) CAD in Millions	1 Months Ended	12 Months Ended	240 Months Ended	360 Months Ended
	May. 31, 2015USD ($)	Dec. 31, 2015CAD	Apr. 30, 2045	Apr. 30, 2075	Dec. 31, 2015USD ($)	Dec. 31, 2014CAD	Dec. 31, 2014USD ($)
Debt Instrument [Line Items]
Outstanding at December 31 | CAD		CAD 2,422				CAD 1,160
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding at December 31 | CAD		CAD 2,422				1,160
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding at December 31					$ 1,000,000,000
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 2075
Debt Instrument [Line Items]
Outstanding at December 31		CAD 1,038			$ 750,000,000
Effective Interest Rate		5.30%			5.30%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067
Debt Instrument [Line Items]
Outstanding at December 31		CAD 1,384			$ 1,000,000,000	CAD 1,160	$ 1,000,000,000
Effective Interest Rate		6.40%			6.40%	6.50%	6.50%
TRANSCANADA PIPELINES LIMITED | TransCanada Trust loan, due in May 2075 | Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate	5.875%
Debt	$ 750,000,000
Administrative charge	0.25%
Redemption price as a percentage of principal amount plus accrued and unpaid interest	100.00%
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 (Deta

NON-CONTROLLING INTERESTS (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014CAD	Dec. 31, 2013CAD	Jan. 01, 2015	Jan. 01, 2014	May. 01, 2013	Dec. 31, 2012CAD
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	CAD 1,717		CAD 1,583
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	6		151	CAD 105
Additional information
Impairment charge	3,745
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
Noncontrolling Interest
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	1,717		1,583	1,417				CAD 1,036
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	CAD (13)		136	93
Additional information
Percentage of non-controlling interests	72.00%				71.70%	71.10%	66.70%
Impairment charge	CAD 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	CAD 19		CAD 15	CAD 12
Additional information
Percentage of non-controlling interests	38.30%		38.30%	38.30%

COMMON SHARES - Narrative (Deta

COMMON SHARES - Narrative (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Additional disclosure
Maximum amount allowed for paying dividends	CAD 4,100	CAD 8,700	CAD 1,300
Award vesting period	3 years
Expiration period	7 years
Amount expensed for stock awards, with a corresponding increase in additional paid-in capital	CAD 11	CAD 9	CAD 6
Aggregate intrinsic value of total options exercisable	23
Total intrinsic value of options outstanding	CAD 23

COMMON SHARES - Reconciliation

COMMON SHARES - Reconciliation (Details) - CAD shares in Thousands, CAD in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Changes in common shares during the period
Outstanding at the end of the period (in shares)	779,000
Outstanding at the end of the period	CAD 16,320
Common Shares
Changes in common shares during the period
Outstanding at the beginning of the period (in shares)	757,114	738,381
Outstanding at the beginning of the period	CAD 15,205	CAD 14,306
Exercise of options (in shares)	22,365	18,733
Exercise of options	CAD 1,115	CAD 899
Outstanding at the end of the period (in shares)	779,479	757,114
Outstanding at the end of the period	CAD 16,320	CAD 15,205

COMMON SHARES - Weighted-Averag

COMMON SHARES - Weighted-Average Assumptions (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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%

COMMON SHARES - Additional Stoc

COMMON SHARES - Additional Stock Option Information (Details) - CAD shares in Millions, CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Additional Stock Option Information
Total intrinsic value of options exercised	CAD 37	CAD 68	CAD 25
Fair value of options that have vested	CAD 91	CAD 95	CAD 64
Total options vested (in shares)	2	1.7	1.3

PREFERRED SHARES (Details)

PREFERRED SHARES (Details) - CAD CAD / shares in Units, shares in Millions, CAD in Millions	1 Months Ended
	Mar. 31, 2014	Oct. 31, 2013
Series Y preferred shares
Preferred Shares [Line Items]
Stock redeemed during period (in shares)	4
Redemption price per share (in Canadian dollars per share)	CAD 50
Gross payment for preferred stock redemption	CAD 200
Series U preferred shares
Preferred Shares [Line Items]
Stock redeemed during period (in shares)		4
Redemption price per share (in Canadian dollars per share)		CAD 50
Gross payment for preferred stock redemption		CAD 200

