TC Energy (TRP) 40-F13 Feb 152014 FY Annual report (Canada)Financial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	12 Months Ended
Document and Entity Information	Dec. 31, 2014
Document and Entity Information
Entity Registrant Name	TRANSCANADA CORP
Entity Central Index Key	1232384
Document Type	40-F
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding	708,563,076
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

CONSOLIDATED_STATEMENT_OF_INCO

CONSOLIDATED STATEMENT OF INCOME (CAD)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues
Natural Gas Pipelines	4,913	4,497	4,264
Liquids Pipelines	1,547	1,124	1,039
Energy	3,725	3,176	2,704
Total Revenues	10,185	8,797	8,007
Income from Equity Investments (Note 8)	522	597	257
Operating and Other Expenses
Plant operating costs and other	2,973	2,674	2,577
Commodity purchases resold	1,836	1,317	1,049
Property taxes	473	445	434
Depreciation and amortization	1,611	1,485	1,375
Total Operating and Other Expenses	6,893	5,921	5,435
Gain on Sale of Assets (Note 25)	117	0	0
Financial Charges/(Income)
Interest expense (Note 15)	1,198	985	976
Interest income and other	-91	-34	-85
Total Financial Charges/(Income)	1,107	951	891
Income before Income Taxes	2,824	2,522	1,938
Income Tax Expense (Note 16)
Current	145	43	181
Deferred	686	568	285
Total Income Tax Expense/(Recovery)	831	611	466
Net Income	1,993	1,911	1,472
Net Income Attributable to Non-Controlling Interests (Note 18)	153	125	118
Net Income Attributable to Controlling Interests	1,840	1,786	1,354
Preferred Share Dividends (Note 20)	97	74	55
Net Income Attributable to Common Shares	1,743	1,712	1,299
Net Income per Common Share (Note 19)
Basic and Diluted (in dollars per share)	2.46	2.42	1.84
Dividends Declared per Common Share (in dollars per share)	1.92	1.84	1.76
Weighted Average Number of Common Shares
Basic (in shares)	708	707	705
Diluted (in shares)	710	708	706

CONSOLIDATED_STATEMENT_OF_COMP

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net Income	1,993	1,911	1,472
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains and losses on net investments in foreign operations	517	383	-129
Change in fair value of net investment hedges	-276	-239	44
Change in fair value of cash flow hedges	-69	71	48
Reclassification to Net Income of gains and losses on cash flow hedges	-55	41	138
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	-102	67	-73
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	18	23	22
Other Comprehensive Income/(Loss) on equity investments	-204	234	-70
Other Comprehensive Income/(Loss) (Note 21)	-171	580	-20
Comprehensive Income	1,822	2,491	1,452
Comprehensive Income Attributable to Non-Controlling Interests	283	191	97
Comprehensive Income Attributable to Controlling Interests	1,539	2,300	1,355
Preferred Share Dividends	97	74	55
Comprehensive Income Attributable to Common Shares	1,442	2,226	1,300

CONSOLIDATED_STATEMENT_OF_CASH

CONSOLIDATED STATEMENT OF CASH FLOWS (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Generated from Operations
Net Income	1,993	1,911	1,472
Depreciation and amortization	1,611	1,485	1,375
Deferred income taxes (Note 16)	686	568	285
Income from equity investments (Note 8)	-522	-597	-257
Distributed earnings received from equity investments (Note 8)	579	605	376
Employee post-retirement benefits expense, net of funding (Note 22)	37	50	9
Gain on sale of assets (Note 25)	-117	0	0
Equity AFUDC (Note 9)	-95	-19	-15
Unrealized losses/(gains) on financial instruments	74	-35	22
Other	22	32	17
(Increase)/decrease in operating working capital (Note 24)	-189	-326	287
Net cash provided by operations	4,079	3,674	3,571
Investing Activities
Capital expenditures (Note 4)	-3,550	-4,264	-2,595
Capital projects under development (Note 4)	-807	-488	-3
Equity investments	-256	-163	-652
Acquisitions, net of cash acquired (Note 25)	-241	-216	-214
Proceeds from sale of assets, net of transaction costs (Note 25)	196	0	0
Deferred amounts and other	514	11	208
Net cash used in investing activities	-4,144	-5,120	-3,256
Financing Activities
Dividends on common shares (Note 19)	-1,345	-1,285	-1,226
Dividends on preferred shares (Note 20)	-94	-71	-55
Distributions paid to non-controlling interests	-178	-166	-135
Notes payable issued/(repaid), net	544	-492	449
Long-term debt issued, net of issue costs	1,403	4,253	1,491
Repayment of long-term debt	-1,069	-1,286	-980
Common shares issued	47	72	53
Preferred shares issued, net of issue costs	440	585	0
Partnership units of subsidiary issued, net of issue costs	79	384	0
Preferred shares of subsidiary redeemed (Note 18)	-200	-200	0
Net cash (used in)/provided by financing activities	-373	1,794	-403
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	0	28	-15
(Decrease)/Increase in Cash and Cash Equivalents	-438	376	-103
Cash and Cash Equivalents, Beginning of year	927	551	654
Cash and Cash Equivalents, End of year	489	927	551

CONSOLIDATED_BALANCE_SHEET

CONSOLIDATED BALANCE SHEET (CAD)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current Assets
Cash and cash equivalents	489	927
Accounts receivable	1,313	1,122
Inventories	292	251
Other (Note 5)	1,446	847
Total Current Assets	3,540	3,147
Plant, Property and Equipment (Note 7)	41,774	37,606
Equity Investments (Note 8)	5,598	5,759
Regulatory Assets (Note 9)	1,297	1,735
Goodwill (Note 10)	4,034	3,696
Intangible and Other Assets (Note 11)	2,704	1,955
Total Assets	58,947	53,898
Current Liabilities
Notes payable (Note 12)	2,467	1,842
Accounts payable and other (Note 13)	2,896	2,155
Accrued interest	424	388
Current portion of long-term debt (Note 15)	1,797	973
Total Current Liabilities	7,584	5,358
Regulatory Liabilities (Note 9)	263	229
Other Long-Term Liabilities (Note 14)	1,052	656
Deferred Income Tax Liabilities (Note 16)	5,275	4,564
Long-Term Debt (Note 15)	22,960	21,892
Junior Subordinated Notes (Note 17)	1,160	1,063
Total Liabilities	38,294	33,762
EQUITY
Common shares, no par value; Issued and outstanding: December 31, 2014 - 709 million shares; December 31, 2013 - 707 million shares	12,202	12,149
Preferred shares (Note 20)	2,255	1,813
Additional paid-in capital	370	401
Retained earnings	5,478	5,096
Accumulated other comprehensive loss (Note 21)	-1,235	-934
Controlling interests	19,070	18,525
Non-controlling interests (Note 18)	1,583	1,611
Total Equity	20,653	20,136
Total Liabilities and Equity	58,947	53,898

CONSOLIDATED_BALANCE_SHEET_Par

CONSOLIDATED BALANCE SHEET (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Common shares issued (in shares)	709	707
Common shares outstanding (in shares)	709	707

CONSOLIDATED_STATEMENT_OF_EQUI

CONSOLIDATED STATEMENT OF EQUITY (CAD)	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
In Millions, unless otherwise specified	Total	Equity Attributable to Controlling Interests	Common Shares	Preferred Shares	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Equity Attributable to Non-Controlling Interests
Balance at beginning of year at Dec. 31, 2011			12,011	1,224	380	4,628	-1,449	1,465
Increase (decrease) in equity
Shares issued on exercise of stock options (Note 19)			58
Shares issued under public offering, net of issue costs				0
Issuance of stock options, net of exercises					-1
Dilution impact from TC PipeLines, LP units issued (Note 25)					0			0
Redemption of subsidiary's preferred shares					0			0
Impact of asset drop downs to TC Pipelines, LP (Note 25)					0
Net income attributable to controlling interests	1,354					1,354
Common share dividends						-1,240
Preferred share dividends						-55
Other comprehensive (loss)/income	-20						1
Equity Attributable to Non-Controlling Interests
TC PipeLines, LP								91
Preferred share dividends of TCPL								22
Portland	118							5
Other comprehensive income/(loss) attributable to non-controlling interests								-21
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					0			0
Decrease in TransCanada's ownership of TC PipeLines, LP								0
Distributions declared to non-controlling interests								-135
Redemption of subsidiary's preferred shares					0			0
Foreign exchange and other								-2
Balance at end of year at Dec. 31, 2012	18,336	16,911	12,069	1,224	379	4,687	-1,448	1,425
Increase (decrease) in equity
Shares issued on exercise of stock options (Note 19)			80
Shares issued under public offering, net of issue costs				589
Issuance of stock options, net of exercises					-2
Dilution impact from TC PipeLines, LP units issued (Note 25)					29			384
Redemption of subsidiary's preferred shares					-5			-195
Impact of asset drop downs to TC Pipelines, LP (Note 25)					0
Net income attributable to controlling interests	1,786					1,786
Common share dividends						-1,301
Preferred share dividends						-76
Other comprehensive (loss)/income	580						514
Equity Attributable to Non-Controlling Interests
TC PipeLines, LP								93
Preferred share dividends of TCPL								20
Portland	125							12
Other comprehensive income/(loss) attributable to non-controlling interests								66
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					29			384
Decrease in TransCanada's ownership of TC PipeLines, LP								-47
Distributions declared to non-controlling interests								-166
Redemption of subsidiary's preferred shares					-5			-195
Foreign exchange and other								19
Balance at end of year at Dec. 31, 2013	20,136	18,525	12,149	1,813	401	5,096	-934	1,611
Increase (decrease) in equity
Shares issued on exercise of stock options (Note 19)			53
Shares issued under public offering, net of issue costs				442
Issuance of stock options, net of exercises					3
Dilution impact from TC PipeLines, LP units issued (Note 25)					9			79
Redemption of subsidiary's preferred shares					-6			-194
Impact of asset drop downs to TC Pipelines, LP (Note 25)					-37
Net income attributable to controlling interests	1,840					1,840
Common share dividends						-1,360
Preferred share dividends						-98
Other comprehensive (loss)/income	-171						-301
Equity Attributable to Non-Controlling Interests
TC PipeLines, LP								136
Preferred share dividends of TCPL								2
Portland	153							15
Other comprehensive income/(loss) attributable to non-controlling interests								130
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					9			79
Decrease in TransCanada's ownership of TC PipeLines, LP								-14
Distributions declared to non-controlling interests								-182
Redemption of subsidiary's preferred shares					-6			-194
Foreign exchange and other								0
Balance at end of year at Dec. 31, 2014	20,653	19,070	12,202	2,255	370	5,478	-1,235	1,583

DESCRIPTION_OF_TRANSCANADAS_BU

DESCRIPTION OF TRANSCANADA'S BUSINESS	12 Months Ended
DESCRIPTION OF TRANSCANADA'S BUSINESS	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
DESCRIPTION OF TRANSCANADA'S BUSINESS	DESCRIPTION OF TRANSCANADA'S BUSINESS
	TransCanada Corporation (TransCanada or the Company) is a leading North American energy infrastructure company which operates in three business segments, Natural Gas Pipelines, Liquids Pipelines and Energy, each of which offers different products and services.
	Natural Gas Pipelines
	The Natural Gas Pipelines segment consists of the Company's investments in 68,000 km (42,000 miles) of regulated natural gas pipelines and 400 Bcf of regulated natural gas storage facilities. These assets are located in Canada, the United States and Mexico.
	Liquids Pipelines
	The Liquids Pipelines segment consists of 4,250 km (2,600 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, 2014
Accounting Policies [Abstract]
ACCOUNTING POLICIES	ACCOUNTING POLICIES
	The Company's consolidated financial statements have been prepared by management in accordance with United States generally accepted accounting principles (GAAP). Amounts are stated in Canadian dollars unless otherwise indicated.
	Basis of Presentation
	The consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.
	Use of Estimates and Judgments
	In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to:

	•	carrying values and depreciation rates of plant, property and equipment (Note 7);

	•	carrying value of equity investments (Note 8);

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

	•	carrying value of goodwill (Note 10);

	•	amortization rates and carrying values of intangible assets (Note 11);

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

	•	provisions for income taxes (Note 16);

	•	assumptions used to measure retirement and other postretirement 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) of Canada. In the U.S., natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the U.S. Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission of Mexico (CRE). The Company's Canadian, U.S. and Mexican natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls. Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TransCanada's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain of our liquids pipelines projects. RRA is not applicable to the Keystone Pipeline System and, as a result, 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 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. The 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 at the time of the regulatory decision.
	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 periodically 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 rate of return on common equity (ROE) assumptions. Adjustments to revenue are recorded when the NEB decision is received.
	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. 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 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.
	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 is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.
	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 the goodwill might be impaired. If TransCanada concludes that it is not more likely than not that 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 book value, which includes goodwill. If the fair value is less than book 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 PPA is a long-term contract for the purchase or sale of power on a predetermined basis. Substantially all PPAs under which TransCanada buys power are accounted for as operating leases. Initial payments for these PPAs were recognized in Intangible and Other Assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TransCanada records the margin earned from the subleases as a component of Revenues.
	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.
Recorded ARO relates 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 Balance Sheet at historical cost and expensed when they are utilized. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TransCanada are not attributed a value for accounting purposes. When required, TransCanada accrues emission liabilities on the Balance Sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues.
Stock Options and Other Compensation Programs
TransCanada's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period, with an offset to Additional Paid-In Capital. Upon exercise of stock options, amounts originally recorded against Additional Paid-In Capital are reclassified to Common Shares.
The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.
Employee Post-Retirement Benefits
The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.
The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service life of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Balance Sheet and recognizes changes in that funded status through Other Comprehensive Income (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated Other Comprehensive 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 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 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
ACCOUNTING CHANGES	Dec. 31, 2014
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES
	Changes in Accounting Policies for 2014
	Obligations resulting from joint and several liability arrangements
	In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This new guidance was effective January 1, 2014 and there was no material impact on the Company’s consolidated financial statements as a result of applying this new standard.
	Foreign currency matters - cumulative translation adjustment
	In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This new guidance was applied prospectively from January 1, 2014 and there was no material impact on the Company’s consolidated financial statements as a result of applying this new standard.
	Unrecognized tax benefit
	In July 2013, the FASB issued amended guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This new guidance was effective January 1, 2014. There was no material impact on the Company's consolidated financial statements as a result of applying this new standard.
	Future Accounting Changes
	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 is effective from January 1, 2015 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.
	Revenue from contracts with customers
	In May 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. This new guidance is effective from January 1, 2017 with 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. Early application is not permitted. The Company is currently evaluating the impact of the adoption of this ASU and has not yet determined the effect on its consolidated financial statements.

SEGMENTED_INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION


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

	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 Sale of Assets	9			—			108			—			117

	Segment earnings	2,187			843			1,051			(150	)		3,931

	Interest Expense													(1,198	)

	Interest Income and Other													91

	Income before Income Taxes													2,824

	Income Tax Expense													(831	)

	Net Income													1,993

	Net Income Attributable to Non-Controlling Interests													(153	)

	Net Income Attributable to Controlling Interests													1,840

	Preferred Share Dividends													(97	)

	Net Income Attributable to Common Shares													1,743


	Capital Spending
	Capital Expenditures	1,768			1,530			206			46			3,550

	Projects Under Development	368			439			—			—			807

		2,136			1,969			206			46			4,357


	at December 31, 2014
	(millions of Canadian dollars)
	Total Assets	27,103			16,116			14,197			1,531			58,947




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

	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	)
Segment earnings	1,881			603			1,113			(124	)		3,473

Interest Expense													(985	)

Interest Income and Other													34

Income before Income Taxes													2,522

Income Tax Expense													(611	)

Net Income													1,911

Net Income Attributable to Non-Controlling Interests													(125	)

Net Income Attributable to Controlling Interests													1,786

Preferred Share Dividends													(74	)

Net Income Attributable to Common Shares													1,712


Capital Spending
Capital Expenditures	1,776			2,286			152			50			4,264

Projects Under Development	245			243			—			—			488

	2,021			2,529			152			50			4,752


at December 31, 2013
(millions of Canadian dollars)
Total Assets	25,165			13,253			13,747			1,733			53,898





year ended December 31, 2012	Natural Gas			Liquids			Energy			Corporate			Total
(millions of Canadian dollars)	Pipelines			Pipelines

Revenues	4,264			1,039			2,704			—			8,007

Income from Equity Investments	157			—			100			—			257

Plant Operating Costs and Other	(1,365	)		(296	)		(819	)		(97	)		(2,577	)
Commodity Purchases Resold	—			—			(1,049	)		—			(1,049	)

Property Taxes	(315	)		(45	)		(74	)		—			(434	)

Depreciation and Amortization	(933	)		(145	)		(283	)		(14	)		(1,375	)
Segment earnings	1,808			553			579			(111	)		2,829

Interest Expense													(976	)

Interest Income and Other													85

Income before Income Taxes													1,938

Income Tax Expense													(466	)

Net Income													1,472

Net Income Attributable to Non-Controlling Interests													(118	)

Net Income Attributable to Controlling Interests													1,354

Preferred Share Dividends													(55	)

Net Income Attributable to Common Shares													1,299


Capital Spending
Capital Expenditures	1,389			1,145			24			37			2,595

Projects Under Development	—			3			—			—			3

	1,389			1,148			24			37			2,598


at December 31, 2012
(millions of Canadian dollars)
Total Assets	23,210			10,485			13,157			1,481			48,333

Geographic Information


year ended December 31	2014			2013			2012
(millions of Canadian dollars)

Revenues
Canada – domestic	4,021			4,659			3,527

Canada – export	1,314			997			1,121

United States	4,653			3,029			3,252

Mexico	197			112			107

	10,185			8,797			8,007



at December 31	2014			2013
(millions of Canadian dollars)

Plant, Property and Equipment
Canada	19,191			18,462

United States	20,098			17,570

Mexico	2,485			1,574

	41,774			37,606

OTHER_CURRENT_ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2014
Other Assets [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS


	at December 31	2014	2013

	(millions of Canadian dollars)

	Deferred income tax assets (Note 16)	427	119

	Cash held as collateral	423	42

	Fair value of derivative contracts (Note 23)	409	395

	Other	171	164

	Regulatory Assets (Note 9)	16	42

	Assets held for sale (Note 6)	—	85

		1,446	847

ASSETS_HELD_FOR_SALE

ASSETS HELD FOR SALE	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
ASSETS HELD FOR SALE	ASSETS HELD FOR SALE


	at December 31	2013
	(millions of Canadian dollars)

	Assets Held for Sale
	Cash and Cash Equivalents	1

	Accounts Receivable	12

	Inventories	11

	Plant, Property and Equipment	61

	Total Assets Held for Sale (included in Other Current Assets, Note 5)	85

	Liabilities Related to Assets Held for Sale
	Accounts Payable and Other	4

	Other Long-Term Liabilities	1

	Total Liabilities Related to Assets Held for Sale (included in Accounts Payable and Other, Note 13)	5

	The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and expects the sale to close within the next twelve months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying amount or its estimated fair value, reduced for selling costs, and depreciation expense is no longer recorded for that asset.
	At December 31, 2013, the Company classified Cancarb Limited and its related power generation facility as assets held for sale in the Energy segment. The assets were recorded at their carrying amount at December 31, 2013.
	On April 15, 2014, the Company sold these assets for aggregate gross proceeds of $190 million and recognized a gain of $108 million ($99 million after tax).

PLANT_PROPERTY_AND_EQUIPMENT

PLANT, PROPERTY AND EQUIPMENT	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
PLANT, PROPERTY AND EQUIPMENT	PLANT, PROPERTY AND EQUIPMENT


		2014						2013
	at December 31	Cost		Accumulated		Net		Cost		Accumulated		Net
	(millions of Canadian dollars)			Depreciation		Book Value				Depreciation		Book Value

	Natural Gas Pipelines
	Canadian Mainline
	Pipeline	9,045		5,712		3,333		8,970		5,457		3,513

	Compression	3,423		2,100		1,323		3,392		1,961		1,431

	Metering and other	458		180		278		409		174		235

		12,926		7,992		4,934		12,771		7,592		5,179

	Under construction	135		—		135		85		—		85

		13,061		7,992		5,069		12,856		7,592		5,264

	NGTL System
	Pipeline	8,185		3,619		4,566		7,813		3,410		4,403

	Compression	2,055		1,318		737		2,038		1,253		785

	Metering and other	1,032		446		586		947		418		529

		11,272		5,383		5,889		10,798		5,081		5,717

	Under construction	413		—		413		290		—		290

		11,685		5,383		6,302		11,088		5,081		6,007

	ANR
	Pipeline	1,087		85		1,002		922		59		863

	Compression	741		102		639		635		81		554

	Metering and other	617		110		507		535		91		444

		2,445		297		2,148		2,092		231		1,861

	Under construction	115		—		115		67		—		67

		2,560		297		2,263		2,159		231		1,928

	Other Natural Gas Pipelines
	GTN	1,842		588		1,254		1,685		488		1,197

	Great Lakes	1,807		939		868		1,650		833		817

	Foothills	1,671		1,180		491		1,649		1,120		529

	Mexico	1,518		130		1,388		641		90		551

	Other1	1,800		363		1,437		1,652		288		1,364

		8,638		3,200		5,438		7,277		2,819		4,458

	Under construction	1,132		—		1,132		1,047		—		1,047

		9,770		3,200		6,570		8,324		2,819		5,505

	37,076		16,872		20,204		34,427		15,723		18,704

Liquids Pipelines
Keystone
Pipeline	7,931		463		7,468		5,079		286		4,793

Pumping equipment	964		80		884		1,118		82		1,036

Tanks and other	2,282		144		2,138		962		71		891

	11,177		687		10,490		7,159		439		6,720

Under construction2	4,438		—		4,438		6,020		—		6,020

	15,615		687		14,928		13,179		439		12,740

Energy
Natural Gas – Ravenswood	2,140		476		1,664		1,966		377		1,589

Natural Gas – Other3,4	3,214		971		2,243		3,061		846		2,215

Hydro	736		156		580		673		126		547

Wind	970		190		780		946		155		791

Natural Gas Storage	653		99		554		677		92		585

Solar5	488		13		475		226		2		224

Other	64		19		45		57		30		27

	8,265		1,924		6,341		7,606		1,628		5,978

Under construction	149		—		149		54		—		54

	8,414		1,924		6,490		7,660		1,628		6,032

Corporate	232		80		152		191		61		130

	61,337		19,563		41,774		55,457		17,851		37,606





1	Includes Bison, Portland, North Baja, Tuscarora and Ventures LP.

2	Includes $3.2 billion for Keystone XL at December 31, 2014 (2013 – $2.6 billion). Keystone XL remains subject to regulatory approvals.

3	Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $695 million and $103 million, respectively, at December 31, 2014 (2013 – $640 million and $78 million, respectively). Revenues of $81 million were recognized in 2014 (2013 – $78 million; 2012 – $73 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 each of 2014 and 2013.

EQUITY_INVESTMENTS

EQUITY INVESTMENTS	12 Months Ended
	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	EQUITY INVESTMENTS


	(millions of Canadian dollars)	Ownership			Income/(Loss) from Equity						Equity
		Interest at			Investments						Investments
		December 31, 2014			year ended December 31						at December 31
					2014		2013		2012		2014	2013


	Natural Gas Pipelines
	Northern Border1,2				76		66		72		587	557

	Iroquois	44.5	%		43		41		41		210	188

	TQM	50	%		12		13		16		73	76

	Other	Various			32		25		28		68	62

	Energy
	Bruce A3	48.9	%		209		202		(149	)	3,944	3,988

	Bruce B3	31.6	%		105		108		163		51	377

	ASTC Power Partnership	50	%		8		110		40		29	41

	Portlands Energy	50	%		36		31		28		335	343

	Other4	Various			1		1		18		61	57

	Liquids Pipelines
	Grand Rapids	50	%		—		—		—		240	70

					522		597		257		5,598	5,759


	1	The results reflect a 50 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2014, TransCanada had an ownership interest in TC PipeLines, LP of 28.3 per cent (2013 – 28.9 and 2012 – 33.3 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.2 per cent (2013 – 14.5 and 2012 – 16.7 per cent).

	2	At December 31, 2014, 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 (2013 – US$118 million) due to the fair value assessment of assets at the time of acquisition.

	3	At December 31, 2014, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $776 million (2013 – $820 million) due to the fair value assessment of assets at the time of acquisition.

	4	In December 2012, TransCanada acquired the remaining 40 per cent interest in CrossAlta to bring the Company's ownership interest to 100 per cent. The results reflect the Company's 60 per cent share of equity income up to that date.


	Distributions received from equity investments for the year ended December 31, 2014 were $726 million (2013 – $725 million; 2012 – $436 million) of which $147 million (2013 – $120 million; 2012 – $60 million) were returns of capital and are included in Deferred Amounts and Other in the Consolidated Statement of Cash Flows. The undistributed earnings from equity investments as at December 31, 2014 were $551 million (2013 – $754 million; 2012 – $883 million).
	Summarized Financial Information of Equity Investments


	year ended December 31	2014			2013		2012
	(millions of Canadian dollars)

	Income
	Revenues	4,814			4,989		3,860

	Operating and Other Expenses	(3,489	)		(3,536	)	(3,090	)
	Net Income	1,264			1,390		717

	Net Income attributable to TransCanada	522			597		257




	at December 31	2014			2013
	(millions of Canadian dollars)

Balance Sheet
Current assets	1,412			1,500

Non current assets	12,260			12,158

Current liabilities	(1,067	)		(1,117	)
Non current liabilities	(3,255	)		(2,507	)

RATEREGULATED_BUSINESSES

RATE-REGULATED BUSINESSES	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
RATE-REGULATED BUSINESSES	RATE-REGULATED BUSINESSES
	TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain Canadian liquids pipelines currently under 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 (Canada). The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems.
	TransCanada's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return on capital as approved by the NEB. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent that actual costs and revenues are more or less than the forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur.
	Canadian Mainline
	On November 28, 2014, the NEB released its decision on TransCanada's 2015-2030 Tolls Application (the NEB 2014 Decision). The NEB 2014 Decision acknowledged that an off-ramp had been reached on the NEB 2013 Decision (discussed 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 a deemed common equity of 40 per cent, an incentive mechanism that has both upside and downside risk and a $20 million after-tax annual TransCanada contribution to reduce the revenue requirement. Toll stabilization is achieved through the continued use of deferral accounts, namely the Long Term Adjustment Account (LTAA) and the Bridging Amortization Account, to capture the surplus or the shortfall between the Company's revenues and cost of service for each year over the six-year fixed toll term of the NEB 2014 Decision. TransCanada is required to file a compliance filing with the NEB in first quarter 2015 and a toll review for the 2018 to 2020 period prior to December 31, 2017.
	In March 2013, TransCanada 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 a 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 our revenues and our cost of service for each year over the five-year term of the decision. In addition, the decision provided an opportunity to generate incentive earnings by increasing revenues and reducing costs. The NEB also identified certain circumstances that would require a new tolls application prior to the end of the five-year term. One of those circumstances occurred in 2013 when the TSA balance became positive. In December 2013, TransCanada filed the 2015-2030 Tolls Application with the NEB that addressed tolls moving forward including tolls for 2014.
	The Canadian Mainline's 2012 results reflect an ROE of 8.08 per cent on a deemed common equity of 40 per cent and excluded incentive earnings.
	NGTL System
	In November 2013, the NEB approved the NGTL System’s 2013-2014 Revenue Requirement Settlement Application. This settlement is structured similar to the previous multi-year settlement with fixed annual operating, maintenance and administration (OM&A) costs and a 10.1 per cent ROE on a deemed common equity of 40 per cent. Any variance between fixed OM&A costs in the settlement and actual costs accrue to TransCanada. The Settlement also establishes an increase in the composite depreciation rates to 3.05 per cent in 2013 and 3.12 per cent in 2014.
	The NGTL System's 2012 results reflected a 9.70 per cent ROE on a deemed common equity of 40 per cent and fixed certain annual OM&A costs. Any variances between actual costs and those agreed to in the settlement then in effect accrued to TransCanada. All other costs were treated on a flow-through basis.
	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 2012 through 2014 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 2012 through 2016. Any variances between actual costs and those included in the fixed component accrue to TQM.