OTHER COMPREHENSIVE INCOME_(L92

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components - (Details) - CAD 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	CAD 798	CAD 462	CAD 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)	CAD 602	CAD (171)	CAD 580

OTHER COMPREHENSIVE INCOME_(L93

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD 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	CAD (1,235)	CAD (934)	CAD (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
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	CAD (261)	CAD (308)	CAD (104)

OTHER COMPREHENSIVE INCOME_(L94

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD 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)	CAD 4,038	CAD 3,725	CAD 3,176
Interest expense	(1,398)	(1,235)	(1,046)
Income / (Loss) from Equity Investments	440	522	597
(Loss)/Income before income taxes	(1,105)	2,824	2,499
Income tax expense	(35)	(830)	(605)
Net (Loss)/Income Attributable to Controlling Interests	(1,146)	1,843	1,789
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		5
Net (Loss)/Income Attributable to Controlling Interests	CAD (14)	CAD (2)	CAD (15)

EMPLOYEE POST-RETIREMENT BENE95

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments and Changes (Details) - CAD 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	CAD 41	CAD 37	CAD 29
Cash Payments for Employee Post-Retirement Benefits [Abstract]
Savings and DC Plans	41	37	29
Total cash contributions	143	116	CAD 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)	CAD (380)	CAD (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	CAD 96	CAD 73	CAD 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	CAD 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	CAD (180)	CAD (177)

EMPLOYEE POST-RETIREMENT BENE96

EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD 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	CAD 2,636	CAD 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	CAD (2,780)	CAD (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	CAD 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	CAD (127)	CAD (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	CAD 2	CAD 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	CAD 4	CAD 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
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	0.00%	0.00%
Pension Benefit Plans | Alternatives | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	5.00%
Pension Benefit Plans | Alternatives | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	15.00%
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	CAD (198)	CAD (191)
Funded Status – Plan Deficit	(198)	(191)
Funded status based on accumulated benefit obligation
Plan assets at fair value	CAD 45	CAD 39	CAD 35

EMPLOYEE POST-RETIREMENT BENE97

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

EMPLOYEE POST-RETIREMENT BENE98

EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD 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	CAD 2,437
Plan assets at fair value – end of year	2,636	CAD 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	CAD 14	CAD 13

EMPLOYEE POST-RETIREMENT BENE99

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD 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	CAD 37
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits for 2013 (as a percent)	7.00%
Percentage level to which average annual rate was assumed to decrease	5.00%
Effects of a one per cent change in assumed health care cost trend rates
Effect on total of service and interest cost components, Increase	CAD 1
Effect on total of service and interest cost components, Decrease	(1)
Effect on post-retirement benefit obligation, Increase	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
2,016	129
2,017	133
2,018	138
2,019	142
2,020	146
2021 to 2025	CAD 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	CAD 108	CAD 85	CAD 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
Net Benefit Cost Recognized	128	100	122
Pre-tax amounts recognized in AOCI
Net loss	247	348	236
Prior service cost		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	CAD (128)
Pension Benefit Plans | Canada
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	214	CAD 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
2,016	8
2,017	9
2,018	9
2,019	9
2,020	10
2021 to 2025	CAD 51
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.40%	4.20%
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%
Net benefit cost
Service cost	CAD 3	CAD 2	CAD 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
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		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)
Funded status adjustment	(7)	9
Total pre-tax amounts recognized in OCI	CAD (12)	CAD 7	CAD (2)

RISK MANAGEMENT AND FINANCIA100

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

RISK MANAGEMENT AND FINANCIA101

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) - Designated as a net investment hedge CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015CAD	Dec. 31, 2014CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Derivative [Line Items]
Fair value	CAD (680)	CAD (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	CAD 50	CAD (28)
Forward foreign exchange contracts | US$ denominated
Derivative [Line Items]
Notional or Principal Amount | $			$ 1,800	$ 1,400

RISK MANAGEMENT AND FINANCIA102

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015CAD	Dec. 31, 2014CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Carrying and fair values of non-derivative financial instruments
Current and Long-Term Debt	CAD (31,584)	CAD (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 (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	CAD (36,055)	CAD (29,607)

RISK MANAGEMENT AND FINANCIA103

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015CADGWhBcf	Dec. 31, 2014CADGWhBcf	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	CAD 610	CAD 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	CAD (717)	CAD (657)
Commodities | Power | Not designated as hedging instrument | Purchases
Derivatives, Fair Value [Line Items]
Power (in GWh) | GWh	70,331	53,217
Commodities | Power | Not designated as hedging instrument | Sales
Derivatives, Fair Value [Line Items]
Power (in GWh) | GWh	54,382	39,429
Commodities | Natural Gas | Not designated as hedging instrument | Purchases
Derivatives, Fair Value [Line Items]
Natural Gas (in Bcf) | Bcf	133	60
Commodities | Natural Gas | Not designated as hedging instrument | Sales
Derivatives, Fair Value [Line Items]
Natural Gas (in Bcf) | Bcf	70	38
Commodities | Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	CAD (630)	CAD (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)	CAD (1)
Other long-term liabilities | Interest rate | Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	CAD (1)
Fixed income securities
Derivatives, Fair Value [Line Items]
Fixed income securities (maturing within 5 years)	5 years	5 years
Fixed income securities (maturing after 10 years)	10 years	10 years
LMCI Restricted Investments | Fixed income securities
Derivatives, Fair Value [Line Items]
Available-for-sale Securities, Debt Maturities, after Ten Years, Fair Value	CAD 261
Fixed income securities	261
Other Restricted Investments | Fixed income securities
Derivatives, Fair Value [Line Items]
Available-for-sale Securities, Debt Maturities, within Five Years, Fair Value	90	CAD 75
Fixed income securities	CAD 90	CAD 75

RISK MANAGEMENT AND FINANCIA104

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses)/Gains (Details) - CAD 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	CAD 11	CAD 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	CAD 8	CAD 4

RISK MANAGEMENT AND FINANCIA105

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - Cash Flow Hedges - CAD 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)	CAD (92)	CAD (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)	CAD 16	CAD 16

RISK MANAGEMENT AND FINANCIA106

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative - Asset
Gross derivative assets presented on the balance sheet	CAD 610	CAD 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
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	CAD (299)	CAD (270)

RISK MANAGEMENT AND FINANCIA107

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Hierarchy
Derivative Instrument Assets	CAD 610	CAD 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	CAD (4)	CAD (3)

RISK MANAGEMENT AND FINANCIA108

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 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	CAD 7	CAD 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
Total gains included in Net income	3	3
Sales	(2)
Settlements	(1)
Balance at end of year	9	CAD 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	CAD 2

RISK MANAGEMENT AND FINANCIA109

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

CHANGES IN OPERATING WORKING110

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CHANGES IN OPERATING WORKING CAPITAL
Increase in Accounts receivable	CAD (20)	CAD (205)	CAD (60)
Increase in Inventories	(3)	(27)	(30)
(Increase)/decrease in Other current assets	(268)	(386)	40
(Decrease)/increase in Accounts payable and other	(159)	393	(291)
Increase in Accrued interest	91	36	7
Increase in Operating Working Capital	CAD (359)	CAD (189)	CAD (334)

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Details) $ / shares in Units, CAD in Millions, $ in Millions

Dec. 03, 2015CAD

Apr. 01, 2015USD ($)

Nov. 26, 2014CAD

Oct. 01, 2014USD ($)

Apr. 15, 2014CAD

Jul. 31, 2013USD ($)

May. 31, 2013CADshares

May. 31, 2013USD ($)$ / sharesshares

Dec. 31, 2015CAD

Dec. 31, 2014CADfacility

Dec. 31, 2013CADfacility

Dec. 31, 2014facility

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)

CAD 196

Gain (loss) on disposal

CAD (125)

117

Contributions made to equity investments

493

256

CAD 163

Purchase price

236

CAD 241

CAD 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)

CAD 9

Gain (loss) on disposal

9

Proceeds from sale of assets, net of tax

CAD 8

Cancarb Limited | Disposal group, not discontinued operations

ACQUISITIONS AND DISPOSITIONS

Proceeds from sale of assets, net of transaction costs (Note 25)

CAD 190

Gain (loss) on disposition, gross

108

Gain (loss) on disposition, net of tax

CAD 99

Gas Transmission Northwest LLC | Natural Gas

ACQUISITIONS AND DISPOSITIONS

Ownership interest before transaction (as a percent)

45.00%

Ontario solar projects | Energy

ACQUISITIONS AND DISPOSITIONS

Number of facilities acquired | facility

4

4

8

Purchase price

CAD 457

CAD 241

CAD 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

CAD 29

Pre-tax dilution gain recorded in additional paid-in capital as a result of decrease in ownership interest