	U.S. Regulated Operations
	TransCanada's U.S. natural gas pipelines are "natural gas companies" operating under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The Company's significant regulated U.S. natural gas pipelines are described below.
	ANR
	ANR's natural gas transportation and storage services are provided under tariffs regulated by the FERC. These tariffs include maximum and minimum rates for services and allow ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline Company rates were established pursuant to a settlement approved by the FERC that was effective for all periods presented, beginning in 1997. ANR Pipeline Company is not required to conduct a review of currently effective rates with the FERC at any time in the future, but is not prohibited from filing for new rates if necessary.
	ANR Storage Company rates were established pursuant to a settlement approved by the FERC in August 2012. ANR Storage Company is required to file a NGA Section 4 general rate case no later than July 1, 2016.
	TC Offshore LLC, another ANR-related regulated entity, began operating under FERC approved tariff rates on November 1, 2012. TC Offshore LLC is required to file a cost and revenue study to justify its existing approved cost-based rates after its first three years of operation.
	Great Lakes
	Great Lakes is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for its various services and permits Great Lakes to discount or negotiate rates on a non-discriminatory basis. Great Lakes operated under a July 2010 FERC approved rate settlement through October 2013. Effective November 1, 2013, Great Lakes operates under rates established pursuant to a settlement approved by the FERC in November 2013. The settlement provides for a moratorium between November 2013 and March 2015 during which Great Lakes and the settling parties are prohibited from taking certain actions under the NGA, including filing to adjust rates. Great Lakes is required to file for new rates to be effective no later than January 2018.
	Other U.S. Pipelines
	GTN and Bison are regulated by the FERC and operate in accordance with FERC-approved tariffs that establish maximum and minimum rates for various services. Both pipelines are 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. GTN is required to file for new rates to be effective no later than January 2016.
	Bison's rates were established pursuant to its initial certificate to construct and operate the pipeline that initiated service in January 2011. Bison filed a cost and revenue study as required by FERC to justify its existing approved cost-based rates after its first three years of operations. This study was filed by Bison on April 10, 2014 and accepted by FERC on May 20, 2014. At this time Bison is not required to conduct a review of currently effective rates with the FERC at any time in the future but is not prohibited from filing for new rates if necessary.
	Mexico Regulated Operations
	TransCanada's Mexican operations are regulated by the CRE and operate in accordance with CRE-approved tariffs. In 2014, TransCanada began using RRA for all natural gas pipelines in Mexico. The rates were established based on CRE approved negotiated contracts.
	Regulatory Assets and Liabilities


	at December 31	2014		2013		Remaining
						Recovery/
						Settlement
	(millions of Canadian dollars)					Period (years)

	Regulatory Assets
	Deferred income taxes1	1,001		1,149		n/a

	Operating and debt-service regulatory assets2	4		16		1

	Pensions and other post retirement benefits3	236		190		n/a

	Long Term Adjustment Account4	—		354		31

	Other5	72		68		n/a

		1,313		1,777

	Less: Current portion included in Other Current Assets (Note 5)	16		42

		1,297		1,735

	Regulatory Liabilities
	Foreign exchange on long-term debt6	42		84		15-Jan

	Operating and debt-service regulatory liabilities2	21		5		1

	ANR-related post-employment and retirement benefits other than pension7	117		104		n/a

	Long Term Adjustment Account4	64		—		44

Other5	49		43		n/a

	293		236

Less: Current portion included in Accounts Payable and Other (Note 13)	30		7

	263		229


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 2014 would have been $28 million higher (2013 – $76 million higher; 2012 - $50 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 2014 would have been $46 million lower (2013 – $171 million higher; 2012 - $61 million lower) had these amounts not been recorded as regulatory assets and liabilities.

4	The LTAA was established in compliance with the NEB 2013 Decision which is comprised of amounts that were deferred and recoverable in future years. The TSA, also established in the NEB 2013 Decision, includes the variances between revenue and costs. A positive balance in the TSA was realized in 2013 and 2014 and, as specified in the NEB 2013 Decision and the NEB 2014 Decision, the TSA, net of incentive earnings, was combined with the LTAA on December 31, 2013 and 2014.

5	Pre-tax operating results in 2014 would have been $2 million higher (2013 – $2 million higher; 2012 - $66 million higher) had these amounts not been recorded as regulatory assets and liabilities.

6	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.

7	Under the terms of the settlement 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 postretirement 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 postretirement benefits expense. ANR can but is not required to file for new rates. Therefore, the settlement/recovery period is not determinable. Pre-tax operating results in 2014 would have been $13 million higher (2013 – $16 million higher; 2012 - $8 million higher) had these amounts not been recorded as regulatory assets and liabilities.

Allowance for Funds Used During Construction
The total amount of AFUDC included in the Consolidated Statement of Income was $95 million in 2014, $19 million in 2013 and $15 million in 2012.

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2014
GOODWILL
GOODWILL	GOODWILL
	The Company has recorded the following Goodwill on its acquisitions in the U.S.:


	(millions of Canadian dollars)	Natural Gas	Energy	Total
		Pipelines

	Balance at January 1, 2013	2,635	823	3,458

	Foreign exchange rate changes	181	57	238

	Balance at December 31, 2013	2,816	880	3,696

	Foreign exchange rate changes	258	80	338

	Balance at December 31, 2014	3,074	960	4,034

INTANGIBLE_AND_OTHER_ASSETS

INTANGIBLE AND OTHER ASSETS	12 Months Ended
INTANGIBLE AND OTHER ASSETS	Dec. 31, 2014
INTANGIBLES AND OTHER ASSETS
INTANGIBLES AND OTHER ASSETS	INTANGIBLE AND OTHER ASSETS


	at December 31	2014	2013
	(millions of Canadian dollars)	2014	2013

	Capital projects under development	1,286	571
	Capital projects under development	1,286	571
	PPAs	272	324
	PPAs	272	324
	Deferred income tax assets and charges (Note 16)	180	225
	Deferred income tax assets and charges (Note 16)	180	225
	Loans and advances1	167	183
	Loans and advances1	167	183
	Fair value of derivative contracts (Note 23)	93	112
	Fair value of derivative contracts (Note 23)	93	112
	Employee post-retirement benefits (Note 22)	14	16
	Employee post-retirement benefits (Note 22)	14	16
	Other	692	524
	Other	692	524
		2,704	1,955
		2,704	1,955

	1	TransCanada held a note receivable from the seller of Ravenswood of $213 million (US$184 million) and $226 million (US$212 million) as at December 31, 2014 and at December 31, 2013, respectively which bears interest at 6.75 per cent and matures in 2040. The current portion included in Other Current Assets was $46 million (US$40 million) at December 31, 2014, and $43 million (US$40 million) at December 31, 2013.
	The following amounts related to PPAs are included in Intangible and Other Assets:


		2014			2013
	at December 31	Cost	Accumulated	Net Book	Cost	Accumulated	Net Book
	(millions of Canadian dollars)	Cost	Amortization	Value	Cost	Amortization	Value

	Sheerness	585	351	234	585	312	273
	Sheerness	585	351	234	585	312	273
	Sundance A	225	187	38	225	174	51
	Sundance A	225	187	38	225	174	51
		810	538	272	810	486	324
		810	538	272	810	486	324
	Amortization expense for these PPAs was $52 million for the year ended December 31, 2014 (2013 and 2012 – $52 million). The expected annual amortization expense for 2015 to 2017 is $52 million, and $39 million for 2018 and 2019.

NOTES_PAYABLE

NOTES PAYABLE

12 Months Ended

Dec. 31, 2014

Short-term Debt [Abstract]

NOTES PAYABLE

2014

2013

(millions of Canadian dollars)

Outstanding December 31

Weighted

Outstanding December 31

Weighted

Average

Interest Rate

per Annum

at December 31

Canadian dollars

1,540

1.2

751

1.2

U.S. dollars (2014 - US$800; 2013 – US$1,025)

927

0.7

1,091

0.3

2,467

1,842

Notes Payable consists of commercial paper issued by TransCanada PipeLines Limited (TCPL), TransCanada PipeLine USA Ltd. (TCPL USA), TransCanada American Investments Ltd. (TAIL), and TransCanada Keystone Pipeline, LP (TC Keystone) and drawings on credit facilities. The TC Keystone commercial paper program and facility were terminated in November 2013. The TAIL commercial paper program was initiated in November 2013, replacing the TCPL USA program which was terminated in April 2014.

Notes Payable also includes a US$170 million short-term loan, which was issued on October 1, 2014, by TC Pipelines LP.

At December 31, 2014, total committed revolving and demand credit facilities of $6.7 billion (2013 - $6.2 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, 2014

2014

2013

2012

Amount

Unused Capacity

Borrower

For

Matures

Cost to maintain

(millions of Canadian dollars)

$3 billion

TCPL

Committed, syndicated, revolving, extendible TCPL credit facility

Dec-19

US$1 billion

TCPL USA

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

Nov-15

US$1 billion

TAIL

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

Nov-15

—

$1.4 billion

$0.6 billion

TCPL/TCPL USA

Supports the issuance of letters of credit and provides additional liquidity

Demand

—

ACCOUNTS_PAYABLE_AND_OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2014
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER


	at December 31	2014	2013
	(millions of Canadian dollars)

	Trade payables	1,624	866

	Fair value of derivative contracts (Note 23)	749	357

	Dividends payable	359	338

	Deferred Income Tax Liabilities (Note 16)	4	26

	Regulatory Liabilities (Note 9)	30	7

	Liabilities related to assets held for sale (Note 6)	—	5

	Other	130	556

		2,896	2,155

OTHER_LONGTERM_LIABILITIES

OTHER LONG-TERM LIABILITIES	12 Months Ended
	Dec. 31, 2014
Deferred Costs, Noncurrent [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES


	at December 31	2014	2013
	(millions of Canadian dollars)

	Employee post-retirement benefit (Note 22)	444	244

	Fair value of derivative contracts (Note 23)	411	255

	Asset retirement obligations	98	83

	Guarantees (Note 26)	15	18

	Other	84	56

		1,052	656

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Unclassified [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT


				2014						2013
	Outstanding loan amounts	Maturity Dates		Outstanding December 31			Interest			Outstanding December 31			Interest
	(millions of Canadian dollars)						Rate1						Rate1

	TRANSCANADA PIPELINES LIMITED
	Debentures
	Canadian dollars	2015 to 2020		749			10.9	%		874			10.9	%

	U.S. dollars (2014 and 2013 US$400)	2021		464			9.9	%		425			9.9	%

	Medium-Term Notes
	Canadian dollars	2016 to 2041		4,048			5.7	%		4,799			5.7	%

	Senior Unsecured Notes
	U.S. dollars (2014 – US$13,526; 2013 – US$12,276)	2015 to 2043		15,655			5	%		13,027			5	%

				20,916						19,125

	NOVA GAS TRANSMISSION LTD.
	Debentures and Notes
	Canadian dollars2	2016 to 2024		325			11.5	%		378			11.5	%

	U.S. dollars (2014 and 2013 – US$200)	2023		232			7.9	%		213			7.9	%

	Medium-Term Notes
	Canadian dollars	2025 to 2030		504			7.4	%		504			7.4	%

	U.S. dollars (2014 and 2013 – US$33)	2026		38			7.5	%		34			7.5	%

				1,099						1,129

	ANR PIPELINE COMPANY
	Senior Unsecured Notes
	U.S. dollars (2014 and 2013 – US$432)	2021 to 2025		502			8.9	%		459			8.9	%

	GAS TRANSMISSION NORTHWEST CORPORATION
	Senior Unsecured Notes
	U.S. dollars (2014 and 2013 – US$325)	2015 to 2035		377			5.5	%		346			5.5	%

	TC PIPELINES, LP
	Unsecured Loan
	U.S. dollars (2014 – US$330; 2013 – US$380)	2017		383			1.4	%		404			1.4	%

	Unsecured Term Loan Facility
	U.S. dollars (2014 – US$500; 2013 – US$500)	2015 to 2018		580			1.4	%		532			1.4	%

	Senior Unsecured Notes
	U.S. dollars (2014 and 2013 – US$350)	2021		405			4.7	%		372			4.7	%

				1,368						1,308

	GREAT LAKES GAS TRANSMISSION
	LIMITED PARTNERSHIP
	Senior Unsecured Notes
	U.S. dollars (2014 – US$316; 2013 – US$335)	2018 to 2030		367			7.8	%		356			7.8	%

	TUSCARORA GAS TRANSMISSION COMPANY
	Senior Secured Notes
	U.S. dollars (2014 – US$20; 2013 – US$24)	2017		23			4	%		25			4	%

	PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes3
U.S. dollars (2014 – US$90; 2013 – US$110)	2018		105			6.1	%		117			6.1	%

			24,757						22,865

Less: Current Portion of Long-Term Debt			1,797						973

			22,960						21,892



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 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 2014 or 2013.

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

Principal Repayments
Principal repayments on the Long-Term Debt of the Company for the next five years are approximately as follows:


(millions of Canadian dollars)		2015		2016		2017		2018		2019

Principal repayments on Long-Term Debt		1,797		2,225		846		1,766		1,007

Long-Term Debt Issued
The Company issued Long-Term Debt over the last three years ended December 31 as follows:


(millions of Canadian dollars, unless otherwise noted)
Company		Issue date		Type		Maturity date		Amount			Interest Rate

TRANSCANADA PIPELINES LIMITED
		Feb-14		Senior Unsecured Notes		Mar-34		US 1,250			4.63	%

		Oct-13		Senior Unsecured Notes		Oct-23		US 625			3.75	%

		Oct-13		Senior Unsecured Notes		Oct-43		US 625			5	%

		Jul-13		Senior Unsecured Notes		Jun-16		US 500			Floating

		Jul-13		Medium-Term Notes		Jul-23		450			3.69	%

		Jul-13		Medium-Term Notes		Nov-41		300			4.55	%

		Jan-13		Senior Unsecured Notes		Jan-16		US 750			0.75	%

		Aug-12		Senior Unsecured Notes		Aug-22		US 1,000			2.5	%

		Mar-12		Senior Unsecured Notes		Mar-15		US 500			0.88	%

TC PIPELINES, LP
		Jul-13		Unsecured Term Loan Facility		Jul-18		US 500			Floating

Long-Term Debt Retired
The Company retired Long-Term Debt over the last three years ended December 31 as follows:


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

TRANSCANADA PIPELINES LIMITED
		Jun-14		Debentures		125			11.1	%

		Feb-14		Medium-Term Notes		300			5.05	%

		Jan-14		Medium-Term Notes		450			5.65	%

		Aug-13		Senior Unsecured Notes		US 500			5.05	%

		Jun-13		Senior Unsecured Notes		US 350			4	%

		May-12		Senior Unsecured Notes		US 200			8.63	%

NOVA GAS TRANSMISSION LTD.
		Jun-14		Debentures		53			11.2	%

		Dec-12		Debentures		US 175			8.5	%

Interest Expense


year ended December 31	2014			2013			2012
(millions of Canadian dollars)

Interest on Long-Term Debt	1,317			1,216			1,190

Interest on Junior Subordinated Notes (Note 17)	70			65			63

Interest on short-term debt	15			12			16

Capitalized interest	(259	)		(287	)		(300	)
Amortization and other financial charges1	55			(21	)		7

	1,198			985			976


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 $1,123 million in 2014 (2013 – $985 million; 2012 – $966 million) on Long-Term Debt and Junior Subordinated Notes, net of interest capitalized.

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES
	Provision for Income Taxes


	year ended December 31	2014			2013			2012
	(millions of Canadian dollars)

	Current
	Canada	103			27			167

	Foreign	42			16			14

		145			43			181

	Deferred
	Canada	309			245			69

	Foreign	377			323			216

		686			568			285

	Income Tax Expense	831			611			466

	Geographic Components of Income


	year ended December 31	2014			2013			2012
	(millions of Canadian dollars)

	Canada	1,146			1,224			842

	Foreign	1,678			1,298			1,096

	Income before Income Taxes	2,824			2,522			1,938

	Reconciliation of Income Tax Expense


	year ended December 31	2014			2013			2012
	(millions of Canadian dollars)

	Income before Income Taxes	2,824			2,522			1,938

	Federal and provincial statutory tax rate	25	%		25	%		25	%
	Expected income tax expense	706			631			485

	Income tax differential related to regulated operations	129			(13	)		41

	Higher/(lower) effective foreign tax rates	25			33			(12	)

	Income from equity investments and non-controlling interests	(38	)		(28	)		(27	)
	Tax legislation change	—			(25	)		—

	Other	9			13			(21	)

	Actual Income Tax Expense	831			611			466

	Deferred Income Tax Assets and Liabilities


	at December 31	2014			2013
	(millions of Canadian dollars)

	Deferred Income Tax Assets
Operating loss carryforwards	1,266			826

Deferred amounts	215			223

Unrealized foreign exchange losses on long-term debt	140			—

Financial Instruments	104			—

Other	248			128

	1,973			1,177

Less: Valuation allowance1	125			—

	1,848			1,177

Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	5,548			4,245

Equity investments	648			682

Taxes on future revenue requirement	253			291

Unrealized foreign exchange gains on long-term debt	—			35

Other	71			170

	6,520			5,423

Net Deferred Income Tax Liabilities	4,672			4,246



1	A valuation allowance was recorded in 2014 as the Company believes that it is more likely than not that the tax benefit related to the unrealized foreign exchange losses on the long term debt 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	2014			2013
(millions of Canadian dollars)

Deferred Income Tax Assets
Other Current Assets (Note 5)	427			119

Intangible and Other Assets (Note 11)	180			225

	607			344

Deferred Income Tax Liabilities
Accounts Payable and Other (Note 13)	4			26

Deferred Income Tax Liabilities	5,275			4,564

	5,279			4,590

Net Deferred Income Tax Liabilities	4,672			4,246

At December 31, 2014, the Company has recognized the benefit of unused non-capital loss carryforwards of $1,131 million (2013 – $1,026 million) for federal and provincial purposes in Canada, which expire from 2015 to 2034.
At December 31, 2014, the Company has recognized the benefit of unused net operating loss carryforwards of US$2,267 million (2013 – US$1,432 million) for federal purposes in the U.S., which expire from 2028 to 2034.
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, 2014 by approximately $236 million (2013 – $182 million) if there had been a provision for these taxes.
Income Tax Payments
Income tax payments of $109 million, net of refunds, were made in 2014 (2013 – payments, net of refunds, of $202 million; 2012 – refunds, net of payments made, of $190 million).
Reconciliation of Unrecognized Tax Benefit
Below is the reconciliation of the annual changes in the total unrecognized tax benefit:


at December 31	2014			2013			2012
(millions of Canadian dollars)

Unrecognized tax benefits at beginning of year	23			49			52

Gross increases – tax positions in prior years	3			3			2

Gross decreases – tax positions in prior years	(8	)		(28	)		(6	)
Gross increases – tax positions in current year	1			2			9

Lapses of statute of limitations	(1	)		(3	)		(8	)
Unrecognized tax benefits at end of year	18			23			49

TransCanada recognized a favourable income tax adjustment of approximately $25 million due to the enactment of certain Canadian Federal tax legislation in June 2013.
Subject to the results of audit examinations by taxing authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its financial statements.
TransCanada and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2009. Substantially all material U.S. federal income tax matters have been concluded for years through 2007 and U.S. state and local income tax matters through 2007.
TransCanada's practice is to recognize interest and penalties related to income tax uncertainties in Income Tax Expense. Income Tax Expense for the year ended December 31, 2014 reflects a $1 million reversal of Interest Expense and nil for penalties (2013 – $1 million increase of Interest Expense and nil for penalties; 2012 – $2 million reversal for Interest Expense and nil for penalties). At December 31, 2014, the Company had $5 million accrued for Interest Expense and nil accrued for penalties (December 31, 2013 – $6 million accrued for Interest Expense and nil accrued for penalties).

JUNIOR_SUBORDINATED_NOTES

JUNIOR SUBORDINATED NOTES

12 Months Ended

Dec. 31, 2014

Junior Subordinated Notes [Abstract]

JUNIOR SUBORDINATED NOTES

2014

2013

Outstanding loan amount

Maturity

Outstanding December 31

Effective

Outstanding December 31

Effective

(millions of Canadian dollars)

Date

Interest Rate

TRANSCANADA PIPELINES LIMITED

U.S. dollars (2014 and 2013 – US$1,000)

2067

1,160

6.5

1,063

6.5

Junior Subordinated Notes of US$1.0 billion mature in 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 plus 221 basis points. 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 subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and other obligations of TCPL. 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 of the Junior Subordinated Notes 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 of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption and an amount determined by a specified formula in accordance with the terms of the Junior Subordinated Notes.

NONCONTROLLING_INTERESTS

NON-CONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2014
Noncontrolling Interest [Abstract]
NON-CONTROLLING INTERESTS	NON-CONTROLLING INTERESTS
	The Company's Non-Controlling Interests included in the Consolidated Balance Sheet were as follows:


	at December 31	2014	2013
	(millions of Canadian dollars)

	Non-controlling interest in TC PipeLines, LP	1,479	1,323

	Non-controlling interest in Portland	104	94

	Preferred shares of TCPL	—	194

		1,583	1,611

	The Company's Non-Controlling Interests included in the Consolidated Statement of Income were as follows:


	year ended December 31	2014	2013	2012
	(millions of Canadian dollars)

	Non-controlling interest in TC PipeLines, LP	136	93	91

	Non-controlling interest in Portland	15	12	5

	Preferred shares of TCPL	2	20	22

		153	125	118

	During 2014, the non-controlling interest in TC PipeLines, LP increased from 71.1 per cent to 71.7 per cent due to the issuance of common units in TC PipeLines, LP to non-controlling interests. The non-controlling interest in TC PipeLines, LP from May 2013 to August 2014 was 71.1 per cent and from May 2011 to May 2013 was 66.7 per cent.
	The non-controlling interest in Portland as at December 31, 2014 represented the 38.3 per cent interest not owned by TransCanada (2013 and 2012 – 38.3 per cent).
	On October 15, 2013, TCPL redeemed all of the four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series U at a price of $50 per share plus $0.5907 representing accrued and unpaid dividends to the redemption date.
	On March 5, 2014, TCPL redeemed all of the four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series Y at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends to the redemption date.
	In 2014, TransCanada received fees of $3 million from TC PipeLines, LP (2013 and 2012 – $3 million) and $8 million from Portland (2013 and 2012 – $7 million) for services provided.

COMMON_SHARES

COMMON SHARES	12 Months Ended
COMMON SHARES	Dec. 31, 2014
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
COMMON SHARES	COMMON SHARES


		Number of			Amount
		Shares			Amount
		(thousands)			(millions of Canadian dollars)
		(thousands)			(millions of Canadian dollars)
	Outstanding at January 1, 2012	703,861			12,011
	Outstanding at January 1, 2012	703,861			12,011
	Exercise of options	1,600			58
	Exercise of options	1,600			58
	Outstanding at December 31, 2012	705,461			12,069
	Outstanding at December 31, 2012	705,461			12,069
	Exercise of options	1,980			80
	Exercise of options	1,980			80
	Outstanding at December 31, 2013	707,441			12,149
	Outstanding at December 31, 2013	707,441			12,149
	Exercise of options	1,221			53
	Exercise of options	1,221			53
	Outstanding at December 31, 2014	708,662			12,202
	Outstanding at December 31, 2014	708,662			12,202
	Common Shares Issued and Outstanding
	The Company is authorized to issue an unlimited number of common shares without par value.
	Basic and Diluted Net Income per Share
	Net income per share is calculated by dividing Net Income Attributable to Common Shares by the weighted average number of common shares outstanding. The higher weighted average number of shares for the diluted earnings per share calculation is due to options exercisable under TransCanada's Stock Option Plan.


	Weighted Average Common Shares Outstanding	2014			2013			2012
	(millions)	2014			2013			2012

	Basic	708			706.7			704.6
	Basic	708			706.7			704.6
	Diluted	709.6			707.7			705.7
	Diluted	709.6			707.7			705.7
	Stock Options


		Number of			Weighted				Options
		Options			Average				Exercisable
					Exercise
					Prices
		(thousands)							(thousands)
		(thousands)							(thousands)
	Outstanding at January 1, 2012	7,100				$35.44			5,165
	Outstanding at January 1, 2012	7,100				$35.44			5,165
	Granted	1,978				$42.03
	Granted	1,978				$42.03
	Exercised	(1,600	)			$33.13
	Exercised	(1,600	)			$33.13
	Forfeited	(44	)			$36.55
	Forfeited	(44	)			$36.55
	Outstanding at December 31, 2012	7,434				$37.69			4,588
	Outstanding at December 31, 2012	7,434				$37.69			4,588
	Granted	1,939				$47.09
	Granted	1,939				$47.09
	Exercised	(1,980	)			$36.12
	Exercised	(1,980	)			$36.12
	Outstanding at December 31, 2013	7,393				$40.57			3,954
	Outstanding at December 31, 2013	7,393				$40.57			3,954
	Granted	2,292				$49.03
	Granted	2,292				$49.03
	Exercised	(1,221	)			$43.00
	Exercised	(1,221	)			$43.00
	Outstanding at December 31, 2014	8,464				$43.17			4,902
	Outstanding at December 31, 2014	8,464				$43.17			4,902
Stock options outstanding at December 31, 2014 were as follows:


	Options Outstanding									Options Exercisable
Range of	Number of			Weighted				Weighted		Number of	Weighted		Weighted
Exercise Prices	Options			Average				Average		Options	Average		Average
				Exercise				Remaining			Exercise		Remaining
				Price				Contractual			Price		Contractual
								Life					Life
	(thousands)							(years)		(thousands)			(years)
	(thousands)							(years)		(thousands)			(years)
$30.10 to $36.26	1,410				$33.85			1.7		1,410		$33.85	1.7
$30.10 to $36.26	1,410				$33.85			1.7		1,410		$33.85	1.7
$36.90 to $41.65	1,101				$38.24			3.1		1,101		$38.24	3.1
$36.90 to $41.65	1,101				$38.24			3.1		1,101		$38.24	3.1
$41.95 to $45.29	1,819				$42.04			4.2		1,464		$42.02	4.2
$41.95 to $45.29	1,819				$42.04			4.2		1,464		$42.02	4.2
$47.09	1,842				$47.09			5.1		847		$47.09	5.1
$47.09	1,842				$47.09			5.1		847		$47.09	5.1
$49.03	2,292				$49.03			6.2		80		$49.03	6.2
$49.03	2,292				$49.03			6.2		80		$49.03	6.2
	8,464				$43.17			4.3		4,902		$39.81	3.3
	8,464				$43.17			4.3		4,902		$39.81	3.3
An additional 8.2 million common shares were reserved for future issuance under TransCanada's Stock Option Plan at December 31, 2014. The weighted average fair value of options granted to purchase common shares under the Company's Stock Option Plan was determined to be $5.54 for the year ended December 31, 2014 (2013 – $5.74; 2012 – $5.08). The contractual life of options granted is seven years. Options may be exercised at a price determined at the time the option is awarded and vest 33.3 per cent on the anniversary date in each of the three years following the award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation or termination of the option holder's employment.
The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions:


year ended December 31	2014			2013			2012
year ended December 31	2014			2013			2012

Expected life (years)	6			6			5.9
Expected life (years)	6			6			5.9
Interest rate	1.8	%		1.7	%		1.6	%
Volatility1	17	%		18	%		19	%
Dividend yield	3.8	%		3.7	%		4.2	%
Forfeiture rate	5	%		15	%		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 $9 million in 2014 (2013 - $6 million; 2012 – $5 million).
The following table summarizes additional stock option information:


year ended December 31	2014		2013		2012
(millions of Canadian dollars, unless noted otherwise)	2014		2013		2012

Total intrinsic value of options exercised	$68		$25		$18
Fair value of options that have vested	$113		$65		$49
Total options vested	2.0 million		1.3 million		1.0 million
As at December 31, 2014, the aggregate intrinsic value of the total options exercisable was $85 million and the total intrinsic value of options outstanding was $118 million.
Shareholder Rights Plan
TransCanada's Shareholder Rights Plan is designed to provide the Board with sufficient time to explore and develop alternatives for maximizing shareholder value in the event of a takeover offer for the Company and to encourage the fair treatment of shareholders in connection with any such offer. Attached to each common share is one right that, under certain circumstances, entitles certain holders to purchase two common shares of the Company for the then current market price of one.

PREFERRED_SHARES

PREFERRED SHARES	12 Months Ended
	Dec. 31, 2014
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
PREFERRED SHARES	PREFERRED SHARES


	at December 31	Number of	Current Yield		Annual Dividend Per Share1		Redemption Price Per Share2		Redemption and Conversion Option Date 2,3	Right to Convert Into 3,4	2014	2013
		Shares
		Authorized and
		Outstanding
	Cumulative First Preferred Shares5	(thousands)									(millions of	(millions of
											Canadian dollars)6	Canadian dollars)6

	Series 1	9,498	3.27	%		$0.82		$25.00	31-Dec-19	Series 2	233	539

	Series 2	12,502	Floating7		Floating			$25.50	31-Dec-19	Series 1	306	—

	Series 3	14,000	4	%		$1.00		$25.00	30-Jun-15	Series 4	343	343

	Series 5	14,000	4.4	%		$1.10		$25.00	30-Jan-16	Series 6	342	342

	Series 7	24,000	4	%		$1.00		$25.00	30-Apr-19	Series 8	589	589

	Series 9	18,000	4.25	%		$1.06		$25.00	30-Oct-19	Series 10	442	—

											2,255	1,813


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

	2	Series 2 preferred shares are redeemable by TransCanada at any time for $25.50 per share plus all accrued and unpaid dividends on such redemption date, unless redeemed on a designated redemption option date, or any fifth anniversary thereafter, in which case they are redeemable at $25.00 per share plus all accrued and unpaid dividends. For all other series of preferred shares, TransCanada may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the redemption option date and on every fifth anniversary thereafter.

	3	The holder will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter.

	4	With the exception of Series 1 preferred shares, if converted each series will be entitled to receive floating rate, cumulative, quarterly, preferential dividends per share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate + 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), and 2.35 per cent (Series 10). Holders of Series 1 preferred shares will receive fixed, cumulative, quarterly preferential dividends if converted.

	5	With the exception of Series 2 preferred shares, and where the redemption and/or conversion option is not exercised on a designated conversion date, the dividend rate on the fixed rate, cumulative, quarterly, preferential dividends will reset on the redemption and conversion option date and every fifth year thereafter to an annualized rate equal to the then five-year Government of Canada bond yield + 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), and 2.35 per cent (Series 9). Holders of Series 2 preferred shares will receive floating rate, cumulative, quarterly, preferential dividends.

	6	Net of underwriting commissions and deferred income taxes.

	7	Commencing December 31, 2014, the floating quarterly dividend rate for the Series 2 preferred shares is 2.82 per cent and will reset each quarter going forward.
	In January 2014, TransCanada completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at a price of $25.00 per share, resulting in gross proceeds of $450 million.
	At December 31, 2014, holders of 12,501,577 Series 1 preferred shares exercised their option to convert to Series 2 preferred shares and receive floating rate, cumulative, quarterly, preferential dividends at a rate equal to the then 90-day Government of Canada Treasury bill rate + 1.92 per cent until December 31, 2019. The floating quarterly dividend rate for the Series 2 preferred shares for the first quarterly floating rate period (being the period from December 31, 2014 to but excluding March 31, 2015) is 2.82 per cent per annum and will reset every quarter. The 9,498,423 Series 1 preferred shares will pay on a quarterly basis, for the five-year period beginning on December 31, 2014 a fixed quarterly dividend based on an annual fixed dividend rate of 3.27 per cent .

OTHER_COMPREHENSIVE_INCOME_AND

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
OTHER COMPREHENSIVE INCOME AND ACCUMMULATED OTHER COMPREHENSIVE LOSS	OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS
	Components of OCI including Non-Controlling Interests and the related tax effects are as follows:


	year ended December 31, 2014		Before tax amount			Income tax recovery/(expense)			Net of tax amount
	(millions of Canadian dollars)

	Foreign currency translation gains on net investments 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			Net of tax amount
	(millions of Canadian dollars)					recovery/(expense)

	Foreign currency translation gains on net investments 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



	year ended December 31, 2012		Before tax amount			Income tax recovery/(expense)			Net of tax amount
	(millions of Canadian dollars)
	Foreign currency translation losses on net investments in foreign operations		(97	)		(32	)		(129	)
	Change in fair value of net investment hedges		59			(15	)		44

	Change in fair value of cash flow hedges		61			(13	)		48

	Reclassification to Net Income of gains and losses on cash flow hedges		219			(81	)		138

	Unrealized actuarial gains and losses on pension and other post-retirement benefit plans		(104	)		31			(73	)

	Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans		22			—			22

	Other comprehensive loss on Equity Investments		(93	)		23			(70	)

	Other comprehensive income/(loss)		67			(87	)		(20	)

The changes in AOCI by component is as follows:


		Currency			Cash flow			Pension and OPEB plan adjustments			Equity Investments		Total1
		translation			hedges
		adjustments

AOCI Balance at January 1, 2012		(643	)		(302	)		(236	)		(268	)	(1,449	)
Other comprehensive (loss)/income before reclassifications2		(64	)		48			(73	)		(67	)	(156	)

Amounts reclassified from Accumulated Other Comprehensive Loss		—			138			22			(3	)	157

Net current period other comprehensive (loss)/income		(64	)		186			(51	)		(70	)	1

AOCI Balance at December 31, 2012		(707	)		(116	)		(287	)		(338	)	(1,448	)
Other comprehensive income before reclassifications2		78			71			67			219		435

Amounts reclassified from Accumulated Other Comprehensive Loss		—			41			23			15		79

Net current period other comprehensive income		78			112			90			234		514

AOCI Balance at December 31, 2013		(629	)		(4	)		(197	)		(104	)	(934	)
Other comprehensive income/(loss) before reclassifications2		111			(69	)		(102	)		(206	)	(266	)

Amounts reclassified from Accumulated Other Comprehensive Loss3		—			(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	)

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

2	OCI before reclassifications on currency translation adjustments is net of non-controlling interest gains of $130 million in 2014 (2013 - $66 million gains; 2012 - $21 million losses).

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 $95 million ($55 million, net of tax) at December 31, 2014. 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									Affected line item
		accumulated other									in the consolidated
		comprehensive loss1									statement of
year ended December 31		2014			2013			2012			income
(millions of Canadian dollars)

Cash flow hedges
Power and Natural Gas		111			(44	)		201			Revenue (Energy)

Interest		(16	)		(16	)		18			Interest Expense

		95			(60	)		219			Total before tax

		(40	)		19			(81	)		Income Tax Expense

		55			(41	)		138			Net of tax

Pension and OPEB plan adjustments

Amortization of actuarial loss and past service cost2		(25	)		(34	)		(22	)		2
		7			11			—			Income Tax Expense

		(18	)		(23	)		(22	)		Net of tax
Equity Investments
Equity Income		(2	)		(20	)		5			Income from Equity Investments

		—			5			(2	)		Income Tax Expense

		(2	)		(15	)		3			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 additional detail.

EMPLOYEE_POSTRETIREMENT_BENEFI

EMPLOYEE POST-RETIREMENT BENEFITS	12 Months Ended
EMPLOYEE POST-RETIREMENT BENEFITS	Dec. 31, 2014
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. Past service costs are amortized over the expected average remaining service life of employees, which is approximately nine years (2013 and 2012– 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. Past service costs are amortized over the expected average remaining life expectancy of former employees, which was approximately 12 years at December 31, 2014 (2013 – 11 years; 2012 – 12 years). In 2014, the Company expensed $37 million (2013 – $29 million; 2012 – $24 million) for the savings plan and DC Plans.
	Total cash payments for employee post-retirement benefits, consisting of cash contributed by the Company were as follows:


	year ended December 31	2014			2013			2012
	(millions of Canadian dollars)	2014			2013			2012

	DB Plans	73			79			83
	DB Plans	73			79			83
	Other post-retirement benefit plans	6			6			7
	Other post-retirement benefit plans	6			6			7
	Savings and DC Plans	37			29			24
	Savings and DC Plans	37			29			24
		116			114			114
		116			114			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, in 2014 the Company provided a $47 million letter of credit to the Canadian DB Plan (2013 – $59 million; 2012 – $48 million), resulting in a total of $181 million provided to the Canadian DB Plan under letters of credit at December 31, 2014.

	The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2014 and the next required valuation will be as at January 1, 2015.


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

	Change in Benefit Obligation1
	Benefit obligation – beginning of year	2,224			2,142			191			186
	Benefit obligation – beginning of year	2,224			2,142			191			186
	Service cost	85			84			2			2
	Service cost	85			84			2			2
	Interest cost	113			96			10			7
	Interest cost	113			96			10			7
	Employee contributions	4			4			—			—
	Employee contributions	4			4			—			—
	Benefits paid	(102	)		(83	)		(7	)		(7	)
	Actuarial loss/(gain)	302			(39	)		14			(2	)
	Actuarial loss/(gain)	302			(39	)		14			(2	)
	Foreign exchange rate changes	32			20			6			5
	Foreign exchange rate changes	32			20			6			5
	Benefit obligation – end of year	2,658			2,224			216			191
	Benefit obligation – end of year	2,658			2,224			216			191
	Change in Plan Assets
	Plan assets at fair value – beginning of year	2,152			1,825			35			32
	Plan assets at fair value – beginning of year	2,152			1,825			35			32
	Actual return on plan assets	246			313			2			2
	Actual return on plan assets	246			313			2			2
	Employer contributions2	73			79			6			6
	Employer contributions2	73			79			6			6
	Employee contributions	4			4			—			—
	Employee contributions	4			4			—			—
	Benefits paid	(102	)		(83	)		(7	)		(7	)
	Foreign exchange rate changes	25			14			3			2
	Foreign exchange rate changes	25			14			3			2
	Plan assets at fair value – end of year	2,398			2,152			39			35
	Plan assets at fair value – end of year	2,398			2,152			39			35
	Funded Status – Plan Deficit	(260	)		(72	)		(177	)		(156	)

	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 $181 million in letters of credit provided to the Canadian DB Plans for funding purposes (2013 - $134 million).
	The amounts recognized in the Company's Balance Sheet for its DB Plans and other post-retirement benefits plans are as follows:


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

Intangible and Other Assets (Note 11)	—			—			14			16
Intangible and Other Assets (Note 11)	—			—			14			16
Accounts Payable and Other (Note 13)	—			—			(7	)		—
Accounts Payable and Other (Note 13)	—			—			(7	)		—
Other Long-Term Liabilities (Note 14)	(260	)		(72	)		(184	)		(172	)
	(260	)		(72	)		(177	)		(156	)
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
	Benefit Plans						Post-Retirement
							Benefit Plans
(millions of Canadian dollars)	2014			2013			2014			2013
(millions of Canadian dollars)	2014			2013			2014			2013

Projected benefit obligation1	(2,658	)		(2,224	)		(191	)		(172	)
Plan assets at fair value	2,398			2,152			—			—
Plan assets at fair value	2,398			2,152			—			—
Funded Status – Deficit	(260	)		(72	)		(191	)		(172	)

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 accumulated benefit obligation for all DB pension plans at December 31, 2014 is $2,437 million (2013 – $2,039 million).
The funded status based on the accumulated benefit obligation for all DB Plans is as follows:


at December 31	2014			2013
(millions of Canadian dollars)	2014			2013

Accumulated benefit obligation	(2,437	)		(2,039	)
Plan assets at fair value	2,398			2,152
Plan assets at fair value	2,398			2,152
Funded Status – (Deficit)/Surplus	(39	)		113
Funded Status – (Deficit)/Surplus	(39	)		113
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	2014			2013
(millions of Canadian dollars)	2014			2013

Accumulated benefit obligation	(715	)		(569	)
Plan assets at fair value	597			537
Plan assets at fair value	597			537
Funded Status – Deficit	(118	)		(32	)
The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:
Asset Category


	Percentage of						Target Allocations1
	Plan Assets						Target Allocations1
at December 31	2014			2013			2014
at December 31	2014			2013			2014

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

1	Target allocations were revised in November 2013 and the investment mix is being adjusted over time accordingly.






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


at December 31							Percentage of
at December 31							Plan Assets
(millions of Canadian dollars)	2014			2013			2014			2013
(millions of Canadian dollars)	2014			2013			2014			2013

Debt securities	1			2			0.1	%		0.1	%
Debt securities	1			2			0.1	%		0.1	%
Equity securities	1			2			0.1	%		0.1	%
Equity securities	1			2			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. For further information on the fair value hierarchy, refer to Note 23.
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.


at December 31	Quoted Prices in						Significant Other Observable Inputs						Significant Unobservable Inputs				Total		Percentage of
	Active Markets						(Level II)						(Level III)						Total Portfolio
	(Level I)
(millions of Canadian dollars)	2014			2013			2014			2013			2014		2013		2014	2013	2014		2013
(millions of Canadian dollars)	2014			2013			2014			2013			2014		2013		2014	2013	2014		2013

Asset Category
Cash and Cash Equivalents	20			17			—			—			—		—		20	17	1	%	1	%
Cash and Cash Equivalents	20			17			—			—			—		—		20	17	1	%	1	%
Equity Securities:
Canadian	361			474			142			170			—		—		503	644	21	%	29	%
Canadian	361			474			142			170			—		—		503	644	21	%	29	%
U.S.	516			423			35			37			—		—		551	460	23	%	21	%
U.S.	516			423			35			37			—		—		551	460	23	%	21	%
International	218			36			147			330			—		—		365	366	15	%	17	%
International	218			36			147			330			—		—		365	366	15	%	17	%
Global	—			—			141			14			—		—		141	14	6	%	1	%
Global	—			—			141			14			—		—		141	14	6	%	1	%
Emerging	7			—			80			—			—		—		87	—	3	%	—
Emerging	7			—			80			—			—		—		87	—	3	%	—
Fixed Income Securities:
Canadian Bonds:
Federal	—			—			218			190			—		—		218	190	9	%	9	%
Federal	—			—			218			190			—		—		218	190	9	%	9	%
Provincial	—			—			180			154			—		—		180	154	7	%	7	%
Provincial	—			—			180			154			—		—		180	154	7	%	7	%
Municipal	—			—			7			6			—		—		7	6	—		—
Municipal	—			—			7			6			—		—		7	6	—		—
Corporate	—			—			76			77			—		—		76	77	3	%	3	%
Corporate	—			—			76			77			—		—		76	77	3	%	3	%
U.S. Bonds:
State	—			—			47			33			—		—		47	33	2	%	2	%
State	—			—			47			33			—		—		47	33	2	%	2	%
Corporate	—			—			59			48			—		—		59	48	2	%	2	%
Corporate	—			—			59			48			—		—		59	48	2	%	2	%
International:
Corporate	—			—			14			20			—		—		14	20	1	%	1	%
Corporate	—			—			14			20			—		—		14	20	1	%	1	%
Mortgage Backed	—			—			39			26			—		—		39	26	2	%	1	%
Mortgage Backed	—			—			39			26			—		—		39	26	2	%	1	%
Other Investments:
Private Equity Funds	—			—			—			—			13		18		13	18	—		1	%
Private Equity Funds	—			—			—			—			13		18		13	18	—		1	%
Funds held on deposit	117			114			—			—			—		—		117	114	5	%	5	%
Funds held on deposit	117			114			—			—			—		—		117	114	5	%	5	%
	1,239			1,064			1,185			1,105			13		18		2,437	2,187	100	%	100	%
	1,239			1,064			1,185			1,105			13		18		2,437	2,187	100	%	100	%
The following table presents the net change in the Level III fair value category:


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

Balance at December 31, 2012	19
Balance at December 31, 2012	19
Purchases and Sales	(4	)
Realized and unrealized gains	3
Realized and unrealized gains	3
Balance at December 31, 2013	18
Balance at December 31, 2013	18
Purchases and sales	(7	)
Realized and unrealized gains	2
Realized and unrealized gains	2
Balance at December 31, 2014	13
Balance at December 31, 2014	13
The Company's expected funding contributions in 2015 are approximately $70 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $36 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $35 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 dollars)	Pension			Other Post-
	Benefits			Retirement
				Benefits

2015	102			8
2015	102			8
2016	108			8
2016	108			8
2017	114			9
2017	114			9
2018	120			9
2018	120			9
2019	127			10
2019	127			10
2020 to 2024	728			51
2020 to 2024	728			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, 2014. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.
The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:


	Pension Benefit Plans						Other
							Post-Retirement
							Benefit Plans
at December 31	2014			2013			2014			2013
at December 31	2014			2013			2014			2013

Discount rate	4.15	%		4.95	%		4.2	%		5	%
Rate of compensation increase	3.15	%		3.15	%		—			—
Rate of compensation increase	3.15	%		3.15	%		—			—
The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:


	Pension									Other
	Benefit Plans									Post-Retirement
										Benefit Plans
year ended December 31	2014			2013			2012			2014			2013		2012
year ended December 31	2014			2013			2012			2014			2013		2012

Discount rate	4.95	%		4.35	%		5.05	%		5	%		4.35	%	5.1	%
Expected long-term rate of return on plan assets	6.9	%		6.7	%		6.7	%		4.6	%		4.6	%	6.4	%
Rate of compensation increase	3.15	%		3.15	%		3.15	%		—			—		—
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 7.5 per cent average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2020 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 dollars)	Increase			Decrease
(millions of Canadian dollars)	Increase			Decrease

Effect on total of service and interest cost components	1			(1	)
Effect on total of service and interest cost components	1			(1	)
Effect on post-retirement benefit obligation	14			(12	)
Effect on post-retirement benefit obligation	14			(12	)
The Company's net benefit cost is as follows:


at December 31	Pension									Other
	Benefit Plans									Post-Retirement
										Benefit Plans
(millions of Canadian dollars)	2014			2013			2012			2014			2013		2012
(millions of Canadian dollars)	2014			2013			2012			2014			2013		2012

Service cost	85			84			66			2			2		2
Service cost	85			84			66			2			2		2
Interest cost	113			96			94			10			7		8
Interest cost	113			96			94			10			7		8
Expected return on plan assets	(139	)		(120	)		(113	)		(2	)		(2	)	(2	)
Amortization of actuarial loss	21			30			18			2			2		1
Amortization of actuarial loss	21			30			18			2			2		1
Amortization of past service cost	2			2			2			—			—		1
Amortization of past service cost	2			2			2			—			—		1
Amortization of regulatory asset	18			30			19			1			1		1
Amortization of regulatory asset	18			30			19			1			1		1
Amortization of transitional obligation related to regulated business	—			—			—			2			2		2
	—			—			—			2			2		2
Net Benefit Cost Recognized	100			122			86			15			12		13
Net Benefit Cost Recognized	100			122			86			15			12		13
Pre-tax amounts recognized in AOCI were as follows:


	2014						2013						2012
at December 31	Pension			Other Post-			Pension			Other Post-			Pension		Other Post-
at December 31	Benefits			Retirement			Benefits			Retirement			Benefits		Retirement
(millions of Canadian dollars)				Benefits						Benefits					Benefits

Net loss	354			40			236			32			362		33
Net loss	354			40			236			32			362		33
Prior service cost	2			1			3			1			5		2
Prior service cost	2			1			3			1			5		2
	356			41			239			33			367		35
	356			41			239			33			367		35
The estimated net loss and prior service cost for the DB Plans that will be amortized from AOCI into net periodic benefit cost in 2015 are $27 million and $2 million, respectively. The estimated net loss and prior service cost for the other post-retirement plans that will be amortized from AOCI into net periodic benefit cost in 2015 is $2 million and nil, respectively.
Pre-tax amounts recognized in OCI were as follows:


	2014						2013						2012
at December 31	Pension			Other Post-			Pension			Other Post-			Pension		Other Post-
at December 31	Benefits			Retirement			Benefits			Retirement			Benefits		Retirement
(millions of Canadian dollars)				Benefits						Benefits					Benefits

Amortization of net loss from AOCI to OCI	(21	)		(2	)		(30	)		(2	)		(19	)	(1	)
Amortization of prior service costs from AOCI to OCI	(2	)		—			(2	)		—			(2	)	—
Amortization of prior service costs from AOCI to OCI	(2	)		—			(2	)		—			(2	)	—
Funded status adjustment	137			9			(96	)		—			99		5
Funded status adjustment	137			9			(96	)		—			99		5
	114			7			(128	)		(2	)		78		4
	114			7			(128	)		(2	)		78		4

RISK_MANAGEMENT_AND_FINANCIAL_

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2014
Risk Management and Financial Instruments [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
	Risk Management Overview
	TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and, ultimately, shareholder value.
	Risk management strategies, policies and limits are designed to ensure TransCanada's risks and related exposures are in line with the Company's business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits 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. Internal audit personnel assist the Audit Committee in its oversight role by performing regular and ad-hoc reviews of risk management controls and procedures, the results of which are reported to the Audit Committee.
	Market Risk
	The Company constructs and invests in energy infrastructure projects, purchases and sells energy commodities, issues short-term and long-term debt, including amounts in foreign currencies, and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings and the value of the financial instruments it holds.
	The Company uses derivatives as part of its overall risk management strategy to assist in managing the exposure to market risk that results from these activities. These derivative contracts may consist of the following:

	•	Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TransCanada enters into foreign exchange and commodity forwards and futures to manage the impact of volatility 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, particularly in relation to the prices of electricity and natural gas. A number of strategies are used to manage these exposures, including the following:

	•	Subject to its overall risk management strategy, the Company commits a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to manage operational and price risks in its asset portfolio.

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

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

	•	The Company enters into offsetting or back-to-back positions using derivative instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.
	Natural Gas Storage Commodity Price Risk
	TransCanada manages its exposure to seasonal natural gas price spreads in its non-regulated Natural Gas Storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TransCanada simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to natural gas price movements. Unrealized gains and losses on fair value adjustments recorded each period on these forward contracts are not necessarily representative of the amounts that will be realized on settlement.
	Foreign Exchange and Interest Rate Risk
	Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates.
	A portion of TransCanada’s earnings from its Natural Gas Pipelines, Liquids Pipelines and Energy segments is generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TransCanada’s net income. As the Company’s U.S. dollar-denominated operations continue to grow, exposure to changes in currency rates increases; some of this foreign exchange impact is partially offset by interest expense on U.S. dollar-denominated debt 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, in which case certain of the realized gains and losses on these derivatives would be deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers.
	TransCanada has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk.
	Net Investment in Foreign Operations
	The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forward contracts and foreign exchange options.
	U.S. Dollar-Denominated Debt Designated as a Net Investment Hedge


	at December 31		2014		2013
	(millions of Canadian dollars, unless noted otherwise)

	Carrying value		17,000 (US 14,700)		14,200 (US 13,400)
	Fair value		19,000 (US 16,400)		16,000 (US 15,000)
	Derivatives Designated as a Net Investment Hedge


		2014							2013
	at December 31	Fair			Notional or				Fair			Notional or
		Value1			Principal				Value1			Principal
	(millions of Canadian dollars, unless noted otherwise)				Amount							Amount

	U.S. dollar cross-currency interest rate swaps (maturing 2015 to 2019)2	(431	)		US	2,900			(201	)		US	3,800

	U.S. dollar foreign exchange forward contracts (maturing 2015)	(28	)		US	1,400			(11	)		US	850

		(459	)		US	4,300			(212	)		US	4,650


	1	Fair values approximate carrying values.

	2	In 2014, net realized gains of $21 million (2013 – gains of $29 million) related to the interest component of cross-currency swap settlements are included in Interest Expense.
	The balance sheet classification of the fair value of derivatives used to hedge the Company’s net investment in foreign operations is as follows:


	at December 31	2014			2013
	(millions of Canadian dollars)

Other Current Assets (Note 5)	5			5

Intangible and Other Assets (Note 11)	1			—

Accounts Payable and Other (Note 13)	(155	)		(50	)
Other Long-Term Liabilities (Note 14)	(310	)		(167	)
	(459	)		(212	)
Counterparty Credit Risk
Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the related contract or agreement with the Company.
The Company manages its exposure to this potential loss by using recognized credit management techniques, including:

•	Dealing with creditworthy counterparties - a significant amount of the Company’s credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties

•	Setting limits on the amount TransCanada can transact with any one counterparty - the Company monitors and manages the concentration of risk exposure with any one counterparty, and reduces the exposure when needed and when it is allowed under the terms of the contracts

•	Using contract netting arrangements and obtaining financial assurances such as guarantees, letters of credit or cash when deemed necessary.
There is no guarantee that these techniques will protect the Company from material losses.
TransCanada's maximum counterparty credit exposure with respect to financial instruments at December 31, 2014, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets and 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, 2014, 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 $258 million (US$222 million) and $240 million (US$225 million) at December 31, 2014 and 2013, respectively. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.
TransCanada has significant credit and performance exposures to financial institutions as they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.
Financial Instruments
All financial instruments, including both derivative and non-derivative instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company’s normal purchase and normal sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.
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 is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers. The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.
Certain non-derivative financial instruments included in Cash and Cash Equivalents, Accounts Receivable, Intangible and Other Assets, Notes Payable, Accounts Payable and Other, Accrued Interest and Other Long-Term Liabilities have carrying amounts that approximates their fair value due to the nature of the item or the short time to maturity and would be classified in Level II of the fair value hierarchy.
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 equal fair value, and would be classified in Level II of the fair value hierarchy:


	2014						2013
at December 31	Carrying			Fair			Carrying			Fair
(millions of Canadian dollars)	Amount			Value			Amount			Value

Notes receivable and other1	213			263			226			269

Available for sale assets2	62			62			47			47

Current and Long-Term Debt3,4 (Note 15)	(24,757	)		(28,713	)		(22,865	)		(26,134	)
Junior Subordinated Notes (Note 17)	(1,160	)		(1,157	)		(1,063	)		(1,093	)
	(25,642	)		(29,545	)		(23,655	)		(26,911	)

1	Notes receivable are included in Other Current Assets and Intangible and Other Assets on the Consolidated Balance Sheet.

2	Available for sale assets are included in Intangible and Other Assets on the Consolidated Balance Sheet.

3	Long-Term Debt is recorded at amortized cost, except for US$400 million (2013 - US$200 million) that is attributed to hedged risk and recorded at fair value.

4	Consolidated Net Income in 2014 included losses of $3 million (2013 - losses of $5 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$400 million of Long-Term Debt at December 31, 2014 (2013 - US$200 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.
Fair Value of Derivative Instruments
The fair value of foreign exchange and interest rate derivatives have been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives and available for sale assets 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. 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 is as follows:


at December 31	2014			2013
(millions of Canadian dollars)

Other Current Assets (Note 5)	409			395

Intangible and Other Assets (Note 11)	93			112

Accounts Payable and Other (Note 13)	(749	)		(357	)
Other Long-Term Liabilities (Note 14)	(411	)		(255	)
	(658	)		(105	)
2014 Derivative Instruments Summary
The following summary does not include hedges of the net investment in foreign operations.


(millions of Canadian dollars, unless noted otherwise)	Power				Natural				Foreign				Interest
					Gas				Exchange

Derivative Instruments Held for Trading1
Fair Values2
Assets		$362				$69				$1				$4

Liabilities		($391	)			($103	)			($32	)			($4	)

Notional Values
Volumes3
Purchases	42,097				60				—				—

Sales	35,452				38				—				—

U.S. dollars	—				—				US 1,374				US 100

Net unrealized losses in the year4		($5	)			($35	)			($20	)			$—

Net realized (losses)/gains in the year4		($39	)			$11				($28	)			$—

Maturity dates	2015-2019				2015-2020				2015				2015-2016


Derivative Instruments in Hedging Relationships5,6
Fair Values2
Assets		$57				$—				$—				$3

Liabilities		($163	)			$—				$—				($2	)

Notional Values
Volumes3
Purchases	11,120				—				—				—

Sales	3,977				—				—				—

U.S. dollars	—				—				—				US 550

Net realized gains in the year4		$130				$—				$—				$4

Maturity dates	2015-2019				—				—				2015-2018


1	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.

2	Fair value equals carrying value.

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

4	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in Energy 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. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Energy Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

5	All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $3 million and a notional amount of US$400 million. In 2014, net realized gains on fair value hedges were $7 million and were included in Interest Expense. In 2014, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

6	In 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.

2013 Derivative Instruments Summary
The following summary does not include hedges of the net investment in foreign operations.


(millions of Canadian dollars, unless noted otherwise)	Power				Natural				Foreign				Interest
					Gas				Exchange

Derivative Instruments Held for Trading1
Fair Values2
Assets		$265				$73				$—				$8

Liabilities		($280	)			($72	)			($12	)			($7	)

Notional Values
Volumes3
Purchases	29,301				88				—				—

Sales	28,534				60				—				—

Canadian dollars	—				—				—				400

U.S. dollars	—				—				US 1,015				US 100

Net unrealized gains/(losses) in the year4		$19				$17				($10	)			$—

Net realized losses in the year4		($49	)			($13	)			($9	)			$—

Maturity dates	2014-2017				2014-2016				2014				2014-2016


Derivative Instruments in Hedging Relationships5,6
Fair Values2
Assets		$150				$—				$—				$6

Liabilities		($22	)			$—				($1	)			($1	)

Notional Values
Volumes3
Purchases	9,758				—				—				—

Sales	6,906				—				—				—

U.S. dollars	—				—				US 16				US 350

Net realized (losses)/gains in the year4		($19	)			($2	)			$—				$5

Maturity dates	2014-2018				—				2014				2015-2018


1	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.