CAD 47

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

ACQUISITIONS AND DISPOSITIONS

Ownership interest before transaction (as a percent)

30.00%

Total consideration | $

$ 457

Cash received | $

264

Assumption of debt by purchaser | $

98

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

ACQUISITIONS AND DISPOSITIONS

Receipt of new units | $

$ 95

Bison LLC | Natural Gas

ACQUISITIONS AND DISPOSITIONS

Ownership interest before transaction (as a percent)

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 A

ACQUISITIONS AND DISPOSITIONS

Ownership interest

48.90%

48.90%

Bruce B

ACQUISITIONS AND DISPOSITIONS

Ownership interest

46.50%

31.60%

31.60%

Additional ownership acquired

14.89%

Contributions made to equity investments

CAD 236

COMMITMENTS, CONTINGENCIES A112

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Operating Leases (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Minimum Lease Payments
2,016	CAD 354
2,017	355
2,018	270
2,019	248
2,020	185
2021 and thereafter	311
Minimum Lease Payments	1,723
Amounts Recoverable under Sub-leases
2,016	46
2,017	45
2,018	26
2,019	24
2,020	20
2021 and thereafter	1
Amounts Recoverable under Sub-leases	162
Net Payments
2,016	308
2,017	310
2,018	244
2,019	224
2,020	165
2021 and thereafter	310
Net Payments	1,561
Rent Expense
Net rental expense on operating leases	CAD 131	CAD 114	CAD 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 A113

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Power Purchase Arrangements (Details) CAD in Millions	12 Months Ended
	Dec. 31, 2015CADMW	Dec. 31, 2014CAD	Dec. 31, 2013CAD
Alberta PPAs
Commitments under operating leases
Share of payments under PPAs | CAD	CAD 348	CAD 391	CAD 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 A114

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Other Commitments and Contingencies (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014CAD	Dec. 31, 2013CAD
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites	CAD 32		CAD 31	CAD 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	CAD 600		CAD 200

COMMITMENTS, CONTINGENCIES A115

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) CAD in Millions	Dec. 31, 2015CADguarantee	Dec. 31, 2014CADguarantee
Guarantees
Number of guarantees without a termination date | guarantee	1	1
Contingent financial obligation
Guarantees
Potential Exposure	CAD 227	CAD 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	CAD 24	CAD 14

CORPORATE RESTRUCTURING COSTS (

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

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Due from affiliates	CAD 2,476	CAD 2,842
Due to affiliates	311	866
Interest expense	28	37	CAD 62
Transcanada
Related Party Transaction [Line Items]
Interest income, inter-corporate borrowing	29	37	38
Accounts receivable	13	59
Accounts payable and other	12	16
Interest payable		1
Affiliates
Related Party Transaction [Line Items]
Amount	3,500
Discount Notes
Related Party Transaction [Line Items]
Due from affiliates	CAD 2,376	CAD 2,597
Effective interest rate (as a percent)	0.90%	1.30%
Credit Facility
Related Party Transaction [Line Items]
Due from affiliates	CAD 100	CAD 245
Effective interest rate (as a percent)	2.70%	3.00%
Credit Facility
Related Party Transaction [Line Items]
Due to affiliates	CAD 311	CAD 866
Effective interest rate (as a percent)	3.50%	3.80%
Credit Facility | Affiliates | Prime rate
Related Party Transaction [Line Items]
Spread on variable rate (as a percent)	0.75%
Interest
Related Party Transaction [Line Items]
Interest paid	CAD 29	CAD 37	CAD 62

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details)	Feb. 01, 2016USD ($)MW	Jan. 06, 2016USD ($)	Jan. 01, 2016USD ($)	Dec. 31, 2015USD ($)	Jan. 27, 2016USD ($)
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 (as a percent)			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 (as a percent)					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 (as a percent)					3.125%
Subsequent event | Pending litigation | Claim under Chapter 11 of North American Free Trade Agreement
Subsequent Event [Line Items]
Costs and damages sought		$ 15,000,000,000

Uncategorized Items - trp-20151

Label	Element	Value
Common Stock [Member]
Common Stock, Shares, Outstanding	us-gaap_CommonStockSharesOutstanding	779,479,000
Common Stock, Value, Issued	us-gaap_CommonStockValue	CAD 16,320,000,000