2	Fair value equals carrying value.

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

4	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in Energy 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. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Energy Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

5	All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $5 million and a notional amount of US$200 million. In 2013, net realized gains on fair value hedges were $6 million and were included in Interest Expense. In 2013, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

6	In 2013, 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 following table presents the components of OCI (Note 21) related to derivatives in cash flow hedging relationships:


year ended December 31	2014			2013
(millions of Canadian dollars, pre-tax)

Change in fair value of derivative instruments recognized in OCI (effective portion)1
Power	(126	)		117

Natural Gas	(2	)		(1	)
Foreign Exchange	10			5

	(118	)		121

Reclassification of (losses)/gains on derivative instruments from AOCI to Net Income (effective portion)1
Power2	(114	)		40

Natural Gas2	3			4

Interest3	16			16

	(95	)		60

(Losses)/gains on derivative instruments recognized in Net Income (ineffective portion)
Power	(13	)		8

	(13	)		8


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

2	Reported within Energy Revenues on the Consolidated Statement of Income.

3	Reported within Interest Expense on the Consolidated Statement of Income.

Offsetting of Derivative Instruments
The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however, similar contracts are entered into containing rights of offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:


at December 31, 2014	Gross derivative instruments presented on the balance sheet			Amounts available for offset1			Net amounts
(millions of Canadian dollars)

Derivative - Asset
Power	419			(330	)		89

Natural gas	69			(57	)		12

Foreign exchange	7			(7	)		—

Interest	7			(1	)		6

	502			(395	)		107

Derivative - Liability
Power	(554	)		330			(224	)

Natural gas	(103	)		57			(46	)

Foreign exchange	(497	)		7			(490	)

Interest	(6	)		1			(5	)

	(1,160	)		395			(765	)


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, 2013:


at December 31, 2013	Gross derivative instruments presented on the balance sheet			Amounts available for offset1			Net amounts
(millions of Canadian dollars)

Derivative - Asset
Power	415			(277	)		138

Natural gas	73			(61	)		12

Foreign exchange	5			(5	)		—

Interest	14			(2	)		12

	507			(345	)		162

Derivative - Liability
Power	(302	)		277			(25	)

Natural gas	(72	)		61			(11	)

Foreign exchange	(230	)		5			(225	)

Interest	(8	)		2			(6	)

	(612	)		345			(267	)


1	Amounts available for offset do not include cash collateral pledged or received.
With respect to all financial arrangements, including the derivative instruments presented above as at December 31, 2014, the Company had provided cash collateral of $459 million (2013 – $67 million) and letters of credit of $26 million (2013 – $85 million) to its counterparties. The Company held $1 million (2013 – $11 million) in cash collateral and $1 million (2013 – $32 million) in letters of credit from counterparties on asset exposures at December 31, 2014.
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, 2014, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $15 million (2013 – $16 million), for which the Company has provided collateral in the normal course of business of nil (2013 – nil). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2014, the Company would have been required to provide additional collateral of $15 million (2013 – $16 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 power and natural gas 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 derivatives fair value. This category includes long-dated commodity transactions in certain markets where liquidity is low and inputs may include long-term broker quotes.

	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, or increases in the supply of electricity or natural gas, 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 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			Significant other observable inputs Level II1			Significant unobservable inputs			Total
(millions of Canadian dollars, pre-tax)	Level I1						Level III1

Derivative Instrument Assets:
Power commodity contracts	—			417			2			419

Natural gas commodity contracts	40			24			5			69

Foreign exchange contracts	—			7			—			7

Interest rate contracts	—			7			—			7

Derivative Instrument Liabilities:
Power commodity contracts	—			(551	)		(3	)		(554	)

Natural gas commodity contracts	(86	)		(17	)		—			(103	)

Foreign exchange contracts	—			(497	)		—			(497	)

Interest rate contracts	—			(6	)		—			(6	)

Non-Derivative Financial Instruments:
Available for sale assets	—			62			—			62

	(46	)		(554	)		4			(596	)


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 fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2013, are categorized as follows:


at December 31, 2013	Quoted prices in active markets			Significant other observable inputs Level II1			Significant unobservable inputs			Total
(millions of Canadian dollars, pre-tax)	Level I1						Level III1

Derivative Instrument Assets:
Power commodity contracts	—			411			4			415

Natural gas commodity contracts	48			25			—			73

Foreign exchange contracts	—			5			—			5

Interest rate contracts	—			14			—			14

Derivative Instrument Liabilities:
Power commodity contracts	—			(299	)		(3	)		(302	)

Natural gas commodity contracts	(50	)		(22	)		—			(72	)

Foreign exchange contracts	—			(230	)		—			(230	)

Interest rate contracts	—			(8	)		—			(8	)

Non-Derivative Financial Instruments:
Available for sale assets	—			47			—			47

	(2	)		(57	)		1			(58	)


1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2013.
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 dollars, pre-tax)	2014			2013


Balance at beginning of year	1			(2	)

Transfers out of Level III	—			(2	)

Total gains/(losses) included in Net Income	3			(1	)

Total gains included in OCI	—			6

Balance at end of year1	4			1


1	Energy Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2014 of $3 million (2013 – nil).
A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $1 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2014.

CHANGES_IN_OPERATING_WORKING_C

CHANGES IN OPERATING WORKING CAPITAL	12 Months Ended
	Dec. 31, 2014
CHANGES IN OPERATING WORKING CAPITAL
CHANGES IN OPERATING WORKING CAPITAL	CHANGES IN OPERATING WORKING CAPITAL


	year ended December 31	2014		2013		2012
	(millions of Canadian dollars)

	(Increase)/decrease in Accounts Receivable	(189	)	(54	)	67

	(Increase)/decrease in Inventories	(28	)	(30	)	27

	(Increase)/decrease in Other Current Assets	(385	)	40		66

	Increase/(decrease) in Accounts Payable and Other	377		(290	)	127

	Increase in Accrued Interest	36		8		—

	(Increase)/Decrease in Operating Working Capital	(189	)	(326	)	287

ACQUISITIONS_AND_DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
ACQUISITIONS AND DISPOSITIONS	Dec. 31, 2014
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS
	Energy
	Ontario Solar
	As part of a purchase agreement with Canadian Solar Solutions Inc. signed in 2011, TransCanada completed the acquisition of three Ontario solar facilities for $181 million in September 2014 and acquired a fourth facility for $60 million in December 2014. In 2013, TransCanada completed the acquisition of four solar facilities for $216 million. The Company's total investment in the eight solar facilities is $457 million. All power produced by the solar facilities is sold under 20-year PPAs with the Ontario Power Authority.

	Cancarb
	On April 15, 2014, TransCanada sold Cancarb Limited and its related power generation for aggregate gross proceeds of $190 million. Please refer to Note 6 for further information on the sale.
	CrossAlta
	In December 2012, TransCanada purchased BP's 40 per cent interest in the assets of the Crossfield Gas Storage facility and BP's interest in CrossAlta Gas Storage & Services Ltd. (collectively CrossAlta) for $214 million in cash, net of cash acquired, resulting in the Company owning and operating 100 per cent of these operations.
	The Company measured the assets and liabilities acquired at fair value and the transaction resulted in no goodwill. Upon completion of the acquisition, TransCanada began consolidating CrossAlta. Prior to the acquisition, TransCanada applied equity accounting to its 60 per cent ownership interest in CrossAlta.
	Natural Gas Pipelines
	TC PipeLines, LP
	On October 1, 2014, TransCanada completed the sale of its remaining 30 per cent interest in Bison Pipeline LLC
	(Bison LLC) to TC PipeLines, LP for an aggregate purchase price of US$215 million.
	In July 2013, TransCanada completed the sale of a 45 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an aggregate purchase price of US$1.05 billion, which included US$146 million of long-term debt for 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.
	In May 2013, TC PipeLines, LP completed a public offering of 8,855,000 common units at a price of US$43.85 per unit, resulting in gross proceeds of approximately US$388 million and net proceeds of US$373 million after unit issuance costs. TransCanada contributed approximately US$8 million to maintain its two per cent general partnership interest and did not purchase any other units. Upon completion of this offering, TransCanada’s ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent and an after-tax dilution gain of $29 million ($47 million pre-tax) was recorded in Additional Paid-In Capital.
	Gas Pacifico/INNERGY
	On November 26, 2014, TransCanada sold its 30 per cent equity investments in Gas Pacifico and INNERGY for aggregate gross proceeds of $9 million and recognized a gain of $9 million ($8 million after tax).

COMMITMENTS_CONTINGENCIES_AND_

COMMITMENTS, CONTINGENCIES AND GUARANTEES	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, CONTINGENCIES AND GUARANTEES	COMMITMENTS, CONTINGENCIES AND GUARANTEES
	Commitments
	Operating Leases
	Future annual payments, net of sub-lease receipts, under the Company's operating leases for various premises, services and equipment are approximately as follows:


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

	2015	348		48		300

	2016	335		47		288

	2017	335		48		287

	2018	250		27		223

	2019	232		23		209

	2020 and thereafter	407		20		387

		1,907		213		1,694

	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 five years. Net rental expense on operating leases in 2014 was $114 million (2013 – $98 million; 2012 – $84 million).
	TransCanada's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Fixed payments under these PPAs have been included in the above operating leases table. Variable payments have been excluded as these payments are dependent upon plant availability and other factors. TransCanada's share of payments under the PPAs in 2014 was $391 million (2013 – $242 million; 2012 – $238 million). The generating capacities and expiry dates of the PPAs are as follows:


		MW		Expiry Date


	Sundance A	560		December 31, 2017

	Sheerness	756		December 31, 2020

	TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business.
	Other Commitments
	Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts.

	At December 31, 2014, TransCanada was committed to Natural Gas Pipelines capital expenditures totaling approximately $0.9 billion (2013 – $1.3 billion), primarily related to construction costs related to the Mexican and other natural gas pipeline projects.
	At December 31, 2014, the Company was committed to Liquids Pipelines capital expenditures totaling approximately $1.8 billion (2013 – $2.5 billion), primarily related to construction costs of Keystone XL, Grand Rapids and Northern Courier.
	At December 31, 2014, the Company was committed to Energy capital expenditures totaling approximately $0.2 billion (2013 – $0.1 billion), primarily related to capital costs of the Napanee Generating Station.
	Contingencies
	TransCanada is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2014, the Company had accrued approximately $31 million (2013 - $32 million; 2012 – $37 million) related to operating facilities, which represents the present value of the estimated future amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue.
	TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.
	Guarantees
	TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust (BPC), have each severally guaranteed certain contingent financial obligations of Bruce B related to a lease agreement and contractor and supplier services. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations of Bruce A related to a sublease agreement and certain other financial obligations. The Company's exposure under certain of these guarantees is unlimited.
	In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, PPA payments and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.
	The carrying value of these guarantees has been included in Other Long-Term Liabilities. Information regarding the Company’s guarantees is as follows:


			2014				2013
	year ended December 31	Term	Potential Exposure1		Carrying Value		Potential Exposure1	Carrying Value
	(millions of Canadian dollars)

	Bruce Power	Ranging to 20192	634		6		740	8

	Other jointly owned entities	Ranging to 2040	104		14		51	10

			738		20		791	18


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

2	Except for one guarantee with no termination date.

SUBSEQUENT_EVENTS_Notes

SUBSEQUENT EVENTS (Notes)	12 Months Ended
SUBSEQUENT EVENTS (Notes)	Dec. 31, 2014
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	On January 12, 2015 TCPL completed its offering of US$500 million 1.88 per cent Senior Notes due January 12, 2018 and US$250 million Floating Rate Senior Notes due January 12, 2018.

ACCOUNTING_POLICIES_Policies

ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation
	The consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.
Use of Estimates and Judgements	Use of Estimates and Judgments
	In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to:

	•	carrying values and depreciation rates of plant, property and equipment (Note 7);

	•	carrying value of equity investments (Note 8);

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

	•	carrying value of goodwill (Note 10);

	•	amortization rates and carrying values of intangible assets (Note 11);

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

	•	provisions for income taxes (Note 16);

	•	assumptions used to measure retirement and other postretirement 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) of Canada. In the U.S., natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the U.S. Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission of Mexico (CRE). The Company's Canadian, U.S. and Mexican natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls. Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TransCanada's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain of our liquids pipelines projects. RRA is not applicable to the Keystone Pipeline System and, as a result, 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 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. The 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 at the time of the regulatory decision.
	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 periodically 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 rate of return on common equity (ROE) assumptions. Adjustments to revenue are recorded when the NEB decision is received.
	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	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. 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 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.
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 is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.
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 the goodwill might be impaired. If TransCanada concludes that it is not more likely than not that 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 book value, which includes goodwill. If the fair value is less than book 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 PPA is a long-term contract for the purchase or sale of power on a predetermined basis. Substantially all PPAs under which TransCanada buys power are accounted for as operating leases. Initial payments for these PPAs were recognized in Intangible and Other Assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TransCanada records the margin earned from the subleases as a component of Revenues.
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.
	Recorded ARO relates 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 Balance Sheet at historical cost and expensed when they are utilized. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TransCanada are not attributed a value for accounting purposes. When required, TransCanada accrues emission liabilities on the Balance Sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues.
Stock Options and Other Compensation Programs	Stock Options and Other Compensation Programs
	TransCanada's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period, with an offset to Additional Paid-In Capital. Upon exercise of stock options, amounts originally recorded against Additional Paid-In Capital are reclassified to Common Shares.
	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 Balance Sheet and recognizes changes in that funded status through Other Comprehensive Income (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated Other Comprehensive 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 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 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, 2014
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment

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

	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 Sale of Assets	9			—			108			—			117

	Segment earnings	2,187			843			1,051			(150	)		3,931

	Interest Expense													(1,198	)

	Interest Income and Other													91

	Income before Income Taxes													2,824

	Income Tax Expense													(831	)

	Net Income													1,993

	Net Income Attributable to Non-Controlling Interests													(153	)

	Net Income Attributable to Controlling Interests													1,840

	Preferred Share Dividends													(97	)

	Net Income Attributable to Common Shares													1,743


	Capital Spending
	Capital Expenditures	1,768			1,530			206			46			3,550

	Projects Under Development	368			439			—			—			807

		2,136			1,969			206			46			4,357


	at December 31, 2014
	(millions of Canadian dollars)
	Total Assets	27,103			16,116			14,197			1,531			58,947




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

	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	)
Segment earnings	1,881			603			1,113			(124	)		3,473

Interest Expense													(985	)

Interest Income and Other													34

Income before Income Taxes													2,522

Income Tax Expense													(611	)

Net Income													1,911

Net Income Attributable to Non-Controlling Interests													(125	)

Net Income Attributable to Controlling Interests													1,786

Preferred Share Dividends													(74	)

Net Income Attributable to Common Shares													1,712


Capital Spending
Capital Expenditures	1,776			2,286			152			50			4,264

Projects Under Development	245			243			—			—			488

	2,021			2,529			152			50			4,752


at December 31, 2013
(millions of Canadian dollars)
Total Assets	25,165			13,253			13,747			1,733			53,898





year ended December 31, 2012	Natural Gas			Liquids			Energy			Corporate			Total
(millions of Canadian dollars)	Pipelines			Pipelines

Revenues	4,264			1,039			2,704			—			8,007

Income from Equity Investments	157			—			100			—			257

Plant Operating Costs and Other	(1,365	)		(296	)		(819	)		(97	)		(2,577	)
Commodity Purchases Resold	—			—			(1,049	)		—			(1,049	)

Property Taxes	(315	)		(45	)		(74	)		—			(434	)

Depreciation and Amortization	(933	)		(145	)		(283	)		(14	)		(1,375	)
Segment earnings	1,808			553			579			(111	)		2,829

Interest Expense													(976	)

Interest Income and Other													85

Income before Income Taxes													1,938

Income Tax Expense													(466	)

Net Income													1,472

Net Income Attributable to Non-Controlling Interests													(118	)

Net Income Attributable to Controlling Interests													1,354

Preferred Share Dividends													(55	)

Net Income Attributable to Common Shares													1,299


Capital Spending
Capital Expenditures	1,389			1,145			24			37			2,595

Projects Under Development	—			3			—			—			3

	1,389			1,148			24			37			2,598


at December 31, 2012
(millions of Canadian dollars)
Total Assets	23,210			10,485			13,157			1,481			48,333

Revenue from External Customers by Geographic Areas

	year ended December 31	2014			2013			2012
	(millions of Canadian dollars)

	Revenues
	Canada – domestic	4,021			4,659			3,527

	Canada – export	1,314			997			1,121

	United States	4,653			3,029			3,252

	Mexico	197			112			107

		10,185			8,797			8,007

Schedule of Disclosure on Geographic Areas, Long-Lived Assets in Individual Foreign Countries by Country

	at December 31	2014			2013
	(millions of Canadian dollars)

	Plant, Property and Equipment
	Canada	19,191			18,462

	United States	20,098			17,570

	Mexico	2,485			1,574

		41,774			37,606

OTHER_CURRENT_ASSETS_Tables

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2014
Other Assets [Abstract]
Schedule of other current assets

	at December 31	2014	2013

	(millions of Canadian dollars)

	Deferred income tax assets (Note 16)	427	119

	Cash held as collateral	423	42

	Fair value of derivative contracts (Note 23)	409	395

	Other	171	164

	Regulatory Assets (Note 9)	16	42

	Assets held for sale (Note 6)	—	85

		1,446	847

ASSETS_HELD_FOR_SALE_Tables

ASSETS HELD FOR SALE (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule of Assets Held for Sale

	at December 31	2013
	(millions of Canadian dollars)

	Assets Held for Sale
	Cash and Cash Equivalents	1

	Accounts Receivable	12

	Inventories	11

	Plant, Property and Equipment	61

	Total Assets Held for Sale (included in Other Current Assets, Note 5)	85

	Liabilities Related to Assets Held for Sale
	Accounts Payable and Other	4

	Other Long-Term Liabilities	1

	Total Liabilities Related to Assets Held for Sale (included in Accounts Payable and Other, Note 13)	5

PLANT_PROPERTY_AND_EQUIPMENT_T

PLANT, PROPERTY AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule of plant, property and equipment

		2014						2013
	at December 31	Cost		Accumulated		Net		Cost		Accumulated		Net
	(millions of Canadian dollars)			Depreciation		Book Value				Depreciation		Book Value

	Natural Gas Pipelines
	Canadian Mainline
	Pipeline	9,045		5,712		3,333		8,970		5,457		3,513

	Compression	3,423		2,100		1,323		3,392		1,961		1,431

	Metering and other	458		180		278		409		174		235

		12,926		7,992		4,934		12,771		7,592		5,179

	Under construction	135		—		135		85		—		85

		13,061		7,992		5,069		12,856		7,592		5,264

	NGTL System
	Pipeline	8,185		3,619		4,566		7,813		3,410		4,403

	Compression	2,055		1,318		737		2,038		1,253		785

	Metering and other	1,032		446		586		947		418		529

		11,272		5,383		5,889		10,798		5,081		5,717

	Under construction	413		—		413		290		—		290

		11,685		5,383		6,302		11,088		5,081		6,007

	ANR
	Pipeline	1,087		85		1,002		922		59		863

	Compression	741		102		639		635		81		554

	Metering and other	617		110		507		535		91		444

		2,445		297		2,148		2,092		231		1,861

	Under construction	115		—		115		67		—		67

		2,560		297		2,263		2,159		231		1,928

	Other Natural Gas Pipelines
	GTN	1,842		588		1,254		1,685		488		1,197

	Great Lakes	1,807		939		868		1,650		833		817

	Foothills	1,671		1,180		491		1,649		1,120		529

	Mexico	1,518		130		1,388		641		90		551

	Other1	1,800		363		1,437		1,652		288		1,364

		8,638		3,200		5,438		7,277		2,819		4,458

	Under construction	1,132		—		1,132		1,047		—		1,047

		9,770		3,200		6,570		8,324		2,819		5,505

		37,076		16,872		20,204		34,427		15,723		18,704

Liquids Pipelines
Keystone
Pipeline	7,931		463		7,468		5,079		286		4,793

Pumping equipment	964		80		884		1,118		82		1,036

Tanks and other	2,282		144		2,138		962		71		891

	11,177		687		10,490		7,159		439		6,720

Under construction2	4,438		—		4,438		6,020		—		6,020

	15,615		687		14,928		13,179		439		12,740

Energy
Natural Gas – Ravenswood	2,140		476		1,664		1,966		377		1,589

Natural Gas – Other3,4	3,214		971		2,243		3,061		846		2,215

Hydro	736		156		580		673		126		547

Wind	970		190		780		946		155		791

Natural Gas Storage	653		99		554		677		92		585

Solar5	488		13		475		226		2		224

Other	64		19		45		57		30		27

	8,265		1,924		6,341		7,606		1,628		5,978

Under construction	149		—		149		54		—		54

	8,414		1,924		6,490		7,660		1,628		6,032

Corporate	232		80		152		191		61		130

	61,337		19,563		41,774		55,457		17,851		37,606





1	Includes Bison, Portland, North Baja, Tuscarora and Ventures LP.

2	Includes $3.2 billion for Keystone XL at December 31, 2014 (2013 – $2.6 billion). Keystone XL remains subject to regulatory approvals.

3	Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $695 million and $103 million, respectively, at December 31, 2014 (2013 – $640 million and $78 million, respectively). Revenues of $81 million were recognized in 2014 (2013 – $78 million; 2012 – $73 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 each of 2014 and 2013.

EQUITY_INVESTMENTS_Tables

EQUITY INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Schedule of equity investments

	(millions of Canadian dollars)	Ownership		Income/(Loss) from Equity						Equity
		Interest at		Investments						Investments
		December 31, 2014		year ended December 31						at December 31
				2014		2013		2012		2014	2013


	Natural Gas Pipelines
	Northern Border1,2			76		66		72		587	557

	Iroquois	44.5	%	43		41		41		210	188

	TQM	50	%	12		13		16		73	76

	Other	Various		32		25		28		68	62

	Energy
	Bruce A3	48.9	%	209		202		(149	)	3,944	3,988

	Bruce B3	31.6	%	105		108		163		51	377

	ASTC Power Partnership	50	%	8		110		40		29	41

	Portlands Energy	50	%	36		31		28		335	343

	Other4	Various		1		1		18		61	57

	Liquids Pipelines
	Grand Rapids	50	%	—		—		—		240	70

				522		597		257		5,598	5,759


	1	The results reflect a 50 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2014, TransCanada had an ownership interest in TC PipeLines, LP of 28.3 per cent (2013 – 28.9 and 2012 – 33.3 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.2 per cent (2013 – 14.5 and 2012 – 16.7 per cent).

	2	At December 31, 2014, 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 (2013 – US$118 million) due to the fair value assessment of assets at the time of acquisition.

	3	At December 31, 2014, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $776 million (2013 – $820 million) due to the fair value assessment of assets at the time of acquisition.

	4	In December 2012, TransCanada acquired the remaining 40 per cent interest in CrossAlta to bring the Company's ownership interest to 100 per cent. The results reflect the Company's 60 per cent share of equity income up to that date.

Summary of financial information for the equity investees

	year ended December 31	2014		2013		2012
	(millions of Canadian dollars)

	Income
	Revenues	4,814		4,989		3,860

	Operating and Other Expenses	(3,489	)	(3,536	)	(3,090	)
	Net Income	1,264		1,390		717

	Net Income attributable to TransCanada	522		597		257




	at December 31	2014		2013
	(millions of Canadian dollars)

	Balance Sheet
	Current assets	1,412		1,500

	Non current assets	12,260		12,158

	Current liabilities	(1,067	)	(1,117	)
	Non current liabilities	(3,255	)	(2,507	)

RATEREGULATED_BUSINESSES_Table

RATE-REGULATED BUSINESSES (Tables)	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Schedule of regulatory assets and liabilities

	at December 31	2014	2013	Remaining
				Recovery/
				Settlement
	(millions of Canadian dollars)			Period (years)

	Regulatory Assets
	Deferred income taxes1	1,001	1,149	n/a

	Operating and debt-service regulatory assets2	4	16	1

	Pensions and other post retirement benefits3	236	190	n/a

	Long Term Adjustment Account4	—	354	31

	Other5	72	68	n/a

		1,313	1,777

	Less: Current portion included in Other Current Assets (Note 5)	16	42

		1,297	1,735

	Regulatory Liabilities
	Foreign exchange on long-term debt6	42	84	15-Jan

	Operating and debt-service regulatory liabilities2	21	5	1

	ANR-related post-employment and retirement benefits other than pension7	117	104	n/a

	Long Term Adjustment Account4	64	—	44

	Other5	49	43	n/a

		293	236

	Less: Current portion included in Accounts Payable and Other (Note 13)	30	7

		263	229


	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 2014 would have been $28 million higher (2013 – $76 million higher; 2012 - $50 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 2014 would have been $46 million lower (2013 – $171 million higher; 2012 - $61 million lower) had these amounts not been recorded as regulatory assets and liabilities.

	4	The LTAA was established in compliance with the NEB 2013 Decision which is comprised of amounts that were deferred and recoverable in future years. The TSA, also established in the NEB 2013 Decision, includes the variances between revenue and costs. A positive balance in the TSA was realized in 2013 and 2014 and, as specified in the NEB 2013 Decision and the NEB 2014 Decision, the TSA, net of incentive earnings, was combined with the LTAA on December 31, 2013 and 2014.

	5	Pre-tax operating results in 2014 would have been $2 million higher (2013 – $2 million higher; 2012 - $66 million higher) had these amounts not been recorded as regulatory assets and liabilities.

	6	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.

	7	Under the terms of the settlement 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 postretirement 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 postretirement benefits expense. ANR can but is not required to file for new rates. Therefore, the settlement/recovery period is not determinable. Pre-tax operating results in 2014 would have been $13 million higher (2013 – $16 million higher; 2012 - $8 million higher) had these amounts not been recorded as regulatory assets and liabilities.

GOODWILL_Tables

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2014
GOODWILL
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 dollars)	Natural Gas	Energy	Total
		Pipelines

	Balance at January 1, 2013	2,635	823	3,458

	Foreign exchange rate changes	181	57	238

	Balance at December 31, 2013	2,816	880	3,696

	Foreign exchange rate changes	258	80	338

	Balance at December 31, 2014	3,074	960	4,034

INTANGIBLE_AND_OTHER_ASSETS_Ta

INTANGIBLE AND OTHER ASSETS (Tables)	12 Months Ended
INTANGIBLE AND OTHER ASSETS (Tables)	Dec. 31, 2014
INTANGIBLES AND OTHER ASSETS
Schedule of intangible and other assets

	at December 31	2014	2013
	(millions of Canadian dollars)	2014	2013

	Capital projects under development	1,286	571
	Capital projects under development	1,286	571
	PPAs	272	324
	PPAs	272	324
	Deferred income tax assets and charges (Note 16)	180	225
	Deferred income tax assets and charges (Note 16)	180	225
	Loans and advances1	167	183
	Loans and advances1	167	183
	Fair value of derivative contracts (Note 23)	93	112
	Fair value of derivative contracts (Note 23)	93	112
	Employee post-retirement benefits (Note 22)	14	16
	Employee post-retirement benefits (Note 22)	14	16
	Other	692	524
	Other	692	524
		2,704	1,955
		2,704	1,955

	1	TransCanada held a note receivable from the seller of Ravenswood of $213 million (US$184 million) and $226 million (US$212 million) as at December 31, 2014 and at December 31, 2013, respectively which bears interest at 6.75 per cent and matures in 2040. The current portion included in Other Current Assets was $46 million (US$40 million) at December 31, 2014, and $43 million (US$40 million) at December 31, 2013.
Schedule of amounts related to PPAs included in Intangible and Other Assets	The following amounts related to PPAs are included in Intangible and Other Assets:


		2014			2013
	at December 31	Cost	Accumulated	Net Book	Cost	Accumulated	Net Book
	(millions of Canadian dollars)	Cost	Amortization	Value	Cost	Amortization	Value

	Sheerness	585	351	234	585	312	273
	Sheerness	585	351	234	585	312	273
	Sundance A	225	187	38	225	174	51
	Sundance A	225	187	38	225	174	51
		810	538	272	810	486	324
		810	538	272	810	486	324

NOTES_PAYABLE_Tables

NOTES PAYABLE (Tables)

12 Months Ended

Dec. 31, 2014

Short-term Debt [Abstract]

Schedule of notes payable

2014

2013

(millions of Canadian dollars)

Outstanding December 31

Weighted

Outstanding December 31

Weighted

Average

Interest Rate

per Annum

at December 31

Canadian dollars

1,540

1.2

751

1.2

U.S. dollars (2014 - US$800; 2013 – US$1,025)

927

0.7

1,091

0.3

2,467

1,842

Schedule of credit facilities

These unsecured credit facilities included the following:

year ended December 31

at December 31, 2014

2014

2013

2012

Amount

Unused Capacity

Borrower

For

Matures

Cost to maintain

(millions of Canadian dollars)

$3 billion

TCPL

Committed, syndicated, revolving, extendible TCPL credit facility

Dec-19

US$1 billion

TCPL USA

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

Nov-15

US$1 billion

TAIL

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

Nov-15

—

$1.4 billion

$0.6 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, 2014
Payables and Accruals [Abstract]
Schedule of accounts payable and other

	at December 31	2014	2013
	(millions of Canadian dollars)

	Trade payables	1,624	866

	Fair value of derivative contracts (Note 23)	749	357

	Dividends payable	359	338

	Deferred Income Tax Liabilities (Note 16)	4	26

	Regulatory Liabilities (Note 9)	30	7

	Liabilities related to assets held for sale (Note 6)	—	5

	Other	130	556

		2,896	2,155

OTHER_LONGTERM_LIABILITIES_Tab

OTHER LONG-TERM LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2014
Deferred Costs, Noncurrent [Abstract]
Schedule of deferred amounts

	at December 31	2014	2013
	(millions of Canadian dollars)

	Employee post-retirement benefit (Note 22)	444	244

	Fair value of derivative contracts (Note 23)	411	255

	Asset retirement obligations	98	83

	Guarantees (Note 26)	15	18

	Other	84	56

		1,052	656

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Unclassified [Abstract]
Schedule of long-term debt	The Company issued Long-Term Debt over the last three years ended December 31 as follows:


	(millions of Canadian dollars, unless otherwise noted)
	Company		Issue date		Type		Maturity date		Amount			Interest Rate

	TRANSCANADA PIPELINES LIMITED
			Feb-14		Senior Unsecured Notes		Mar-34		US 1,250			4.63	%

			Oct-13		Senior Unsecured Notes		Oct-23		US 625			3.75	%

			Oct-13		Senior Unsecured Notes		Oct-43		US 625			5	%

			Jul-13		Senior Unsecured Notes		Jun-16		US 500			Floating

			Jul-13		Medium-Term Notes		Jul-23		450			3.69	%

			Jul-13		Medium-Term Notes		Nov-41		300			4.55	%

			Jan-13		Senior Unsecured Notes		Jan-16		US 750			0.75	%

			Aug-12		Senior Unsecured Notes		Aug-22		US 1,000			2.5	%

			Mar-12		Senior Unsecured Notes		Mar-15		US 500			0.88	%

	TC PIPELINES, LP
			Jul-13		Unsecured Term Loan Facility		Jul-18		US 500			Floating



				2014						2013
	Outstanding loan amounts	Maturity Dates		Outstanding December 31			Interest			Outstanding December 31			Interest
	(millions of Canadian dollars)						Rate1						Rate1

	TRANSCANADA PIPELINES LIMITED
	Debentures
	Canadian dollars	2015 to 2020		749			10.9	%		874			10.9	%

	U.S. dollars (2014 and 2013 US$400)	2021		464			9.9	%		425			9.9	%

	Medium-Term Notes
	Canadian dollars	2016 to 2041		4,048			5.7	%		4,799			5.7	%

	Senior Unsecured Notes
	U.S. dollars (2014 – US$13,526; 2013 – US$12,276)	2015 to 2043		15,655			5	%		13,027			5	%

				20,916						19,125

	NOVA GAS TRANSMISSION LTD.
	Debentures and Notes
	Canadian dollars2	2016 to 2024		325			11.5	%		378			11.5	%

	U.S. dollars (2014 and 2013 – US$200)	2023		232			7.9	%		213			7.9	%

	Medium-Term Notes
	Canadian dollars	2025 to 2030		504			7.4	%		504			7.4	%

	U.S. dollars (2014 and 2013 – US$33)	2026		38			7.5	%		34			7.5	%

				1,099						1,129

	ANR PIPELINE COMPANY
	Senior Unsecured Notes
	U.S. dollars (2014 and 2013 – US$432)	2021 to 2025		502			8.9	%		459			8.9	%

GAS TRANSMISSION NORTHWEST CORPORATION
Senior Unsecured Notes
U.S. dollars (2014 and 2013 – US$325)	2015 to 2035		377			5.5	%		346			5.5	%

TC PIPELINES, LP
Unsecured Loan
U.S. dollars (2014 – US$330; 2013 – US$380)	2017		383			1.4	%		404			1.4	%

Unsecured Term Loan Facility
U.S. dollars (2014 – US$500; 2013 – US$500)	2015 to 2018		580			1.4	%		532			1.4	%

Senior Unsecured Notes
U.S. dollars (2014 and 2013 – US$350)	2021		405			4.7	%		372			4.7	%

			1,368						1,308

GREAT LAKES GAS TRANSMISSION
LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. dollars (2014 – US$316; 2013 – US$335)	2018 to 2030		367			7.8	%		356			7.8	%

TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
U.S. dollars (2014 – US$20; 2013 – US$24)	2017		23			4	%		25			4	%

PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes3
U.S. dollars (2014 – US$90; 2013 – US$110)	2018		105			6.1	%		117			6.1	%

			24,757						22,865

Less: Current Portion of Long-Term Debt			1,797						973

			22,960						21,892



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 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 2014 or 2013.

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

Schedule of repayments of long-term debt	Principal repayments on the Long-Term Debt of the Company for the next five years are approximately as follows:


	(millions of Canadian dollars)		2015		2016		2017		2018		2019

	Principal repayments on Long-Term Debt		1,797		2,225		846		1,766		1,007
Schedule of long-term debt, retired	The Company retired Long-Term Debt over the last three years ended December 31 as follows:


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

	TRANSCANADA PIPELINES LIMITED
			Jun-14		Debentures		125			11.1	%

			Feb-14		Medium-Term Notes		300			5.05	%

			Jan-14		Medium-Term Notes		450			5.65	%

			Aug-13		Senior Unsecured Notes		US 500			5.05	%

			Jun-13		Senior Unsecured Notes		US 350			4	%

			May-12		Senior Unsecured Notes		US 200			8.63	%

	NOVA GAS TRANSMISSION LTD.
			Jun-14		Debentures		53			11.2	%

			Dec-12		Debentures		US 175			8.5	%

Schedule of interest expense

	year ended December 31	2014			2013			2012
	(millions of Canadian dollars)

	Interest on Long-Term Debt	1,317			1,216			1,190

	Interest on Junior Subordinated Notes (Note 17)	70			65			63

	Interest on short-term debt	15			12			16

	Capitalized interest	(259	)		(287	)		(300	)
	Amortization and other financial charges1	55			(21	)		7

		1,198			985			976


	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.

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of provision for income taxes

	year ended December 31	2014		2013		2012
	(millions of Canadian dollars)

	Current
	Canada	103		27		167

	Foreign	42		16		14

		145		43		181

	Deferred
	Canada	309		245		69

	Foreign	377		323		216

		686		568		285

	Income Tax Expense	831		611		466

Schedule of geographic components of income

	year ended December 31	2014		2013		2012
	(millions of Canadian dollars)

	Canada	1,146		1,224		842

	Foreign	1,678		1,298		1,096

	Income before Income Taxes	2,824		2,522		1,938

Schedule of reconciliation of income tax expense

	year ended December 31	2014		2013		2012
	(millions of Canadian dollars)

	Income before Income Taxes	2,824		2,522		1,938

	Federal and provincial statutory tax rate	25	%	25	%	25	%
	Expected income tax expense	706		631		485

	Income tax differential related to regulated operations	129		(13	)	41

	Higher/(lower) effective foreign tax rates	25		33		(12	)

	Income from equity investments and non-controlling interests	(38	)	(28	)	(27	)
	Tax legislation change	—		(25	)	—

	Other	9		13		(21	)

	Actual Income Tax Expense	831		611		466

Schedule of deferred income tax assets and liabilities and amounts classified in the consolidated balance sheet

	at December 31	2014		2013
	(millions of Canadian dollars)

	Deferred Income Tax Assets
	Operating loss carryforwards	1,266		826

	Deferred amounts	215		223

	Unrealized foreign exchange losses on long-term debt	140		—

	Financial Instruments	104		—

	Other	248		128

		1,973		1,177

	Less: Valuation allowance1	125		—

		1,848		1,177

	Deferred Income Tax Liabilities
	Difference in accounting and tax bases of plant, property and equipment and PPAs	5,548		4,245

	Equity investments	648		682

	Taxes on future revenue requirement	253		291

	Unrealized foreign exchange gains on long-term debt	—		35

	Other	71		170

		6,520		5,423

	Net Deferred Income Tax Liabilities	4,672		4,246



	1	A valuation allowance was recorded in 2014 as the Company believes that it is more likely than not that the tax benefit related to the unrealized foreign exchange losses on the long term debt 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	2014		2013
	(millions of Canadian dollars)

	Deferred Income Tax Assets
	Other Current Assets (Note 5)	427		119

	Intangible and Other Assets (Note 11)	180		225

		607		344

	Deferred Income Tax Liabilities
	Accounts Payable and Other (Note 13)	4		26

	Deferred Income Tax Liabilities	5,275		4,564

		5,279		4,590

	Net Deferred Income Tax Liabilities	4,672		4,246

Schedule of 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	2014		2013		2012
	(millions of Canadian dollars)

	Unrecognized tax benefits at beginning of year	23		49		52

	Gross increases – tax positions in prior years	3		3		2

	Gross decreases – tax positions in prior years	(8	)	(28	)	(6	)
	Gross increases – tax positions in current year	1		2		9

	Lapses of statute of limitations	(1	)	(3	)	(8	)
	Unrecognized tax benefits at end of year	18		23		49

JUNIOR_SUBORDINATED_NOTES_Tabl

JUNIOR SUBORDINATED NOTES (Tables)

12 Months Ended

Dec. 31, 2014

Junior Subordinated Notes [Abstract]

Schedule of junior subordinated notes

2014

2013

Outstanding loan amount

Maturity

Outstanding December 31

Effective

Outstanding December 31

Effective

(millions of Canadian dollars)

Date

Interest Rate

TRANSCANADA PIPELINES LIMITED

U.S. dollars (2014 and 2013 – US$1,000)

2067

1,160

6.5

1,063

6.5

NONCONTROLLING_INTERESTS_Table

NON-CONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2014
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 were as follows:


	at December 31	2014	2013
	(millions of Canadian dollars)

	Non-controlling interest in TC PipeLines, LP	1,479	1,323

	Non-controlling interest in Portland	104	94

	Preferred shares of TCPL	—	194

		1,583	1,611

	The Company's Non-Controlling Interests included in the Consolidated Statement of Income were as follows:


	year ended December 31	2014	2013	2012
	(millions of Canadian dollars)

	Non-controlling interest in TC PipeLines, LP	136	93	91

	Non-controlling interest in Portland	15	12	5

	Preferred shares of TCPL	2	20	22

		153	125	118

COMMON_SHARES_Tables

COMMON SHARES (Tables)	12 Months Ended
COMMON SHARES (Tables)	Dec. 31, 2014
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Schedule of common shares

		Number of			Amount
		Shares			Amount
		(thousands)			(millions of Canadian dollars)
		(thousands)			(millions of Canadian dollars)
	Outstanding at January 1, 2012	703,861			12,011
	Outstanding at January 1, 2012	703,861			12,011
	Exercise of options	1,600			58
	Exercise of options	1,600			58
	Outstanding at December 31, 2012	705,461			12,069
	Outstanding at December 31, 2012	705,461			12,069
	Exercise of options	1,980			80
	Exercise of options	1,980			80
	Outstanding at December 31, 2013	707,441			12,149
	Outstanding at December 31, 2013	707,441			12,149
	Exercise of options	1,221			53
	Exercise of options	1,221			53
	Outstanding at December 31, 2014	708,662			12,202
	Outstanding at December 31, 2014	708,662			12,202
Schedule of weighted average shares

	Weighted Average Common Shares Outstanding	2014			2013		2012
	(millions)	2014			2013		2012

	Basic	708			706.7		704.6
	Basic	708			706.7		704.6
	Diluted	709.6			707.7		705.7
	Diluted	709.6			707.7		705.7
Schedule of stock options activity

		Number of			Weighted			Options
		Options			Average			Exercisable
					Exercise
					Prices
		(thousands)						(thousands)
		(thousands)						(thousands)
	Outstanding at January 1, 2012	7,100				$35.44		5,165
	Outstanding at January 1, 2012	7,100				$35.44		5,165
	Granted	1,978				$42.03
	Granted	1,978				$42.03
	Exercised	(1,600	)			$33.13
	Exercised	(1,600	)			$33.13
	Forfeited	(44	)			$36.55
	Forfeited	(44	)			$36.55
	Outstanding at December 31, 2012	7,434				$37.69		4,588
	Outstanding at December 31, 2012	7,434				$37.69		4,588
	Granted	1,939				$47.09
	Granted	1,939				$47.09
	Exercised	(1,980	)			$36.12
	Exercised	(1,980	)			$36.12
	Outstanding at December 31, 2013	7,393				$40.57		3,954
	Outstanding at December 31, 2013	7,393				$40.57		3,954
	Granted	2,292				$49.03
	Granted	2,292				$49.03
	Exercised	(1,221	)			$43.00
	Exercised	(1,221	)			$43.00
	Outstanding at December 31, 2014	8,464				$43.17		4,902
	Outstanding at December 31, 2014	8,464				$43.17		4,902
Schedule of stock options outstanding and exercisable by the range of exercise price	Stock options outstanding at December 31, 2014 were as follows:


		Options Outstanding							Options Exercisable
	Range of	Number of			Weighted			Weighted	Number of	Weighted		Weighted
	Exercise Prices	Options			Average			Average	Options	Average		Average
					Exercise			Remaining		Exercise		Remaining
					Price			Contractual		Price		Contractual
								Life				Life
		(thousands)						(years)	(thousands)			(years)
		(thousands)						(years)	(thousands)			(years)
	$30.10 to $36.26	1,410				$33.85		1.7	1,410		$33.85	1.7
	$30.10 to $36.26	1,410				$33.85		1.7	1,410		$33.85	1.7
	$36.90 to $41.65	1,101				$38.24		3.1	1,101		$38.24	3.1
	$36.90 to $41.65	1,101				$38.24		3.1	1,101		$38.24	3.1
	$41.95 to $45.29	1,819				$42.04		4.2	1,464		$42.02	4.2
	$41.95 to $45.29	1,819				$42.04		4.2	1,464		$42.02	4.2
	$47.09	1,842				$47.09		5.1	847		$47.09	5.1
	$47.09	1,842				$47.09		5.1	847		$47.09	5.1
	$49.03	2,292				$49.03		6.2	80		$49.03	6.2
	$49.03	2,292				$49.03		6.2	80		$49.03	6.2
		8,464				$43.17		4.3	4,902		$39.81	3.3
		8,464				$43.17		4.3	4,902		$39.81	3.3
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	2014			2013		2012
	year ended December 31	2014			2013		2012

	Expected life (years)	6			6		5.9
	Expected life (years)	6			6		5.9
	Interest rate	1.8	%		1.7	%	1.6	%
	Volatility1	17	%		18	%	19	%
	Dividend yield	3.8	%		3.7	%	4.2	%
	Forfeiture rate	5	%		15	%	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	2014		2013		2012
	(millions of Canadian dollars, unless noted otherwise)	2014		2013		2012

	Total intrinsic value of options exercised	$68		$25		$18
	Fair value of options that have vested	$113		$65		$49
	Total options vested	2.0 million		1.3 million		1.0 million

PREFERRED_SHARES_Tables

PREFERRED SHARES (Tables)	12 Months Ended
	Dec. 31, 2014
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Schedule of preferred shares

	at December 31	Number of	Current Yield		Annual Dividend Per Share1		Redemption Price Per Share2		Redemption and Conversion Option Date 2,3	Right to Convert Into 3,4	2014	2013
		Shares
		Authorized and
		Outstanding
	Cumulative First Preferred Shares5	(thousands)									(millions of	(millions of
											Canadian dollars)6	Canadian dollars)6

	Series 1	9,498	3.27	%		$0.82		$25.00	31-Dec-19	Series 2	233	539

	Series 2	12,502	Floating7		Floating			$25.50	31-Dec-19	Series 1	306	—

	Series 3	14,000	4	%		$1.00		$25.00	30-Jun-15	Series 4	343	343

	Series 5	14,000	4.4	%		$1.10		$25.00	30-Jan-16	Series 6	342	342

	Series 7	24,000	4	%		$1.00		$25.00	30-Apr-19	Series 8	589	589

	Series 9	18,000	4.25	%		$1.06		$25.00	30-Oct-19	Series 10	442	—

											2,255	1,813


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

	2	Series 2 preferred shares are redeemable by TransCanada at any time for $25.50 per share plus all accrued and unpaid dividends on such redemption date, unless redeemed on a designated redemption option date, or any fifth anniversary thereafter, in which case they are redeemable at $25.00 per share plus all accrued and unpaid dividends. For all other series of preferred shares, TransCanada may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the redemption option date and on every fifth anniversary thereafter.

	3	The holder will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter.

	4	With the exception of Series 1 preferred shares, if converted each series will be entitled to receive floating rate, cumulative, quarterly, preferential dividends per share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate + 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), and 2.35 per cent (Series 10). Holders of Series 1 preferred shares will receive fixed, cumulative, quarterly preferential dividends if converted.

	5	With the exception of Series 2 preferred shares, and where the redemption and/or conversion option is not exercised on a designated conversion date, the dividend rate on the fixed rate, cumulative, quarterly, preferential dividends will reset on the redemption and conversion option date and every fifth year thereafter to an annualized rate equal to the then five-year Government of Canada bond yield + 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), and 2.35 per cent (Series 9). Holders of Series 2 preferred shares will receive floating rate, cumulative, quarterly, preferential dividends.

	6	Net of underwriting commissions and deferred income taxes.

	7	Commencing December 31, 2014, the floating quarterly dividend rate for the Series 2 preferred shares is 2.82 per cent and will reset each quarter going forward.

OTHER_COMPREHENSIVE_INCOME_AND1

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Schedule of components of other comprehensive income	Components of OCI including Non-Controlling Interests and the related tax effects are as follows:


	year ended December 31, 2014		Before tax amount		Income tax recovery/(expense)		Net of tax amount
	(millions of Canadian dollars)

	Foreign currency translation gains on net investments 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		Net of tax amount
	(millions of Canadian dollars)				recovery/(expense)

	Foreign currency translation gains on net investments 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



	year ended December 31, 2012		Before tax amount		Income tax recovery/(expense)		Net of tax amount
	(millions of Canadian dollars)
	Foreign currency translation losses on net investments in foreign operations		(97	)	(32	)	(129	)
	Change in fair value of net investment hedges		59		(15	)	44

	Change in fair value of cash flow hedges		61		(13	)	48

	Reclassification to Net Income of gains and losses on cash flow hedges		219		(81	)	138

	Unrealized actuarial gains and losses on pension and other post-retirement benefit plans		(104	)	31		(73	)

	Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans		22		—		22

	Other comprehensive loss on Equity Investments		(93	)	23		(70	)

	Other comprehensive income/(loss)		67		(87	)	(20	)

Schedule of changes in accumulated other comprehensive income	The changes in AOCI by component is as follows:


			Currency		Cash flow		Pension and OPEB plan adjustments		Equity Investments		Total1
			translation		hedges
			adjustments

	AOCI Balance at January 1, 2012		(643	)	(302	)	(236	)	(268	)	(1,449	)
	Other comprehensive (loss)/income before reclassifications2		(64	)	48		(73	)	(67	)	(156	)

	Amounts reclassified from Accumulated Other Comprehensive Loss		—		138		22		(3	)	157

	Net current period other comprehensive (loss)/income		(64	)	186		(51	)	(70	)	1

	AOCI Balance at December 31, 2012		(707	)	(116	)	(287	)	(338	)	(1,448	)
	Other comprehensive income before reclassifications2		78		71		67		219		435

	Amounts reclassified from Accumulated Other Comprehensive Loss		—		41		23		15		79

	Net current period other comprehensive income		78		112		90		234		514

	AOCI Balance at December 31, 2013		(629	)	(4	)	(197	)	(104	)	(934	)
	Other comprehensive income/(loss) before reclassifications2		111		(69	)	(102	)	(206	)	(266	)

	Amounts reclassified from Accumulated Other Comprehensive Loss3		—		(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	)

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

	2	OCI before reclassifications on currency translation adjustments is net of non-controlling interest gains of $130 million in 2014 (2013 - $66 million gains; 2012 - $21 million losses).

	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 $95 million ($55 million, net of tax) at December 31, 2014. 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						Affected line item
			accumulated other						in the consolidated
			comprehensive loss1						statement of
	year ended December 31		2014		2013		2012		income
	(millions of Canadian dollars)

	Cash flow hedges
	Power and Natural Gas		111		(44	)	201		Revenue (Energy)

	Interest		(16	)	(16	)	18		Interest Expense

			95		(60	)	219		Total before tax

			(40	)	19		(81	)	Income Tax Expense

			55		(41	)	138		Net of tax

	Pension and OPEB plan adjustments

	Amortization of actuarial loss and past service cost2		(25	)	(34	)	(22	)	2
			7		11		—		Income Tax Expense

			(18	)	(23	)	(22	)	Net of tax
	Equity Investments
	Equity Income		(2	)	(20	)	5		Income from Equity Investments

			—		5		(2	)	Income Tax Expense

			(2	)	(15	)	3		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 additional detail.

EMPLOYEE_POSTRETIREMENT_BENEFI1

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)	12 Months Ended
EMPLOYEE POST-RETIREMENT BENEFITS (Tables)	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Schedule of payments for defined benefit plans	Total cash payments for employee post-retirement benefits, consisting of cash contributed by the Company were as follows:


	year ended December 31	2014		2013		2012
	(millions of Canadian dollars)	2014		2013		2012

	DB Plans	73		79		83
	DB Plans	73		79		83
	Other post-retirement benefit plans	6		6		7
	Other post-retirement benefit plans	6		6		7
	Savings and DC Plans	37		29		24
	Savings and DC Plans	37		29		24
		116		114		114
		116		114		114
Schedule of change in benefit obligations, change in plan assets, and funded status	The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2014 and the next required valuation will be as at January 1, 2015.


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

	Change in Benefit Obligation1
	Benefit obligation – beginning of year	2,224		2,142		191		186
	Benefit obligation – beginning of year	2,224		2,142		191		186
	Service cost	85		84		2		2
	Service cost	85		84		2		2
	Interest cost	113		96		10		7
	Interest cost	113		96		10		7
	Employee contributions	4		4		—		—
	Employee contributions	4		4		—		—
	Benefits paid	(102	)	(83	)	(7	)	(7	)
	Actuarial loss/(gain)	302		(39	)	14		(2	)
	Actuarial loss/(gain)	302		(39	)	14		(2	)
	Foreign exchange rate changes	32		20		6		5
	Foreign exchange rate changes	32		20		6		5
	Benefit obligation – end of year	2,658		2,224		216		191
	Benefit obligation – end of year	2,658		2,224		216		191
	Change in Plan Assets
	Plan assets at fair value – beginning of year	2,152		1,825		35		32
	Plan assets at fair value – beginning of year	2,152		1,825		35		32
	Actual return on plan assets	246		313		2		2
	Actual return on plan assets	246		313		2		2
	Employer contributions2	73		79		6		6
	Employer contributions2	73		79		6		6
	Employee contributions	4		4		—		—
	Employee contributions	4		4		—		—
	Benefits paid	(102	)	(83	)	(7	)	(7	)
	Foreign exchange rate changes	25		14		3		2
	Foreign exchange rate changes	25		14		3		2
	Plan assets at fair value – end of year	2,398		2,152		39		35
	Plan assets at fair value – end of year	2,398		2,152		39		35
	Funded Status – Plan Deficit	(260	)	(72	)	(177	)	(156	)

	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 $181 million in letters of credit provided to the Canadian DB Plans for funding purposes (2013 - $134 million).
Schedule of amounts recognized in the Company's Balance Sheet for its DB plans and other post-retirement benefits plans	The amounts recognized in the Company's Balance Sheet for its DB Plans and other post-retirement benefits plans are as follows:


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

	Intangible and Other Assets (Note 11)	—		—		14		16
	Intangible and Other Assets (Note 11)	—		—		14		16
	Accounts Payable and Other (Note 13)	—		—		(7	)	—
	Accounts Payable and Other (Note 13)	—		—		(7	)	—
	Other Long-Term Liabilities (Note 14)	(260	)	(72	)	(184	)	(172	)
		(260	)	(72	)	(177	)	(156	)
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
		Benefit Plans				Post-Retirement
						Benefit Plans
	(millions of Canadian dollars)	2014		2013		2014		2013
	(millions of Canadian dollars)	2014		2013		2014		2013

	Projected benefit obligation1	(2,658	)	(2,224	)	(191	)	(172	)
	Plan assets at fair value	2,398		2,152		—		—
	Plan assets at fair value	2,398		2,152		—		—
	Funded Status – Deficit	(260	)	(72	)	(191	)	(172	)

	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	2014		2013
	(millions of Canadian dollars)	2014		2013

	Accumulated benefit obligation	(2,437	)	(2,039	)
	Plan assets at fair value	2,398		2,152
	Plan assets at fair value	2,398		2,152
	Funded Status – (Deficit)/Surplus	(39	)	113
	Funded Status – (Deficit)/Surplus	(39	)	113
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	2014		2013
	(millions of Canadian dollars)	2014		2013

	Accumulated benefit obligation	(715	)	(569	)
	Plan assets at fair value	597		537
	Plan assets at fair value	597		537
	Funded Status – Deficit	(118	)	(32	)
Schedule of the Company's pension plans 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:
	Asset Category


		Percentage of				Target Allocations1
		Plan Assets				Target Allocations1
	at December 31	2014		2013		2014
	at December 31	2014		2013		2014

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

	1	Target allocations were revised in November 2013 and the investment mix is being adjusted over time accordingly.

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
	at December 31					Plan Assets
	(millions of Canadian dollars)	2014		2013		2014		2013
	(millions of Canadian dollars)	2014		2013		2014		2013

	Debt securities	1		2		0.1	%	0.1	%
	Debt securities	1		2		0.1	%	0.1	%
	Equity securities	1		2		0.1	%	0.1	%
	Equity securities	1		2		0.1	%	0.1	%
Schedule of plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into three categories based on a fair value hierarchy	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.


	at December 31	Quoted Prices in				Significant Other Observable Inputs				Significant Unobservable Inputs				Total		Percentage of
		Active Markets				(Level II)				(Level III)						Total Portfolio
		(Level I)
	(millions of Canadian dollars)	2014		2013		2014		2013		2014		2013		2014	2013	2014		2013
	(millions of Canadian dollars)	2014		2013		2014		2013		2014		2013		2014	2013	2014		2013

	Asset Category
	Cash and Cash Equivalents	20		17		—		—		—		—		20	17	1	%	1	%
	Cash and Cash Equivalents	20		17		—		—		—		—		20	17	1	%	1	%
	Equity Securities:
	Canadian	361		474		142		170		—		—		503	644	21	%	29	%
	Canadian	361		474		142		170		—		—		503	644	21	%	29	%
	U.S.	516		423		35		37		—		—		551	460	23	%	21	%
	U.S.	516		423		35		37		—		—		551	460	23	%	21	%
	International	218		36		147		330		—		—		365	366	15	%	17	%
	International	218		36		147		330		—		—		365	366	15	%	17	%
	Global	—		—		141		14		—		—		141	14	6	%	1	%
	Global	—		—		141		14		—		—		141	14	6	%	1	%
	Emerging	7		—		80		—		—		—		87	—	3	%	—
	Emerging	7		—		80		—		—		—		87	—	3	%	—
	Fixed Income Securities:
	Canadian Bonds:
	Federal	—		—		218		190		—		—		218	190	9	%	9	%
	Federal	—		—		218		190		—		—		218	190	9	%	9	%
	Provincial	—		—		180		154		—		—		180	154	7	%	7	%
	Provincial	—		—		180		154		—		—		180	154	7	%	7	%
	Municipal	—		—		7		6		—		—		7	6	—		—
	Municipal	—		—		7		6		—		—		7	6	—		—
	Corporate	—		—		76		77		—		—		76	77	3	%	3	%
	Corporate	—		—		76		77		—		—		76	77	3	%	3	%
	U.S. Bonds:
	State	—		—		47		33		—		—		47	33	2	%	2	%
	State	—		—		47		33		—		—		47	33	2	%	2	%
	Corporate	—		—		59		48		—		—		59	48	2	%	2	%
	Corporate	—		—		59		48		—		—		59	48	2	%	2	%
	International:
	Corporate	—		—		14		20		—		—		14	20	1	%	1	%
	Corporate	—		—		14		20		—		—		14	20	1	%	1	%
	Mortgage Backed	—		—		39		26		—		—		39	26	2	%	1	%
	Mortgage Backed	—		—		39		26		—		—		39	26	2	%	1	%
	Other Investments:
	Private Equity Funds	—		—		—		—		13		18		13	18	—		1	%
	Private Equity Funds	—		—		—		—		13		18		13	18	—		1	%
	Funds held on deposit	117		114		—		—		—		—		117	114	5	%	5	%
	Funds held on deposit	117		114		—		—		—		—		117	114	5	%	5	%
		1,239		1,064		1,185		1,105		13		18		2,437	2,187	100	%	100	%
		1,239		1,064		1,185		1,105		13		18		2,437	2,187	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 dollars, pre-tax)	Private
	(millions of Canadian dollars, pre-tax)	Equity Funds

	Balance at December 31, 2012	19
	Balance at December 31, 2012	19
	Purchases and Sales	(4	)
	Realized and unrealized gains	3
	Realized and unrealized gains	3
	Balance at December 31, 2013	18
	Balance at December 31, 2013	18
	Purchases and sales	(7	)
	Realized and unrealized gains	2
	Realized and unrealized gains	2
	Balance at December 31, 2014	13
	Balance at December 31, 2014	13
Schedule of estimated future benefit payments, which reflect expected future service	The following are estimated future benefit payments, which reflect expected future service:


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

	2015	102		8
	2015	102		8
	2016	108		8
	2016	108		8
	2017	114		9
	2017	114		9
	2018	120		9
	2018	120		9
	2019	127		10
	2019	127		10
	2020 to 2024	728		51
	2020 to 2024	728		51
Schedule of weighted average assumptions used in calculating benefit obligation	The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:


		Pension Benefit Plans				Other
						Post-Retirement
						Benefit Plans
	at December 31	2014		2013		2014		2013
	at December 31	2014		2013		2014		2013

	Discount rate	4.15	%	4.95	%	4.2	%	5	%
	Rate of compensation increase	3.15	%	3.15	%	—		—
	Rate of compensation increase	3.15	%	3.15	%	—		—
Schedule of significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs	The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:


		Pension						Other
		Benefit Plans						Post-Retirement
								Benefit Plans
	year ended December 31	2014		2013		2012		2014		2013		2012
	year ended December 31	2014		2013		2012		2014		2013		2012

	Discount rate	4.95	%	4.35	%	5.05	%	5	%	4.35	%	5.1	%
	Expected long-term rate of return on plan assets	6.9	%	6.7	%	6.7	%	4.6	%	4.6	%	6.4	%
	Rate of compensation increase	3.15	%	3.15	%	3.15	%	—		—		—
	Rate of compensation increase	3.15	%	3.15	%	3.15	%	—		—		—
Schedule of effects of a one per cent 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 dollars)	Increase		Decrease
	(millions of Canadian dollars)	Increase		Decrease

	Effect on total of service and interest cost components	1		(1	)
	Effect on total of service and interest cost components	1		(1	)
	Effect on post-retirement benefit obligation	14		(12	)
	Effect on post-retirement benefit obligation	14		(12	)
Schedule of the Company's net benefit cost	The Company's net benefit cost is as follows:


	at December 31	Pension						Other
		Benefit Plans						Post-Retirement
								Benefit Plans
	(millions of Canadian dollars)	2014		2013		2012		2014		2013		2012
	(millions of Canadian dollars)	2014		2013		2012		2014		2013		2012

	Service cost	85		84		66		2		2		2
	Service cost	85		84		66		2		2		2
	Interest cost	113		96		94		10		7		8
	Interest cost	113		96		94		10		7		8
	Expected return on plan assets	(139	)	(120	)	(113	)	(2	)	(2	)	(2	)
	Amortization of actuarial loss	21		30		18		2		2		1
	Amortization of actuarial loss	21		30		18		2		2		1
	Amortization of past service cost	2		2		2		—		—		1
	Amortization of past service cost	2		2		2		—		—		1
	Amortization of regulatory asset	18		30		19		1		1		1
	Amortization of regulatory asset	18		30		19		1		1		1
	Amortization of transitional obligation related to regulated business	—		—		—		2		2		2
		—		—		—		2		2		2
	Net Benefit Cost Recognized	100		122		86		15		12		13
	Net Benefit Cost Recognized	100		122		86		15		12		13
Schedule of the pre-tax amounts recognized in AOCI	Pre-tax amounts recognized in AOCI were as follows:


		2014				2013				2012
	at December 31	Pension		Other Post-		Pension		Other Post-		Pension		Other Post-
	at December 31	Benefits		Retirement		Benefits		Retirement		Benefits		Retirement
	(millions of Canadian dollars)			Benefits				Benefits				Benefits

	Net loss	354		40		236		32		362		33
	Net loss	354		40		236		32		362		33
	Prior service cost	2		1		3		1		5		2
	Prior service cost	2		1		3		1		5		2
		356		41		239		33		367		35
		356		41		239		33		367		35
Schedule of the pre-tax amounts recognized in OCI	Pre-tax amounts recognized in OCI were as follows:


		2014				2013				2012
	at December 31	Pension		Other Post-		Pension		Other Post-		Pension		Other Post-
	at December 31	Benefits		Retirement		Benefits		Retirement		Benefits		Retirement
	(millions of Canadian dollars)			Benefits				Benefits				Benefits

	Amortization of net loss from AOCI to OCI	(21	)	(2	)	(30	)	(2	)	(19	)	(1	)
	Amortization of prior service costs from AOCI to OCI	(2	)	—		(2	)	—		(2	)	—
	Amortization of prior service costs from AOCI to OCI	(2	)	—		(2	)	—		(2	)	—
	Funded status adjustment	137		9		(96	)	—		99		5
	Funded status adjustment	137		9		(96	)	—		99		5
		114		7		(128	)	(2	)	78		4
		114		7		(128	)	(2	)	78		4

RISK_MANAGEMENT_AND_FINANCIAL_1

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative financial instruments
Schedule of the carrying and fair values of non-derivative financial instruments	The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts equal fair value, and would be classified in Level II of the fair value hierarchy:


		2014						2013
	at December 31	Carrying			Fair			Carrying			Fair
	(millions of Canadian dollars)	Amount			Value			Amount			Value

	Notes receivable and other1	213			263			226			269

	Available for sale assets2	62			62			47			47

	Current and Long-Term Debt3,4 (Note 15)	(24,757	)		(28,713	)		(22,865	)		(26,134	)
	Junior Subordinated Notes (Note 17)	(1,160	)		(1,157	)		(1,063	)		(1,093	)
		(25,642	)		(29,545	)		(23,655	)		(26,911	)

	1	Notes receivable are included in Other Current Assets and Intangible and Other Assets on the Consolidated Balance Sheet.

	2	Available for sale assets are included in Intangible and Other Assets on the Consolidated Balance Sheet.

	3	Long-Term Debt is recorded at amortized cost, except for US$400 million (2013 - US$200 million) that is attributed to hedged risk and recorded at fair value.

	4	Consolidated Net Income in 2014 included losses of $3 million (2013 - losses of $5 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$400 million of Long-Term Debt at December 31, 2014 (2013 - US$200 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.
Schedule of fair value of the derivative financial instruments in the Company's Balance Sheet	The balance sheet classification of the fair value of the derivative instruments is as follows:


	at December 31	2014			2013
	(millions of Canadian dollars)

	Other Current Assets (Note 5)	409			395

	Intangible and Other Assets (Note 11)	93			112

	Accounts Payable and Other (Note 13)	(749	)		(357	)
	Other Long-Term Liabilities (Note 14)	(411	)		(255	)
		(658	)		(105	)
Schedule of components of OCI related to derivates in cash flow hedging relationships	The following table presents the components of OCI (Note 21) related to derivatives in cash flow hedging relationships:


	year ended December 31	2014			2013
	(millions of Canadian dollars, pre-tax)

	Change in fair value of derivative instruments recognized in OCI (effective portion)1
	Power	(126	)		117

	Natural Gas	(2	)		(1	)
	Foreign Exchange	10			5

		(118	)		121

	Reclassification of (losses)/gains on derivative instruments from AOCI to Net Income (effective portion)1
	Power2	(114	)		40

	Natural Gas2	3			4

	Interest3	16			16

		(95	)		60

	(Losses)/gains on derivative instruments recognized in Net Income (ineffective portion)
	Power	(13	)		8

		(13	)		8


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

	2	Reported within Energy 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, 2014	Gross derivative instruments presented on the balance sheet			Amounts available for offset1			Net amounts
	(millions of Canadian dollars)

	Derivative - Asset
	Power	419			(330	)		89

	Natural gas	69			(57	)		12

	Foreign exchange	7			(7	)		—

	Interest	7			(1	)		6

		502			(395	)		107

	Derivative - Liability
	Power	(554	)		330			(224	)

	Natural gas	(103	)		57			(46	)

	Foreign exchange	(497	)		7			(490	)

	Interest	(6	)		1			(5	)

		(1,160	)		395			(765	)


	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, 2013:


	at December 31, 2013	Gross derivative instruments presented on the balance sheet			Amounts available for offset1			Net amounts
	(millions of Canadian dollars)

	Derivative - Asset
	Power	415			(277	)		138

	Natural gas	73			(61	)		12

	Foreign exchange	5			(5	)		—

	Interest	14			(2	)		12

		507			(345	)		162

	Derivative - Liability
	Power	(302	)		277			(25	)

	Natural gas	(72	)		61			(11	)

	Foreign exchange	(230	)		5			(225	)

	Interest	(8	)		2			(6	)

		(612	)		345			(267	)


	1	Amounts available for offset do not include cash collateral pledged or received.
Schedule of offsetting liabilities	The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2013:


	at December 31, 2013	Gross derivative instruments presented on the balance sheet			Amounts available for offset1			Net amounts
	(millions of Canadian dollars)

	Derivative - Asset
	Power	415			(277	)		138

	Natural gas	73			(61	)		12

	Foreign exchange	5			(5	)		—

	Interest	14			(2	)		12

		507			(345	)		162

	Derivative - Liability
	Power	(302	)		277			(25	)

	Natural gas	(72	)		61			(11	)

	Foreign exchange	(230	)		5			(225	)

	Interest	(8	)		2			(6	)

		(612	)		345			(267	)


	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:


	at December 31, 2014	Gross derivative instruments presented on the balance sheet			Amounts available for offset1			Net amounts
	(millions of Canadian dollars)

	Derivative - Asset
	Power	419			(330	)		89

	Natural gas	69			(57	)		12

	Foreign exchange	7			(7	)		—

	Interest	7			(1	)		6

		502			(395	)		107

	Derivative - Liability
	Power	(554	)		330			(224	)

	Natural gas	(103	)		57			(46	)

	Foreign exchange	(497	)		7			(490	)

	Interest	(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 the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions	The fair value of the Company's 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			Significant other observable inputs Level II1			Significant unobservable inputs			Total
	(millions of Canadian dollars, pre-tax)	Level I1						Level III1

	Derivative Instrument Assets:
	Power commodity contracts	—			417			2			419

	Natural gas commodity contracts	40			24			5			69

	Foreign exchange contracts	—			7			—			7

	Interest rate contracts	—			7			—			7

	Derivative Instrument Liabilities:
	Power commodity contracts	—			(551	)		(3	)		(554	)

	Natural gas commodity contracts	(86	)		(17	)		—			(103	)

	Foreign exchange contracts	—			(497	)		—			(497	)

	Interest rate contracts	—			(6	)		—			(6	)

	Non-Derivative Financial Instruments:
	Available for sale assets	—			62			—			62

		(46	)		(554	)		4			(596	)


	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 fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2013, are categorized as follows:


	at December 31, 2013	Quoted prices in active markets			Significant other observable inputs Level II1			Significant unobservable inputs			Total
	(millions of Canadian dollars, pre-tax)	Level I1						Level III1

	Derivative Instrument Assets:
	Power commodity contracts	—			411			4			415

	Natural gas commodity contracts	48			25			—			73

	Foreign exchange contracts	—			5			—			5

	Interest rate contracts	—			14			—			14

	Derivative Instrument Liabilities:
	Power commodity contracts	—			(299	)		(3	)		(302	)

	Natural gas commodity contracts	(50	)		(22	)		—			(72	)

	Foreign exchange contracts	—			(230	)		—			(230	)

	Interest rate contracts	—			(8	)		—			(8	)

	Non-Derivative Financial Instruments:
	Available for sale assets	—			47			—			47

		(2	)		(57	)		1			(58	)


	1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2013
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 dollars, pre-tax)	2014			2013


	Balance at beginning of year	1			(2	)

	Transfers out of Level III	—			(2	)

	Total gains/(losses) included in Net Income	3			(1	)

	Total gains included in OCI	—			6

	Balance at end of year1	4			1


	1	Energy Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2014 of $3 million (2013 – nil).
Derivative financial instrument, excluding net investment hedges
Derivative financial instruments
Schedule of fair values and notional or principal amounts for the derivatives	The following summary does not include hedges of the net investment in foreign operations.


	(millions of Canadian dollars, unless noted otherwise)	Power				Natural				Foreign				Interest
						Gas				Exchange

	Derivative Instruments Held for Trading1
	Fair Values2
	Assets		$265				$73				$—				$8

	Liabilities		($280	)			($72	)			($12	)			($7	)

	Notional Values
	Volumes3
	Purchases	29,301				88				—				—

	Sales	28,534				60				—				—

	Canadian dollars	—				—				—				400

	U.S. dollars	—				—				US 1,015				US 100

	Net unrealized gains/(losses) in the year4		$19				$17				($10	)			$—

	Net realized losses in the year4		($49	)			($13	)			($9	)			$—

	Maturity dates	2014-2017				2014-2016				2014				2014-2016


	Derivative Instruments in Hedging Relationships5,6
	Fair Values2
	Assets		$150				$—				$—				$6

	Liabilities		($22	)			$—				($1	)			($1	)

	Notional Values
	Volumes3
	Purchases	9,758				—				—				—

	Sales	6,906				—				—				—

	U.S. dollars	—				—				US 16				US 350

	Net realized (losses)/gains in the year4		($19	)			($2	)			$—				$5

	Maturity dates	2014-2018				—				2014				2015-2018


	1	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.

	2	Fair value equals carrying value.

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

	4	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in Energy 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. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Energy Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

	5	All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $5 million and a notional amount of US$200 million. In 2013, net realized gains on fair value hedges were $6 million and were included in Interest Expense. In 2013, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

	6	In 2013, 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.
	The following summary does not include hedges of the net investment in foreign operations.


	(millions of Canadian dollars, unless noted otherwise)	Power				Natural				Foreign				Interest
						Gas				Exchange

Derivative Instruments Held for Trading1
Fair Values2
Assets		$362				$69				$1				$4

Liabilities		($391	)			($103	)			($32	)			($4	)

Notional Values
Volumes3
Purchases	42,097				60				—				—

Sales	35,452				38				—				—

U.S. dollars	—				—				US 1,374				US 100

Net unrealized losses in the year4		($5	)			($35	)			($20	)			$—

Net realized (losses)/gains in the year4		($39	)			$11				($28	)			$—

Maturity dates	2015-2019				2015-2020				2015				2015-2016


Derivative Instruments in Hedging Relationships5,6
Fair Values2
Assets		$57				$—				$—				$3

Liabilities		($163	)			$—				$—				($2	)

Notional Values
Volumes3
Purchases	11,120				—				—				—

Sales	3,977				—				—				—

U.S. dollars	—				—				—				US 550

Net realized gains in the year4		$130				$—				$—				$4

Maturity dates	2015-2019				—				—				2015-2018


1	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.

2	Fair value equals carrying value.

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

4	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in Energy 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. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Energy Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

5	All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $3 million and a notional amount of US$400 million. In 2014, net realized gains on fair value hedges were $7 million and were included in Interest Expense. In 2014, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

6	In 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.
Designated as a net investment hedge
Derivative financial instruments
Schedule of the carrying and fair values of non-derivative financial instruments

	at December 31		2014		2013
	(millions of Canadian dollars, unless noted otherwise)

	Carrying value		17,000 (US 14,700)		14,200 (US 13,400)
	Fair value		19,000 (US 16,400)		16,000 (US 15,000)
Schedule of fair values and notional or principal amounts for the derivatives

		2014							2013
	at December 31	Fair			Notional or				Fair			Notional or
		Value1			Principal				Value1			Principal
	(millions of Canadian dollars, unless noted otherwise)				Amount							Amount

	U.S. dollar cross-currency interest rate swaps (maturing 2015 to 2019)2	(431	)		US	2,900			(201	)		US	3,800

	U.S. dollar foreign exchange forward contracts (maturing 2015)	(28	)		US	1,400			(11	)		US	850

		(459	)		US	4,300			(212	)		US	4,650


	1	Fair values approximate carrying values.

	2	In 2014, net realized gains of $21 million (2013 – gains of $29 million) related to the interest component of cross-currency swap settlements are included in Interest Expense.
Schedule of fair value of the derivative financial instruments in the Company's Balance Sheet	The balance sheet classification of the fair value of derivatives used to hedge the Company’s net investment in foreign operations is as follows:


	at December 31	2014			2013
	(millions of Canadian dollars)

	Other Current Assets (Note 5)	5			5

	Intangible and Other Assets (Note 11)	1			—

	Accounts Payable and Other (Note 13)	(155	)		(50	)
	Other Long-Term Liabilities (Note 14)	(310	)		(167	)
		(459	)		(212	)

CHANGES_IN_OPERATING_WORKING_C1

CHANGES IN OPERATING WORKING CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2014
CHANGES IN OPERATING WORKING CAPITAL
Schedule of changes in operating working capital

	year ended December 31	2014		2013		2012
	(millions of Canadian dollars)

	(Increase)/decrease in Accounts Receivable	(189	)	(54	)	67

	(Increase)/decrease in Inventories	(28	)	(30	)	27

	(Increase)/decrease in Other Current Assets	(385	)	40		66

	Increase/(decrease) in Accounts Payable and Other	377		(290	)	127

	Increase in Accrued Interest	36		8		—

	(Increase)/Decrease in Operating Working Capital	(189	)	(326	)	287

COMMITMENTS_CONTINGENCIES_AND_1

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of future annual payments, net of sub-lease receipts, under the Company's operating leases for various premises, services and equipment	Future annual payments, net of sub-lease receipts, under the Company's operating leases for various premises, services and equipment are approximately as follows:


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

	2015	348		48		300

	2016	335		47		288

	2017	335		48		287

	2018	250		27		223

	2019	232		23		209

	2020 and thereafter	407		20		387

		1,907		213		1,694

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:


			2014				2013
	year ended December 31	Term	Potential Exposure1		Carrying Value		Potential Exposure1	Carrying Value
	(millions of Canadian dollars)

	Bruce Power	Ranging to 20192	634		6		740	8

	Other jointly owned entities	Ranging to 2040	104		14		51	10

			738		20		791	18


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

	2	Except for one guarantee with no termination date.

DESCRIPTION_OF_TRANSCANADAS_BU1

DESCRIPTION OF TRANSCANADA'S BUSINESS (Details)	12 Months Ended
	Dec. 31, 2014
	segment
	plant
	facility
	Bcf
	km
	mi
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of business segments in which the entity operates	3
Public Utilities Property, Plant and Equipment, Regulated Natural Gas Pipelines, in kilometers	68,000
Public Utilities, Property, Plant and Equipment, Regulated Natural Gas Pipelines, in Miles	42,000
Public Utilities, Property, Plant and Equipment, Regulated Natural Gas Storage Facilities, in Billion Cubic Feet	400
Public Utilities, Property, Plant and Equipment, Crude Oil Pipelines, in Kilometers	4,250
Public Utilities, Property, Plant and Equipment, Crude Oil Pipelines, in Miles	2,600
Public Utilities, Property, Plant and Equipment, Electrical Power Generation Plants	19
Public Utilities, Property, Plant and Equipment, Number of Non-Regulated Natural Gas Storage Facilities	2

ACCOUNTING_POLICIES_Details

ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2014
	level
Annual review for goodwill impairment
Number of levels below operating segments level considered for measuring reporting unit level	1
Employee Post-Retirement Benefits
Moving average period of basis used to determine expected return on plan assets	5 years
Corporate \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	3.00%
Corporate \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	20.00%
Natural Gas Pipelines \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	1.00%
Natural Gas Pipelines \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	6.00%
Natural Gas Pipelines \| Compression \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	1.00%
Natural Gas Pipelines \| Compression \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	6.00%
Liquids Pipelines \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.00%
Liquids Pipelines \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.50%
Liquids Pipelines \| Pumping equipment \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.00%
Liquids Pipelines \| Pumping equipment \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.50%
Energy \| Power generation and natural gas storage plant, equipment and structures \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.00%
Energy \| Power generation and natural gas storage plant, equipment and structures \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	20.00%

SEGMENTED_INFORMATION_Details

SEGMENTED INFORMATION (Details) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segmented information
Revenues	10,185	8,797	8,007
Income from Equity Investments (Note 8)	522	597	257
Plant Operating Costs and Other	-2,973	-2,674	-2,577
Commodity Purchases Resold	-1,836	-1,317	-1,049
Property Taxes	-473	-445	-434
Depreciation and Amortization	-1,611	-1,485	-1,375
Gain on Sale of Assets	117	0	0
Segment Earnings	3,931	3,473	2,829
Interest Expense	-1,198	-985	-976
Interest Income and Other	91	34	85
Income before Income Taxes	2,824	2,522	1,938
Income Tax Expense	-831	-611	-466
Net Income	1,993	1,911	1,472
Net Income Attributable to Non-Controlling Interests	-153	-125	-118
Net Income Attributable to Controlling Interests	1,840	1,786	1,354
Preferred Share Dividends	-97	-74	-55
Net Income Attributable to Common Shares	1,743	1,712	1,299
Capital Spending
Capital Expenditures	3,550	4,264	2,595
Projects Under Development	807	488	3
Payments to Acquire Productive Assets	4,357	4,752	2,598
Total Assets	58,947	53,898	48,333
GEOGRAPHIC INFORMATION
Revenues	10,185	8,797	8,007
Plant, Property and Equipment (Note 7)	41,774	37,606
Canada
GEOGRAPHIC INFORMATION
Plant, Property and Equipment (Note 7)	19,191	18,462
Canada - domestic
Segmented information
Revenues	4,021	4,659	3,527
GEOGRAPHIC INFORMATION
Revenues	4,021	4,659	3,527
Canada - export
Segmented information
Revenues	1,314	997	1,121
GEOGRAPHIC INFORMATION
Revenues	1,314	997	1,121
United States
Segmented information
Revenues	4,653	3,029	3,252
GEOGRAPHIC INFORMATION
Revenues	4,653	3,029	3,252
Plant, Property and Equipment (Note 7)	20,098	17,570
Mexico
Segmented information
Revenues	197	112	107
GEOGRAPHIC INFORMATION
Revenues	197	112	107
Plant, Property and Equipment (Note 7)	2,485	1,574
Corporate
Segmented information
Plant Operating Costs and Other	-127	-108	-97
Depreciation and Amortization	-23	-16	-14
Gain on Sale of Assets	0
Segment Earnings	-150	-124	-111
Capital Spending
Capital Expenditures	46	50	37
Projects Under Development	0	0	0
Payments to Acquire Productive Assets	46	50	37
Total Assets	1,531	1,733	1,481
GEOGRAPHIC INFORMATION
Plant, Property and Equipment (Note 7)	152	130
Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	4,913	4,497	4,264
Income from Equity Investments (Note 8)	163	145	157
Plant Operating Costs and Other	-1,501	-1,405	-1,365
Property Taxes	-334	-329	-315
Depreciation and Amortization	-1,063	-1,027	-933
Gain on Sale of Assets	9
Segment Earnings	2,187	1,881	1,808
Capital Spending
Capital Expenditures	1,768	1,776	1,389
Projects Under Development	368	245	0
Payments to Acquire Productive Assets	2,136	2,021	1,389
Total Assets	27,103	25,165	23,210
GEOGRAPHIC INFORMATION
Revenues	4,913	4,497	4,264
Plant, Property and Equipment (Note 7)	20,204	18,704
Liquids Pipelines \| Operating segments
Segmented information
Revenues	1,547	1,124	1,039
Plant Operating Costs and Other	-426	-328	-296
Property Taxes	-62	-44	-45
Depreciation and Amortization	-216	-149	-145
Gain on Sale of Assets	0
Segment Earnings	843	603	553
Capital Spending
Capital Expenditures	1,530	2,286	1,145
Projects Under Development	439	243	3
Payments to Acquire Productive Assets	1,969	2,529	1,148
Total Assets	16,116	13,253	10,485
GEOGRAPHIC INFORMATION
Revenues	1,547	1,124	1,039
Plant, Property and Equipment (Note 7)	14,928	12,740
Energy \| Operating segments
Segmented information
Revenues	3,725	3,176	2,704
Income from Equity Investments (Note 8)	359	452	100
Plant Operating Costs and Other	-919	-833	-819
Commodity Purchases Resold	-1,836	-1,317	-1,049
Property Taxes	-77	-72	-74
Depreciation and Amortization	-309	-293	-283
Gain on Sale of Assets	108
Segment Earnings	1,051	1,113	579
Capital Spending
Capital Expenditures	206	152	24
Projects Under Development	0	0	0
Payments to Acquire Productive Assets	206	152	24
Total Assets	14,197	13,747	13,157
GEOGRAPHIC INFORMATION
Revenues	3,725	3,176	2,704
Plant, Property and Equipment (Note 7)	6,490	6,032

OTHER_CURRENT_ASSETS_Details

OTHER CURRENT ASSETS (Details) (CAD)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Other Assets [Abstract]
Deferred income tax assets (Note 16)	427	119
Cash held as collateral	423	42
Fair value of derivative contracts (Note 23)	409	395
Other	171	164
Regulatory Assets (Note 9)	16	42
Assets held for sale (Note 6)	0	85
Other Assets, Current	1,446	847

ASSETS_HELD_FOR_SALE_Details

ASSETS HELD FOR SALE (Details) (CAD)	0 Months Ended
In Millions, unless otherwise specified	Apr. 15, 2014	Dec. 31, 2014	Dec. 31, 2013
Assets Held for Sale
Cash and Cash Equivalents			1
Accounts Receivable			12
Inventories			11
Plant, Property and Equipment			61
Total Assets Held for Sale (included in Other Current Assets, Note 5)		0	85
Liabilities Related to Assets Held for Sale
Accounts Payable and Other			4
Other Long-Term Liabilities			1
Total Liabilities Related to Assets Held for Sale (included in Accounts Payable and Other, Note 13)		0	5
Proceeds from Sale of Other Assets	190
Gain (Loss) on Disposition of Other Assets, Gross	108
Gain (Loss) on Disposition of Other Assets	99

PLANT_PROPERTY_AND_EQUIPMENT_D

PLANT, PROPERTY AND EQUIPMENT (Details) (CAD)	12 Months Ended
PLANT, PROPERTY AND EQUIPMENT (Details) (CAD)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Plant, property and equipment
Cost	61,337,000,000	55,457,000,000
Accumulated Depreciation	19,563,000,000	17,851,000,000
Net Book Value	41,774,000,000	37,606,000,000
Mexico
Plant, property and equipment
Net Book Value	2,485,000,000	1,574,000,000
Liquids Pipelines \| Keystone XL \| Under construction
Plant, property and equipment
Amount of construction in progress, which remains subject to regulatory approvals	3,200,000,000	2,600,000,000
Energy \| Facilities under PPAs
Plant, property and equipment
Cost	695,000,000	640,000,000
Accumulated Depreciation	103,000,000	78,000,000
Revenues recognized through the sale of electricity	81,000,000	78,000,000	73,000,000
Operating segments \| Natural Gas Pipelines
Plant, property and equipment
Cost	37,076,000,000	34,427,000,000
Accumulated Depreciation	16,872,000,000	15,723,000,000
Net Book Value	20,204,000,000	18,704,000,000
Operating segments \| Natural Gas Pipelines \| Pipeline \| Mexico
Plant, property and equipment
Cost	1,518,000,000	641,000,000
Accumulated Depreciation	130,000,000	90,000,000
Net Book Value	1,388,000,000	551,000,000
Operating segments \| Natural Gas Pipelines \| Canadian Mainline
Plant, property and equipment
Cost	13,061,000,000	12,856,000,000
Accumulated Depreciation	7,992,000,000	7,592,000,000
Net Book Value	5,069,000,000	5,264,000,000
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Pipeline
Plant, property and equipment
Cost	9,045,000,000	8,970,000,000
Accumulated Depreciation	5,712,000,000	5,457,000,000
Net Book Value	3,333,000,000	3,513,000,000
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Compression
Plant, property and equipment
Cost	3,423,000,000	3,392,000,000
Accumulated Depreciation	2,100,000,000	1,961,000,000
Net Book Value	1,323,000,000	1,431,000,000
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Metering and other
Plant, property and equipment
Cost	458,000,000	409,000,000
Accumulated Depreciation	180,000,000	174,000,000
Net Book Value	278,000,000	235,000,000
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	12,926,000,000	12,771,000,000
Accumulated Depreciation	7,992,000,000	7,592,000,000
Net Book Value	4,934,000,000	5,179,000,000
Operating segments \| Natural Gas Pipelines \| Canadian Mainline \| Under construction
Plant, property and equipment
Cost	135,000,000	85,000,000
Net Book Value	135,000,000	85,000,000
Operating segments \| Natural Gas Pipelines \| NGTL System
Plant, property and equipment
Cost	11,685,000,000	11,088,000,000
Accumulated Depreciation	5,383,000,000	5,081,000,000
Net Book Value	6,302,000,000	6,007,000,000
Operating segments \| Natural Gas Pipelines \| NGTL System \| Pipeline
Plant, property and equipment
Cost	8,185,000,000	7,813,000,000
Accumulated Depreciation	3,619,000,000	3,410,000,000
Net Book Value	4,566,000,000	4,403,000,000
Operating segments \| Natural Gas Pipelines \| NGTL System \| Compression
Plant, property and equipment
Cost	2,055,000,000	2,038,000,000
Accumulated Depreciation	1,318,000,000	1,253,000,000
Net Book Value	737,000,000	785,000,000
Operating segments \| Natural Gas Pipelines \| NGTL System \| Metering and other
Plant, property and equipment
Cost	1,032,000,000	947,000,000
Accumulated Depreciation	446,000,000	418,000,000
Net Book Value	586,000,000	529,000,000
Operating segments \| Natural Gas Pipelines \| NGTL System \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	11,272,000,000	10,798,000,000
Accumulated Depreciation	5,383,000,000	5,081,000,000
Net Book Value	5,889,000,000	5,717,000,000
Operating segments \| Natural Gas Pipelines \| NGTL System \| Under construction
Plant, property and equipment
Cost	413,000,000	290,000,000
Net Book Value	413,000,000	290,000,000
Operating segments \| Natural Gas Pipelines \| ANR
Plant, property and equipment
Cost	2,560,000,000	2,159,000,000
Accumulated Depreciation	297,000,000	231,000,000
Net Book Value	2,263,000,000	1,928,000,000
Operating segments \| Natural Gas Pipelines \| ANR \| Pipeline
Plant, property and equipment
Cost	1,087,000,000	922,000,000
Accumulated Depreciation	85,000,000	59,000,000
Net Book Value	1,002,000,000	863,000,000
Operating segments \| Natural Gas Pipelines \| ANR \| Compression
Plant, property and equipment
Cost	741,000,000	635,000,000
Accumulated Depreciation	102,000,000	81,000,000
Net Book Value	639,000,000	554,000,000
Operating segments \| Natural Gas Pipelines \| ANR \| Metering and other
Plant, property and equipment
Cost	617,000,000	535,000,000
Accumulated Depreciation	110,000,000	91,000,000
Net Book Value	507,000,000	444,000,000
Operating segments \| Natural Gas Pipelines \| ANR \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	2,445,000,000	2,092,000,000
Accumulated Depreciation	297,000,000	231,000,000
Net Book Value	2,148,000,000	1,861,000,000
Operating segments \| Natural Gas Pipelines \| ANR \| Under construction
Plant, property and equipment
Cost	115,000,000	67,000,000
Net Book Value	115,000,000	67,000,000
Operating segments \| Natural Gas Pipelines \| Other Natural Gas Pipelines
Plant, property and equipment
Cost	9,770,000,000	8,324,000,000
Accumulated Depreciation	3,200,000,000	2,819,000,000
Net Book Value	6,570,000,000	5,505,000,000
Operating segments \| Natural Gas Pipelines \| Other Natural Gas Pipelines \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	8,638,000,000	7,277,000,000
Accumulated Depreciation	3,200,000,000	2,819,000,000
Net Book Value	5,438,000,000	4,458,000,000
Operating segments \| Natural Gas Pipelines \| Other Natural Gas Pipelines \| Under construction
Plant, property and equipment
Cost	1,132,000,000	1,047,000,000
Net Book Value	1,132,000,000	1,047,000,000
Operating segments \| Natural Gas Pipelines \| GTN \| Pipeline
Plant, property and equipment
Cost	1,842,000,000	1,685,000,000
Accumulated Depreciation	588,000,000	488,000,000
Net Book Value	1,254,000,000	1,197,000,000
Operating segments \| Natural Gas Pipelines \| Great Lakes \| Pipeline
Plant, property and equipment
Cost	1,807,000,000	1,650,000,000
Accumulated Depreciation	939,000,000	833,000,000
Net Book Value	868,000,000	817,000,000
Operating segments \| Natural Gas Pipelines \| Foothills \| Pipeline
Plant, property and equipment
Cost	1,671,000,000	1,649,000,000
Accumulated Depreciation	1,180,000,000	1,120,000,000
Net Book Value	491,000,000	529,000,000
Operating segments \| Natural Gas Pipelines \| Other \| Pipeline
Plant, property and equipment
Cost	1,800,000,000	1,652,000,000
Accumulated Depreciation	363,000,000	288,000,000
Net Book Value	1,437,000,000	1,364,000,000
Operating segments \| Liquids Pipelines
Plant, property and equipment
Cost	15,615,000,000	13,179,000,000
Accumulated Depreciation	687,000,000	439,000,000
Net Book Value	14,928,000,000	12,740,000,000
Operating segments \| Liquids Pipelines \| Under construction
Plant, property and equipment
Cost	4,438,000,000	6,020,000,000
Net Book Value	4,438,000,000	6,020,000,000
Operating segments \| Liquids Pipelines \| Keystone \| Pipeline
Plant, property and equipment
Cost	7,931,000,000	5,079,000,000
Accumulated Depreciation	463,000,000	286,000,000
Net Book Value	7,468,000,000	4,793,000,000
Operating segments \| Liquids Pipelines \| Keystone \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	11,177,000,000	7,159,000,000
Accumulated Depreciation	687,000,000	439,000,000
Net Book Value	10,490,000,000	6,720,000,000
Operating segments \| Liquids Pipelines \| Keystone \| Pumping equipment
Plant, property and equipment
Cost	964,000,000	1,118,000,000
Accumulated Depreciation	80,000,000	82,000,000
Net Book Value	884,000,000	1,036,000,000
Operating segments \| Liquids Pipelines \| Keystone \| Tanks and other
Plant, property and equipment
Cost	2,282,000,000	962,000,000
Accumulated Depreciation	144,000,000	71,000,000
Net Book Value	2,138,000,000	891,000,000
Operating segments \| Energy
Plant, property and equipment
Cost	8,414,000,000	7,660,000,000
Accumulated Depreciation	1,924,000,000	1,628,000,000
Net Book Value	6,490,000,000	6,032,000,000
Operating segments \| Energy \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	8,265,000,000	7,606,000,000
Accumulated Depreciation	1,924,000,000	1,628,000,000
Net Book Value	6,341,000,000	5,978,000,000
Operating segments \| Energy \| Under construction
Plant, property and equipment
Cost	149,000,000	54,000,000
Net Book Value	149,000,000	54,000,000
Operating segments \| Energy \| Natural Gas b Ravenswood
Plant, property and equipment
Cost	2,140,000,000	1,966,000,000
Accumulated Depreciation	476,000,000	377,000,000
Net Book Value	1,664,000,000	1,589,000,000
Operating segments \| Energy \| Natural Gas - Other
Plant, property and equipment
Cost	3,214,000,000	3,061,000,000
Accumulated Depreciation	971,000,000	846,000,000
Net Book Value	2,243,000,000	2,215,000,000
Operating segments \| Energy \| Hydro
Plant, property and equipment
Cost	736,000,000	673,000,000
Accumulated Depreciation	156,000,000	126,000,000
Net Book Value	580,000,000	547,000,000
Operating segments \| Energy \| Wind
Plant, property and equipment
Cost	970,000,000	946,000,000
Accumulated Depreciation	190,000,000	155,000,000
Net Book Value	780,000,000	791,000,000
Operating segments \| Energy \| Natural Gas Storage
Plant, property and equipment
Cost	653,000,000	677,000,000
Accumulated Depreciation	99,000,000	92,000,000
Net Book Value	554,000,000	585,000,000
Operating segments \| Energy \| Solar
Plant, property and equipment
Cost	488,000,000	226,000,000
Accumulated Depreciation	13,000,000	2,000,000
Net Book Value	475,000,000	224,000,000
Number of facilities acquired	4
Operating segments \| Energy \| Other
Plant, property and equipment
Cost	64,000,000	57,000,000
Accumulated Depreciation	19,000,000	30,000,000
Net Book Value	45,000,000	27,000,000
Corporate
Plant, property and equipment
Cost	232,000,000	191,000,000
Accumulated Depreciation	80,000,000	61,000,000
Net Book Value	152,000,000	130,000,000

EQUITY_INVESTMENTS_Details

EQUITY INVESTMENTS (Details)

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

31-May-13

Apr. 30, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

CAD

TC PipeLines, LP

Northern Border

Bruce Power

CrossAlta

Natural Gas Pipelines

Energy

Liquids Pipelines

USD ($)

CAD

Northern Border

Iroquois

TQM

Other

Bruce A

Bruce B

ASTC Power Partnership

Portlands Energy

Grand Rapids

CAD

TC PipeLines, LP

CAD

Equity Investments

Ownership interest (as a percent)

40.00%

60.00%

14.20%

14.50%

16.70%

50.00%

44.50%

50.00%

48.90%

31.60%

50.00%

Income/(Loss) from Equity Investments

522

597

257

209

202

-149

105

108

163

110

Equity Investments (Note 8)

5,598

5,759

587

557

210

188

3,944

3,988

377

335

343

240

TransCanada ownership (as a percent)

28.30%

28.90%

33.30%

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

117

118

776

820

Ownership interest after acquisition (as a percent)

100.00%

Distributions received from equity investments

726

725

436

Returns of capital

147

120

Undistributed earnings

551

754

883

EQUITY_INVESTMENTS_Summarized_

EQUITY INVESTMENTS (Summarized Financial Information of Equity Investments) (Details) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income
Revenues	4,814	4,989	3,860
Operating and Other Expenses	-3,489	-3,536	-3,090
Net Income	1,264	1,390	717
Net Income attributable to TransCanada	522	597	257
Balance Sheet
Current assets	1,412	1,500
Non current assets	12,260	12,158
Current liabilities	-1,067	-1,117
Non current liabilities	-3,255	-2,507

RATEREGULATED_BUSINESSES_Detai

RATE-REGULATED BUSINESSES (Details) (CAD)	0 Months Ended	12 Months Ended		1 Months Ended		12 Months Ended	1 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Nov. 28, 2014	Dec. 31, 2014	Dec. 31, 2013	Jan. 31, 2011	Mar. 31, 2013	Dec. 31, 2012	Nov. 30, 2013	Nov. 01, 2012
Rate-regulated business
Payment to Reduce Revenue Requirement, Net of Tax	20
Fixed Toll Term, Period	6 years
Composite depreciation rate		3.12%	3.05%
U.S. \| Bison LLC
Rate-regulated business
Period of operation after which cost and revenue study is required to be filed				3 years
Canadian Mainline \| Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity (as a percent)	10.10%				11.50%	8.08%
Deemed common equity (as a percent)	40.00%				40.00%	40.00%
Term of regulatory decisions			5 years		5 years
NGTL System \| Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity (as a percent)						9.70%	10.10%
Deemed common equity (as a percent)						40.00%	40.00%
ANR \| U.S. \| TC Offshore LLC
Rate-regulated business
Period of operation after which cost and revenue study is required to be filed								3 years

RATEREGULATED_BUSINESSES_Detai1

RATE-REGULATED BUSINESSES (Details 2) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets
Total regulatory assets	1,313	1,777
Regulatory Assets (Note 9)	16	42
Regulatory assets, noncurrent	1,297	1,735
Regulatory Liabilities
Total regulatory liabilities	293	236
Less: Current portion included in Accounts Payable and Other	30	7
Regulated liabilities, noncurrent	263	229
Foreign exchange on long-term debt
Regulatory Liabilities
Total regulatory liabilities	42	84
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Total regulatory liabilities	21	5
Remaining Recovery/Settlement Period	1 year
Postretirement Benefit Costs
Regulatory Liabilities
Total regulatory liabilities	117	104
Long-Term Adjustment Account
Regulatory Liabilities
Total regulatory liabilities	64	0
Remaining Recovery/Settlement Period	44 years
Other
Regulatory Liabilities
Total regulatory liabilities	49	43
Deferred income taxes
Regulatory Assets
Total regulatory assets	1,001	1,149
Operating and debt-service regulatory assets
Regulatory Assets
Total regulatory assets	4	16
Remaining Recovery/ Settlement Period	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	28	76	-50
Pension and Other Postretirement Plans Costs
Regulatory Assets
Total regulatory assets	236	190
Pension and Other Postretirement Plans Costs \| Pension and Other Postretirement Plans 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	46	171	61
Long-Term Adjustment Account
Regulatory Assets
Total regulatory assets	0	354
Remaining Recovery/ Settlement Period	31 years
Other
Regulatory Assets
Total regulatory assets	72	68
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	2	2	66
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	13	16	8
Minimum \| Foreign exchange on long-term debt
Regulatory Liabilities
Remaining Recovery/Settlement Period	1 year
Maximum \| Foreign exchange on long-term debt
Regulatory Liabilities
Remaining Recovery/Settlement Period	15 years

RATEREGULATED_BUSINESSES_Detai2

RATE-REGULATED BUSINESSES (Details 3) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Regulated Operations [Abstract]
Allowance for Funds Used During Construction	95	19	15

GOODWILL_Details

GOODWILL (Details) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Goodwill
Balance at the beginning of the period	3,696	3,458
Foreign exchange rate changes	338	238
Balance at the end of the period	4,034	3,696
Natural Gas Pipelines
Goodwill
Balance at the beginning of the period	2,816	2,635
Foreign exchange rate changes	258	181
Balance at the end of the period	3,074	2,816
Energy
Goodwill
Balance at the beginning of the period	880	823
Foreign exchange rate changes	80	57
Balance at the end of the period	960	880

INTANGIBLE_AND_OTHER_ASSETS_De

INTANGIBLE AND OTHER ASSETS (Details)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013
	CAD	CAD	CAD	USD ($)	USD ($)	Sheerness	Sheerness	Sundance A	Sundance A
						CAD	CAD	CAD	CAD
Goodwill and Intangible Assets Disclosure [Abstract]
Capital projects under development	1,286	571
PPAs	272	324				234	273	38	51
Deferred income tax assets and charges	180	225
Loans and advances	167	183
Fair value of derivative contracts	93	112
Employee post-retirement benefits	14	16
Other	692	524
Intangibles and Other Assets	2,704	1,955
Note receivable
Notes receivable	213	226		184	212
Interest rate on notes receivable	6.75%
Current portion of note receivable	46	43		40	40
Amount related to PPAs which are included in intangibles and other assets
Cost	810	810				585	585	225	225
Accumulated Amortization	538	486				351	312	187	174
Net Book Value	272	324				234	273	38	51
Amortization expense	52	52	52
Expected annual amortization expense
2015	52
2016	52
2017	52
2018	39
2019	39

NOTES_PAYABLE_Details

NOTES PAYABLE (Details)

Dec. 31, 2014

Dec. 31, 2013

Oct. 01, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

CAD

Short-term Debt [Member]

Notes payable

Revolving and demand credit facilities

Committed, syndicated, revolving, extendible credit facility

Demand credit facility

USD ($)

Canadian dollars

U.S. dollars

CAD

TransCanada PipeLines Limited

TCPL USA

TAIL

Canadian dollars

U.S. dollars

TransCanada Pipelines Limited and TransCanada Pipelines USA

Canadian dollars

CAD

USD ($)

CAD

USD ($)

CAD

TransCanada PipeLines Limited

TCPL USA

TAIL

CAD

TransCanada Pipelines Limited and TransCanada Pipelines USA

CAD

USD ($)

CAD

Notes payable

Outstanding December 31

2,467,000,000

1,842,000,000

$170,000,000

1,540,000,000

751,000,000

$800,000,000

927,000,000

$1,025,000,000

1,091,000,000

Weighted Average Interest Rate per Annum at December 31

1.20%

0.70%

0.30%

Unused Capacity

6,700,000,000

6,200,000,000

3,000,000,000

1,000,000,000

600,000,000

Maximum borrowing capacity

3,000,000,000

1,000,000,000

1,400,000,000

Cost to maintain the facility

6,000,000

4,000,000

2,000,000

1,000,000

ACCOUNTS_PAYABLE_AND_OTHER_Det

ACCOUNTS PAYABLE AND OTHER (Details) (CAD)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Payables and Accruals [Abstract]
Trade payables	1,624	866
Fair value of derivative contracts (Note 23)	749	357
Dividends payable	359	338
Deferred Income Tax Liabilities (Note 16)	4	26
Regulatory Liabilities (Note 9)	30	7
Liabilities related to assets held for sale (Note 6)	0	5
Other	130	556
Accounts payable and other	2,896	2,155

OTHER_LONGTERM_LIABILITIES_Det

OTHER LONG-TERM LIABILITIES (Details) (CAD)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred Costs, Noncurrent [Abstract]
Employee post-retirement benefit (Note 22)	444	244
Fair value of derivative contracts (Note 23)	411	255
Asset retirement obligations	98	83
Guarantees (Note 26)	15	18
Other	84	56
Other Long-Term Liabilities	1,052	656

LONGTERM_DEBT_AND_PRINCIPAL_RE

LONG-TERM DEBT AND PRINCIPAL REPAYMENTS (Details)

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

In Millions, unless otherwise specified

CAD

TransCanada PipeLines Limited

Nova Gas Transmission LTD

ANR Pipe Line Company

Gas Transmission Northwest Corporation

TC PipeLines, LP

Great Lakes Gas Transmission Limited Partnership

Tuscarora Gas Transmission Company

Portland Natural Gas Transmission System

Canadian dollars

U.S. dollars

Maximum

CAD

Debentures, Maturity Dates Between 2015 and 2020

Debentures, Maturity Date of 2021

Medium-term Notes

Senior Unsecured Notes

CAD

Debentures and Notes, Maturity Dates between 2016 and 2024

Debentures and Notes, Maturity Date of 2023

Medium-Term Notes, Maturity between 2025 and 2030

Medium-Term Notes, Maturity Date of 2026

Senior Unsecured Notes

CAD

Senior Unsecured Notes

Unsecured Debt

Unsecured Term Loan Facility

Senior Unsecured Notes

Secured Debt

TransCanada PipeLines Limited

Nova Gas Transmission LTD

TransCanada PipeLines Limited

Nova Gas Transmission LTD

ANR Pipe Line Company

Gas Transmission Northwest Corporation

TC PipeLines, LP

Great Lakes Gas Transmission Limited Partnership

Tuscarora Gas Transmission Company

Portland Natural Gas Transmission System

Canadian dollars

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

Debentures, Maturity Dates Between 2015 and 2020

Debentures and Notes, Maturity Dates between 2016 and 2024

Medium-Term Notes, Maturity between 2025 and 2030

Debentures and Notes

Debentures, Maturity Date of 2021

Debentures and Notes, Maturity Date of 2023

Medium-Term Notes, Maturity Date of 2026

Senior Unsecured Notes

Unsecured Debt

Unsecured Term Loan Facility

Senior Unsecured Notes

Secured Debt

Nova Gas Transmission LTD

CAD

USD ($)

Debentures and Notes

Debt Instrument [Line Items]

Current and Long-Term Debt, Outstanding December 31

24,757

22,865

20,916

19,125

749

874

$400

464

$400

425

4,048

4,799

$13,526

15,655

$12,276

13,027

1,099

1,129

325

378

$200

232

$200

213

504

$33

502

459

377

346

1,368

1,308

405

372

383

404

580

532

367

356

105

117

$432

$325

$350

$330

$380

$500

$316

$335

$20

$24

$90

$110

Interest Rate

5.70%

5.00%

8.90%

5.50%

4.70%

1.40%

7.80%

4.00%

6.10%

10.90%

11.50%

7.40%

9.90%

7.90%

7.50%

Long-term Debt, Current Maturities

1,797

973

Long-term Debt, Excluding Current Maturities

22,960

21,892

Long-Term Debt Issued with Retraction Provision

225

Debt Instrument, Redemption Price, Percentage

8.00%

Repayments of Long-term Debt [Abstract]

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

1,797

Long-term Debt, Maturities, Repayments of Principal in Year Two

2,225

Long-term Debt, Maturities, Repayments of Principal in Year Three

846

Long-term Debt, Maturities, Repayments of Principal in Year Four

1,766

Long-term Debt, Maturities, Repayments of Principal in Year Five

1,007

LONGTERM_DEBT_ISSUED_Details

LONG-TERM DEBT ISSUED (Details)	1 Months Ended
	Feb. 28, 2014	Oct. 31, 2013	Oct. 31, 2013	Jul. 31, 2013	Jul. 31, 2013	Jul. 31, 2013	Jan. 31, 2013	Aug. 31, 2012	Mar. 31, 2012	Oct. 31, 2014
	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TC PipeLines, LP
	4.63% senior unsecured notes, due March 2034	3.75% senior unsecured notes, due October 16, 2023	5.00% senior unsecured notes, due October 16, 2043	0.95% floating rate notes, maturing June 30, 2016	3.69% medium term notes, due July 19, 2023	4.55% medium term notes, due November 15, 2041	0.75 % senior notes, due January 15, 2016	2.5 % senior unsecured notes, due August 1, 2022	0.875 % senior unsecured notes, due March 2, 2015	Medium-Term Loan, Floating Rate, due July 2018
	USD ($)	USD ($)	USD ($)	USD ($)	CAD	CAD	USD ($)	USD ($)	USD ($)	USD ($)
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$1,250,000,000	$625,000,000	$625,000,000	$500,000,000	450,000,000	300,000,000	$750,000,000	$1,000,000,000	$500,000,000	$500,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.63%	3.75%	5.00%		3.69%	4.55%	0.75%	2.50%	0.88%

LONGTERM_DEBT_RETIRED_Details

LONG-TERM DEBT RETIRED (Details)	1 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Feb. 28, 2014	Jan. 31, 2014	Aug. 31, 2013	Jun. 30, 2013	31-May-12	Jun. 30, 2014	Dec. 31, 2012
	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	TransCanada PipeLines Limited	Nova Gas Transmission LTD	Nova Gas Transmission LTD
	Debentures, 11.10%	Medium-Term Notes at 5.05%	Medium-Term Notes, 5.65%	Senior Unsecured Notes 5.05%	4.00% senior unsecured notes	8.63% senior unsecured notes	Debentures, 11.20%	8.50% debentures
	CAD	CAD	CAD	USD ($)	USD ($)	USD ($)	CAD	USD ($)
Debt Instrument [Line Items]
Repayments of Debt	125	300	450	$500	$350	$200	53	$175
Debt Instrument, Interest Rate, Stated Percentage	11.10%	5.05%	5.65%	5.05%	4.00%	8.63%	11.20%	8.50%

LONGTERM_DEBT_INTEREST_EXPENSE

LONG-TERM DEBT - INTEREST EXPENSE AND PAYMENTS (Details) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Interest Expense [Abstract]
Interest Costs Capitalized	-259	-287	-300
Amortization of Financing Costs and Discounts	55	-21	7
Interest expense (Note 15)	1,198	985	976
Interest payments on long-term debt and junior subordinated notes, net of interest capitalized on construction projects	1,123	985	966
Notes payable
Interest Expense [Abstract]
Interest Expense, Debt, Excluding Amortization	15	12	16
Total long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest Expense, Debt, Excluding Amortization	1,317	1,216	1,190
Junior subordinated notes
Interest Expense [Abstract]
Interest Expense, Debt, Excluding Amortization	70	65	63

INCOME_TAXES_Details

INCOME TAXES (Details) (CAD)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current
Canada		103	27	167
Foreign		42	16	14
Total		145	43	181
Deferred
Canada		309	245	69
Foreign		377	323	216
Total		686	568	285
Total Income Tax Expense/(Recovery)		831	611	466
Geographic Components of Income
Canada		1,146	1,224	842
Foreign		1,678	1,298	1,096
Income before Income Taxes		2,824	2,522	1,938
Reconciliation of Income Tax Expense
Income before Income Taxes		2,824	2,522	1,938
Federal and provincial statutory tax rate		25.00%	25.00%	25.00%
Expected income tax expense		706	631	485
Income tax differential related to regulated operations		129	-13	41
Higher/(lower) effective foreign tax rates		25	33	-12
Income from equity investments and non-controlling interests		-38	-28	-27
Tax legislation change	-25	0	-25	0
Other		9	13	-21
Total Income Tax Expense/(Recovery)		831	611	466
Deferred Income Tax Assets
Operating loss carryforwards		1,266	826
Deferred amounts		215	223
Unrealized foreign exchange losses on long-term debt		140	0
Financial Instruments		104	0
Other		248	128
Total		1,973	1,177
Less: Valuation allowance		125	0
Deferred Tax Assets, Net of Valuation Allowance		1,848	1,177
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs		5,548	4,245
Equity investments		648	682
Taxes on future revenue requirement		253	291
Unrealized foreign exchange gains on long-term debt		0	35
Other		71	170
Total		6,520	5,423
Net Deferred Income Tax Liabilities		4,672	4,246
Deferred Income Tax Assets
Deferred income tax assets (Note 16)		427	119
Intangible and Other Assets		180	225
Total		607	344
Deferred Income Tax Liabilities
Accounts Payable and Other		4	26
Deferred Income Tax Liabilities		5,275	4,564
Total		5,279	4,590
Net Deferred Income Tax Liabilities
Net Deferred Income Tax Liabilities		4,672	4,246

INCOME_TAXES_Details_2

INCOME TAXES (Details 2)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013
	CAD	CAD	CAD	Canada federal and provincial	Canada federal and provincial	U.S. federal	U.S. federal
				CAD	CAD	USD ($)	USD ($)
Net operating loss carryforwards
Unused net operating loss carryforwards				1,131	1,026	$2,267	$1,432
Deferred income tax liabilities on the unremitted earnings of foreign investments	236	182
Income tax payments, net of refunds	109	202	-190

INCOME_TAXES_Details_3

INCOME TAXES (Details 3) (CAD)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of the annual changes in the total unrecognized tax benefit
Unrecognized tax benefits at beginning of year		23	49	52
Gross increases b tax positions in prior years		3	3	2
Gross decreases b tax positions in prior years		-8	-28	-6
Gross increases b tax positions in current year		1	2	9
Lapses of statute of limitations		-1	-3	-8
Unrecognized tax benefits at end of year		18	23	49
Tax adjustment	25	0	25	0
Income tax interest and penalties
Interest expense (reversal) reflected within net tax expense		1	1	-2
Accrued interest expense		5	6

JUNIOR_SUBORDINATED_NOTES_Deta

JUNIOR SUBORDINATED NOTES (Details)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2014
In Millions, unless otherwise specified	CAD	CAD	TRANSCANADA PIPELINES LIMITED	TRANSCANADA PIPELINES LIMITED	TRANSCANADA PIPELINES LIMITED	TRANSCANADA PIPELINES LIMITED	London Interbank Offered Rate (LIBOR) [Member]
			Junior subordinated notes	Junior subordinated notes	Junior subordinated notes	Junior subordinated notes	TRANSCANADA PIPELINES LIMITED
			USD ($)	CAD	USD ($)	CAD	Junior subordinated notes
Debt Instrument [Line Items]
Amount outstanding	1,160	1,063	$1,000	1,160	$1,000	1,063
Effective interest rate (as a percent)			6.50%	6.50%	6.50%	6.50%
Interest rate until May 15, 2017 (as a percent)			6.35%	6.35%
Interest rate margin after May 15, 2017 (as a percent)							2.21%
Optional period for which payment of interest can be deferred			10 years	10 years
Redemption price as a percentage of principal amount plus accrued and unpaid interest to the date of redemption			100.00%	100.00%

NONCONTROLLING_INTERESTS_Detai

NON-CONTROLLING INTERESTS (Details) (CAD)	12 Months Ended			0 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 15, 2013	Mar. 05, 2014	Aug. 01, 2014	Jul. 31, 2014	1-May-13
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	1,583	1,611
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	153	125	118
TC PipeLines, LP
Preferred Shares of TCPL
Fees received for services provided	3	3	3
Portland
Preferred Shares of TCPL
Fees received for services provided	8	7	7
TransCanada PipeLines Limited \| Series U
Preferred Shares of TCPL
Number of shares outstanding				4,000,000
Preferred stock dividend rate				5.60%
Redemption price per share (in Canadian dollars per share)				50
Accrued and unpaid dividends, in CAD per share				0.5907
TransCanada PipeLines Limited \| Series Y
Preferred Shares of TCPL
Number of shares outstanding					4,000,000
Preferred stock dividend rate					5.60%
Redemption price per share (in Canadian dollars per share)					50
Accrued and unpaid dividends, in CAD per share					0.2455
Noncontrolling Interest
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	15	12	5
Noncontrolling Interest \| TC PipeLines, LP
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	1,479	1,323
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	136	93	91
Additional information
Percentage of non-controlling interests						71.70%	71.10%	66.70%
Noncontrolling Interest \| Portland
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	104	94
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	15	12	5
Additional information
Percentage of non-controlling interests	38.30%	38.30%	38.30%
Noncontrolling Interest \| TransCanada PipeLines Limited
Non-controlling interest included in the Consolidated Balance Sheet
Preferred shares of TCPL	0	194
Non-controlling interests included in the Consolidated Statement of Income
Preferred shares of TCPL	2	20	22

COMMON_SHARES_Details

COMMON SHARES (Details) (CAD)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in common shares during the period
Outstanding at the beginning of the period (in shares)	707,000,000
Outstanding at the beginning of the period	12,149
Exercise of options (in shares)	1,221,000	1,980,000	1,600,000
Outstanding at the end of the period (in shares)	709,000,000	707,000,000
Outstanding at the end of the period	12,202	12,149
Net Income per Share
Basic (in shares)	708,000,000	707,000,000	705,000,000
Diluted (in shares)	710,000,000	708,000,000	706,000,000
Common Shares
Changes in common shares during the period
Outstanding at the beginning of the period (in shares)	707,441,000	705,461,000	703,861,000
Outstanding at the beginning of the period	12,149	12,069	12,011
Exercise of options (in shares)	1,221,000	1,980,000	1,600,000
Exercise of options	53	80	58
Outstanding at the end of the period (in shares)	708,662,000	707,441,000	705,461,000
Outstanding at the end of the period	12,202	12,149	12,069
Net Income per Share
Basic (in shares)	708,000,000	706,700,000	704,600,000
Diluted (in shares)	709,600,000	707,700,000	705,700,000

COMMON_SHARES_Details_2

COMMON SHARES (Details 2) (CAD)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Number of Options
Outstanding at the beginning of the period (in shares)	7,393	7,434	7,100
Granted (in shares)	2,292	1,939	1,978
Exercised (in shares)	-1,221	-1,980	-1,600
Forfeited (in shares)			-44
Outstanding at the end of the period (in shares)	8,464	7,393	7,434
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share)	40.57	37.69	35.44
Granted (in Canadian dollars per share)	49.03	47.09	42.03
Exercised (in Canadian dollars per share)	43	36.12	33.13
Forfeited (in Canadian dollars per share)			36.55
Outstanding at the end of the period (in Canadian dollars per share)	43.17	40.57	37.69
Options Exercisable
Options Exercisable (in shares)	4,902	3,954	4,588	5,165

COMMON_SHARES_Details_3

COMMON SHARES (Details 3) (CAD)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Options Outstanding
Number of Options (in shares)	8,464,000
Weighted Average Exercise Price (in Canadian dollars per share)	43.17
Weighted Average Remaining Contractual Life	4 years 3 months 17 days
Options Exercisable
Number of Options (in shares)	4,902,000
Weighted Average Exercise Price (in Canadian dollars per share)	39.81
Weighted Average Remaining Contractual Life	3 years 3 months 18 days
Additional disclosure
Common shares reserved for future issuance under stock option plan	8,200,000
Weighted average fair value of options granted (in Canadian dollars per share)	5.54	5.74	5.08
Contractual life of options granted	7 years
Award vesting right percentage	33.30%
Award vesting period	3 years
Weighted average assumptions used in binomial model for determining the fair value of awards granted
Expected life (years)	6 years	6 years	5 years 10 months 24 days
Interest rate (as a percent)	1.80%	1.70%	1.60%
Volatility (as a percent)	17.00%	18.00%	19.00%
Dividend yield (as a percent)	3.80%	3.70%	4.20%
Forfeiture rate (as a percent)	5.00%	15.00%	15.00%
Amount expensed for stock awards, with a corresponding increase in additional paid-in capital	9	6	5
Total intrinsic value of options exercised	68	25	18
Fair value of options that have vested	113	65	49
Total options vested	2,000,000	1,300,000	1,000,000
Aggregate intrinsic value of total options exercisable	85
Total intrinsic value of options outstanding	118
Range of exercise price per share $30.10 to $36.26
Options Outstanding
Number of Options (in shares)	1,410,000
Weighted Average Exercise Price (in Canadian dollars per share)	33.85
Weighted Average Remaining Contractual Life	1 year 8 months 12 days
Options Exercisable
Number of Options (in shares)	1,410,000
Weighted Average Exercise Price (in Canadian dollars per share)	33.85
Weighted Average Remaining Contractual Life	1 year 8 months 12 days
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, End of Period [Abstract]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit	30.1
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit	36.26
Range of exercise price per share $36.90 to $41.65
Options Outstanding
Number of Options (in shares)	1,101,000
Weighted Average Exercise Price (in Canadian dollars per share)	38.24
Weighted Average Remaining Contractual Life	3 years 1 month 6 days
Options Exercisable
Number of Options (in shares)	1,101,000
Weighted Average Exercise Price (in Canadian dollars per share)	38.24
Weighted Average Remaining Contractual Life	3 years 1 month 6 days
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, End of Period [Abstract]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit	36.9
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit	41.65
Range of exercise price per share $41.95 to $45.29
Options Outstanding
Number of Options (in shares)	1,819,000
Weighted Average Exercise Price (in Canadian dollars per share)	42.04
Weighted Average Remaining Contractual Life	4 years 2 months 11 days
Options Exercisable
Number of Options (in shares)	1,464,000
Weighted Average Exercise Price (in Canadian dollars per share)	42.02
Weighted Average Remaining Contractual Life	4 years 2 months 11 days
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, End of Period [Abstract]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit	41.95
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit	45.29
Range of exercise price per share $47.09
Options Outstanding
Number of Options (in shares)	1,842,000
Weighted Average Exercise Price (in Canadian dollars per share)	47.09
Weighted Average Remaining Contractual Life	5 years 1 month 6 days
Options Exercisable
Number of Options (in shares)	847,000
Weighted Average Exercise Price (in Canadian dollars per share)	47.09
Weighted Average Remaining Contractual Life	5 years 1 month 6 days
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, End of Period [Abstract]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit	47.09
Range of exercise price per share $49.03
Options Outstanding
Number of Options (in shares)	2,292,000
Weighted Average Exercise Price (in Canadian dollars per share)	49.03
Weighted Average Remaining Contractual Life	6 years 2 months 12 days
Options Exercisable
Number of Options (in shares)	80,000
Weighted Average Exercise Price (in Canadian dollars per share)	49.03
Weighted Average Remaining Contractual Life	6 years 2 months 6 days
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, End of Period [Abstract]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit	49.03

COMMON_SHARES_Details_4

COMMON SHARES (Details 4)	Dec. 31, 2014
COMMON SHARES (Details 4)	right
Shareholder Rights Plan
Number of rights entitled to each common share	1
Number of common shares entitled to be purchased under each right	2

PREFERRED_SHARES_Details

PREFERRED SHARES (Details) (CAD)	12 Months Ended	0 Months Ended	12 Months Ended	1 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Jan. 31, 2014
Preferred Shares [Line Items]
Preferred shares (Note 20)	2,255	2,255	1,813
Preferred Stock, Redeemed on Designated Conversion Date, Price per Share	25	25
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum	90 days
Preferred Stock Period of Bond Considered for Dividend Yield Calculation	5 years
Series 1
Preferred Shares [Line Items]
Preferred shares, authorized	9,498,423	9,498,423	9,498,423
Preferred shares, outstanding	9,498,423	9,498,423	9,498,423
Preferred stock, current yield (percentage)	3.27%
Annual Dividend Rate per Share (in Canadian dollars per share)	0.82		0.82
Redemption price per share (in Canadian dollars per share)	25	25	25
Preferred shares (Note 20)	233	233	539
Period of subsequent interval for redemption of preferred stock	5 years
Period of subsequent interval for conversion of preferred stock	5 years
Conversion of Stock, Shares Converted		12,501,577
Series 2
Preferred Shares [Line Items]
Preferred shares, authorized	12,502,000	12,502,000
Preferred stock, current yield (percentage)	2.82%
Redemption price per share (in Canadian dollars per share)	25.5	25.5
Preferred shares (Note 20)	306	306	0
Series 3
Preferred Shares [Line Items]
Preferred shares, authorized	14,000,000	14,000,000	14,000,000
Preferred shares, outstanding	14,000,000	14,000,000	14,000,000
Preferred stock, current yield (percentage)	4.00%
Annual Dividend Rate per Share (in Canadian dollars per share)	1		1
Redemption price per share (in Canadian dollars per share)	25	25	25
Preferred shares (Note 20)	343	343	343
Period of subsequent interval for redemption of preferred stock	5 years
Period of subsequent interval for conversion of preferred stock	5 years
Series 5
Preferred Shares [Line Items]
Preferred shares, authorized	14,000,000	14,000,000	14,000,000
Preferred shares, outstanding	14,000,000	14,000,000	14,000,000
Preferred stock, current yield (percentage)	4.40%
Annual Dividend Rate per Share (in Canadian dollars per share)	1.1		1.1
Redemption price per share (in Canadian dollars per share)	25	25	25
Preferred shares (Note 20)	342	342	342
Period of subsequent interval for redemption of preferred stock	5 years
Period of subsequent interval for conversion of preferred stock	5 years
Series 7
Preferred Shares [Line Items]
Preferred shares, authorized	24,000,000	24,000,000	24,000,000
Preferred shares, outstanding	24,000,000	24,000,000	24,000,000
Preferred stock, current yield (percentage)	4.00%
Annual Dividend Rate per Share (in Canadian dollars per share)	1		1
Redemption price per share (in Canadian dollars per share)	25	25	25
Preferred shares (Note 20)	589	589	589
Period of subsequent interval for redemption of preferred stock	5 years
Period of subsequent interval for conversion of preferred stock	5 years
Series 9
Preferred Shares [Line Items]
Preferred shares, authorized	18,000,000	18,000,000	18,000,000
Preferred shares, outstanding	18,000,000	18,000,000	18,000,000
Preferred stock, current yield (percentage)	4.25%
Annual Dividend Rate per Share (in Canadian dollars per share)	1.06		1.06
Redemption price per share (in Canadian dollars per share)	25	25	25
Preferred shares (Note 20)	442	442	0
Period of subsequent interval for redemption of preferred stock	5 years
Period of subsequent interval for conversion of preferred stock	5 years
Number of shares issued				18,000,000
Shares Issued, Price Per Share				25
Gross proceeds from public offering of preferred shares				450
Government of Canada, Treasury Bill Rate \| Series 2
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	1.92%	1.92%
Government of Canada, Treasury Bill Rate \| Series 4
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	1.28%	1.28%
Government of Canada, Treasury Bill Rate \| Series 6
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	1.54%	1.54%
Government of Canada, Treasury Bill Rate \| Series 8
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	2.38%	2.38%
Government of Canada, Treasury Bill Rate \| Series 10
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum				2.35%
Government of Canada, Five-Year Bond Yield \| Series 1
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	1.92%	1.92%
Government of Canada, Five-Year Bond Yield \| Series 3
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	1.28%	1.28%
Government of Canada, Five-Year Bond Yield \| Series 5
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	1.54%	1.54%
Government of Canada, Five-Year Bond Yield \| Series 7
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	2.38%	2.38%
Government of Canada, Five-Year Bond Yield \| Series 9
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum	2.35%	2.35%

OTHER_COMPREHENSIVE_INCOME_AND2

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Details) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Before tax amount
Foreign currency translation gains and losses on net investments in foreign operations	462	269	-97
Change in fair value of net investment hedges	-373	-323	59
Reclassification to Net Income of gains and losses on cash flow hedges	-95	60	219
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	-146	96	-104
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	25	34	22
Other comprehensive loss on Equity Investments	-272	313	-93
Other comprehensive income (loss)	-517	570	67
Income tax recovery/(expense)
Foreign currency translation gains and losses on net investments in foreign operations	55	114	-32
Change in fair value of net investment hedges	-97	-84	15
Change in fair value of cash flow hedges	49	-50	-13
Reclassification to Net Income of gains and losses on cash flow hedges	40	-19	-81
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	44	-29	31
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	-7	-11	0
Other comprehensive loss on Equity Investments	68	-79	23
Other comprehensive income (loss)	346	10	-87
Net of tax amount
Foreign currency translation gains and losses on net investments in foreign operations	517	383	-129
Change in fair value of net investment hedges	-276	-239	44
Change in fair value of cash flow hedges	-69	71	48
Reclassification to Net Income of gains and losses on cash flow hedges	-55	41	138
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	-102	67	-73
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	18	23	22
Other comprehensive loss on Equity Investments	-204	234	-70
Other Comprehensive Income/(Loss) (Note 21)	-171	580	-20
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	-118	121	61

OTHER_COMPREHENSIVE_INCOME_AND3

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Details 2) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	-934	-1,448	-1,449
Other comprehensive income/(loss) before reclassifications	-266	435	-156
Amounts reclassified from Accumulated Other Comprehensive Loss	-35	79	157
Net current period other comprehensive (loss)/income	-301	514	1
AOCI Balance	-1,235	-934	-1,448
Other comprehensive income/(loss) before reclassifications attributable to noncontrolling interest	130	66	-21
Cash flow hedge losses expected to be reclassified within the next twelve months, before tax	95
Cash flow hedge losses expected to be reclassified within the next twelve months, net of tax	55
Currency translation adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	-629	-707	-643
Other comprehensive income/(loss) before reclassifications	111	78	-64
Amounts reclassified from Accumulated Other Comprehensive Loss	0	0	0
Net current period other comprehensive (loss)/income	111	78	-64
AOCI Balance	-518	-629	-707
Cash flow hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	-4	-116	-302
Other comprehensive income/(loss) before reclassifications	-69	71	48
Amounts reclassified from Accumulated Other Comprehensive Loss	-55	41	138
Net current period other comprehensive (loss)/income	-124	112	186
AOCI Balance	-128	-4	-116
Pension and OPEB plan adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	-197	-287	-236
Other comprehensive income/(loss) before reclassifications	-102	67	-73
Amounts reclassified from Accumulated Other Comprehensive Loss	18	23	22
Net current period other comprehensive (loss)/income	-84	90	-51
AOCI Balance	-281	-197	-287
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	-104	-338	-268
Other comprehensive income/(loss) before reclassifications	-206	219	-67
Amounts reclassified from Accumulated Other Comprehensive Loss	2	15	-3
Net current period other comprehensive (loss)/income	-204	234	-70
AOCI Balance	-308	-104	-338

OTHER_COMPREHENSIVE_INCOME_AND4

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Details 3) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenue (Energy)	3,725	3,176	2,704
Interest Expense	-1,198	-985	-976
Income/(Loss) from Equity Investments	522	597	257
Income before Income Taxes	2,824	2,522	1,938
Income Tax Expense	-831	-611	-466
Net Income Attributable to Controlling Interests	1,840	1,786	1,354
Cash flow hedges \| Amounts reclassified from accumulated other comprehensive loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income before Income Taxes	95	-60	219
Income Tax Expense	-40	19	-81
Net Income Attributable to Controlling Interests	55	-41	138
Cash flow hedges \| Power and Natural Gas \| Amounts reclassified from accumulated other comprehensive loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenue (Energy)	111	-44	201
Cash flow hedges \| Interest \| Amounts reclassified from accumulated other comprehensive loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest Expense	-16	-16	18
Pension and other post-retirement plan adjustments \| Amounts reclassified from accumulated other comprehensive loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of actuarial loss and past service cost	-25	-34	-22
Income before Income Taxes	7	11	0
Net Income Attributable to Controlling Interests	-18	-23	-22
Equity Investments \| Amounts reclassified from accumulated other comprehensive loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income/(Loss) from Equity Investments	-2	-20	5
Income Tax Expense	0	5	-2
Net Income Attributable to Controlling Interests	-2	-15	3

EMPLOYEE_POSTRETIREMENT_BENEFI2

EMPLOYEE POST-RETIREMENT BENEFITS (Details) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized	12 years	11 years	12 years
Expense for savings plan and DC Plans	37	29	24
Cash Payments for Employee Post-Retirement Benefits [Abstract]
Cash payments for employee post-retirement benefits, Savings and DC Plans	37	29	24
Cash payments for employee post-retirement benefits	116	114	114
Change in Plan Assets
Plan assets at fair value b beginning of year	2,187
Plan assets at fair value b end of year	2,437	2,187
Amounts recognized in the Balance Sheet
Intangible and Other Assets (Note 11)	14	16
Other Long-Term Liabilities (Note 14)	-444	-244
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]
Cash payments for employee post-retirement benefits, DB Plans and Other	73	79	83
Change in Benefit Obligation
Benefit obligation b beginning of year	2,224	2,142
Service cost	85	84	66
Interest cost	113	96	94
Employee contributions	4	4
Benefits paid	-102	-83
Actuarial loss/(gain)	302	-39
Foreign exchange rate changes	32	20
Benefit obligation b end of year	2,658	2,224	2,142
Change in Plan Assets
Plan assets at fair value b beginning of year	2,152	1,825
Actual return on plan assets	246	313
Employer contributions	73	79	83
Employee contributions	4	4
Benefits paid	-102	-83
Foreign exchange rate changes	25	14
Plan assets at fair value b end of year	2,398	2,152	1,825
Funded Status b Plan Deficit	-260	-72
Amounts recognized in the Balance Sheet
Intangible and Other Assets (Note 11)	0	0
Accounts Payable and Other (Note 13)	0	0
Other Long-Term Liabilities (Note 14)	-260	-72
Net	-260	-72
Pension Benefit Plans \| Canada
Cash Payments for Employee Post-Retirement Benefits [Abstract]
Letter of credit to the DB Plan	47	59	48
Total amount outstanding under letters of credit	181	134
Other Post-Retirement Benefit Plans
Cash Payments for Employee Post-Retirement Benefits [Abstract]
Cash payments for employee post-retirement benefits, DB Plans and Other	6	6	7
Change in Benefit Obligation
Benefit obligation b beginning of year	191	186
Service cost	2	2	2
Interest cost	10	7	8
Employee contributions	0	0
Benefits paid	-7	-7
Actuarial loss/(gain)	14	-2
Foreign exchange rate changes	6	5
Benefit obligation b end of year	216	191	186
Change in Plan Assets
Plan assets at fair value b beginning of year	35	32
Actual return on plan assets	2	2
Employer contributions	6	6	7
Employee contributions	0	0
Benefits paid	-7	-7
Foreign exchange rate changes	3	2
Plan assets at fair value b end of year	39	35	32
Funded Status b Plan Deficit	-177	-156
Amounts recognized in the Balance Sheet
Intangible and Other Assets (Note 11)	14	16
Accounts Payable and Other (Note 13)	-7	0
Other Long-Term Liabilities (Note 14)	-184	-172
Net	-177	-156

EMPLOYEE_POSTRETIREMENT_BENEFI3

EMPLOYEE POST-RETIREMENT BENEFITS (Details 2) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Funded status based on accumulated benefit obligation
Plan assets at fair value	2,437	2,187
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	-2,658	-2,224
Plan assets at fair value	2,398	2,152
Funded Status b Deficit	-260	-72
Accumulated benefit obligation	2,437	2,039
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	-2,437	-2,039
Plan assets at fair value	2,398	2,152	1,825
Funded Status b (Deficit)/Surplus	-39	113
Accumulated benefit obligation and fair value of plan assets for plans that are not fully funded
Accumulated benefit obligation	-715	-569
Plan assets at fair value	597	537
Funded Status b Deficit	-118	-32
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Expected average remaining service life of employees over which past service costs are amortized	9 years	9 years	9 years
Pension Benefit Plans \| Debt securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	31.00%	31.00%
Amount of the Company's debt or the Company's common shares included in plan assets	1	2
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 (as a percent)	25.00%
Pension Benefit Plans \| Debt securities \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations (as a percent)	35.00%
Pension Benefit Plans \| Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	69.00%	69.00%
Amount of the Company's debt or the Company's common shares included in plan assets	1	2
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 (as a percent)	50.00%
Pension Benefit Plans \| Equity securities \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations (as a percent)	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 (as a percent)	5.00%
Pension Benefit Plans \| Alternatives \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations (as a percent)	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	-191	-172
Plan assets at fair value	0	0
Funded Status b Deficit	-191	-172
Funded status based on accumulated benefit obligation
Plan assets at fair value	39	35	32

EMPLOYEE_POSTRETIREMENT_BENEFI4

EMPLOYEE POST-RETIREMENT BENEFITS (Details 3) (CAD)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee post-retirement benefits
Fair value of plan assets	2,437	2,187
Percentage of Total Portfolio	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	1,239	1,064
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1,185	1,105
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	13	18
Cash and cash equivalents
Employee post-retirement benefits
Fair value of plan assets	20	17
Percentage of Total Portfolio	1.00%	1.00%
Cash and cash equivalents \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	20	17
Cash and cash equivalents \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Cash and cash equivalents \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities \| Canada
Employee post-retirement benefits
Fair value of plan assets	503	644
Percentage of Total Portfolio	21.00%	29.00%
Equity securities \| U.S.
Employee post-retirement benefits
Fair value of plan assets	551	460
Percentage of Total Portfolio	23.00%	21.00%
Equity securities \| International
Employee post-retirement benefits
Fair value of plan assets	365	366
Percentage of Total Portfolio	15.00%	17.00%
Equity securities \| Global
Employee post-retirement benefits
Fair value of plan assets	141	14
Percentage of Total Portfolio	6.00%	1.00%
Equity securities \| Emerging
Employee post-retirement benefits
Fair value of plan assets	87	0
Percentage of Total Portfolio	3.00%	0.00%
Equity securities \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	361	474
Equity securities \| Quoted Prices in Active Markets (Level I) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	516	423
Equity securities \| Quoted Prices in Active Markets (Level I) \| International
Employee post-retirement benefits
Fair value of plan assets	218	36
Equity securities \| Quoted Prices in Active Markets (Level I) \| Global
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities \| Quoted Prices in Active Markets (Level I) \| Emerging
Employee post-retirement benefits
Fair value of plan assets	7	0
Equity securities \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	142	170
Equity securities \| Significant Other Observable Inputs (Level II) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	35	37
Equity securities \| Significant Other Observable Inputs (Level II) \| International
Employee post-retirement benefits
Fair value of plan assets	147	330
Equity securities \| Significant Other Observable Inputs (Level II) \| Global
Employee post-retirement benefits
Fair value of plan assets	141	14
Equity securities \| Significant Other Observable Inputs (Level II) \| Emerging
Employee post-retirement benefits
Fair value of plan assets	80	0
Equity securities \| Significant Unobservable Inputs (Level III) \| Canada
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities \| Significant Unobservable Inputs (Level III) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities \| Significant Unobservable Inputs (Level III) \| International
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities \| Significant Unobservable Inputs (Level III) \| Global
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity securities \| Significant Unobservable Inputs (Level III) \| Emerging
Employee post-retirement benefits
Fair value of plan assets	0	0
Federal Bonds \| Canada
Employee post-retirement benefits
Fair value of plan assets	218	190
Percentage of Total Portfolio	9.00%	9.00%
Federal Bonds \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	0	0
Federal Bonds \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	218	190
Federal Bonds \| Significant Unobservable Inputs (Level III) \| Canada
Employee post-retirement benefits
Fair value of plan assets	0	0
Provincial Bonds \| Canada
Employee post-retirement benefits
Fair value of plan assets	180	154
Percentage of Total Portfolio	7.00%	7.00%
Provincial Bonds \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	0	0
Provincial Bonds \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	180	154
Provincial Bonds \| Significant Unobservable Inputs (Level III) \| Canada
Employee post-retirement benefits
Fair value of plan assets	0	0
Municipal Bonds \| Canada
Employee post-retirement benefits
Fair value of plan assets	7	6
Percentage of Total Portfolio	0.00%	0.00%
Municipal Bonds \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	0	0
Municipal Bonds \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	7	6
Municipal Bonds \| Significant Unobservable Inputs (Level III) \| Canada
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate Bonds \| Canada
Employee post-retirement benefits
Fair value of plan assets	76	77
Percentage of Total Portfolio	3.00%	3.00%
Corporate Bonds \| U.S.
Employee post-retirement benefits
Fair value of plan assets	59	48
Percentage of Total Portfolio	2.00%	2.00%
Corporate Bonds \| International
Employee post-retirement benefits
Fair value of plan assets	14	20
Percentage of Total Portfolio	1.00%	1.00%
Corporate Bonds \| Quoted Prices in Active Markets (Level I) \| Canada
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate Bonds \| Quoted Prices in Active Markets (Level I) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate Bonds \| Quoted Prices in Active Markets (Level I) \| International
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate Bonds \| Significant Other Observable Inputs (Level II) \| Canada
Employee post-retirement benefits
Fair value of plan assets	76	77
Corporate Bonds \| Significant Other Observable Inputs (Level II) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	59	48
Corporate Bonds \| Significant Other Observable Inputs (Level II) \| International
Employee post-retirement benefits
Fair value of plan assets	14	20
Corporate Bonds \| Significant Unobservable Inputs (Level III) \| Canada
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate Bonds \| Significant Unobservable Inputs (Level III) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Corporate Bonds \| Significant Unobservable Inputs (Level III) \| International
Employee post-retirement benefits
Fair value of plan assets	0	0
State Bonds \| U.S.
Employee post-retirement benefits
Fair value of plan assets	47	33
Percentage of Total Portfolio	2.00%	2.00%
State Bonds \| Quoted Prices in Active Markets (Level I) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
State Bonds \| Significant Other Observable Inputs (Level II) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	47	33
State Bonds \| Significant Unobservable Inputs (Level III) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	0	0
Mortgage Backed \| International
Employee post-retirement benefits
Fair value of plan assets	39	26
Percentage of Total Portfolio	2.00%	1.00%
Mortgage Backed \| Quoted Prices in Active Markets (Level I) \| International
Employee post-retirement benefits
Fair value of plan assets	0	0
Mortgage Backed \| Significant Other Observable Inputs (Level II) \| International
Employee post-retirement benefits
Fair value of plan assets	39	26
Mortgage Backed \| Significant Unobservable Inputs (Level III) \| International
Employee post-retirement benefits
Fair value of plan assets	0	0
Other Investments: Private Equity Funds
Employee post-retirement benefits
Fair value of plan assets	13	18
Percentage of Total Portfolio	0.00%	1.00%
Other Investments: Private Equity Funds \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	0	0
Other Investments: Private Equity Funds \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Other Investments: Private Equity Funds \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	13	18	19
Funds Held on Deposit
Employee post-retirement benefits
Fair value of plan assets	117	114
Percentage of Total Portfolio	5.00%	5.00%
Funds Held on Deposit \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	117	114
Funds Held on Deposit \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Funds Held on Deposit \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0

EMPLOYEE_POSTRETIREMENT_BENEFI5

EMPLOYEE POST-RETIREMENT BENEFITS (Details 4) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Net change in the Level III fair value category
Plan assets at fair value b end of year	2,437	2,187
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value b end of year	13	18
Other Investments: Private Equity Funds
Net change in the Level III fair value category
Plan assets at fair value b end of year	13	18
Other Investments: Private Equity Funds \| Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value b beginning of year	18	19
Purchases and sales	-7	-4
Realized and unrealized gains	2	3
Plan assets at fair value b end of year	13	18

EMPLOYEE_POSTRETIREMENT_BENEFI6

EMPLOYEE POST-RETIREMENT BENEFITS (Details 5) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for other post-retirement benefit plans, Savings Plan and DC Plans	36
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits for 2013 (as a percent)	7.50%
Percentage level to which average annual rate was assumed to decrease	5.00%
Effects of a one per cent change in assumed health care cost trend rates
Effect on total of service and interest cost components, Increase	1
Effect on total of service and interest cost components, Decrease	-1
Effect on post-retirement benefit obligation, Increase	14
Effect on post-retirement benefit obligation, Decrease	-12
Pension Benefit Plans
DB Plans
Company's expected funding contributions	70
Estimated future benefit payments, which reflect expected future service
2015	102
2016	108
2017	114
2018	120
2019	127
2020 to 2024	728
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.15%	4.95%
Rate of compensation increase	3.15%	3.15%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	4.95%	4.35%	5.05%
Expected long-term rate of return on plan assets	6.90%	6.70%	6.70%
Rate of compensation increase	3.15%	3.15%	3.15%
Net benefit cost
Service cost	85	84	66
Interest cost	113	96	94
Expected return on plan assets	-139	-120	-113
Amortization of actuarial loss	21	30	18
Amortization of past service cost	2	2	2
Amortization of regulatory asset	18	30	19
Amortization of transitional obligation related to regulated business	0	0	0
Net Benefit Cost Recognized	100	122	86
Pre-tax amounts recognized in AOCI
Net loss	354	236	362
Prior service cost	2	3	5
Total pre-tax amounts recognized in AOCI	356	239	367
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	27
Estimated prior period cost that will be amortized	2
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to OCI	-21	-30	-19
Amortization of prior service costs from AOCI to OCI	-2	-2	-2
Funded status adjustment	137	-96	99
Total pre-tax amounts recognized in OCI	114	-128	78
Pension Benefit Plans \| Canada
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	181	134
Pension Benefit Plans \| Canada \| Scenario, Plan
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	35
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	7
Estimated future benefit payments, which reflect expected future service
2015	8
2016	8
2017	9
2018	9
2019	10
2020 to 2024	51
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.20%	5.00%
Rate of compensation increase	0.00%	0.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	5.00%	4.35%	5.10%
Expected long-term rate of return on plan assets	4.60%	4.60%	6.40%
Rate of compensation increase	0.00%	0.00%	0.00%
Net benefit cost
Service cost	2	2	2
Interest cost	10	7	8
Expected return on plan assets	-2	-2	-2
Amortization of actuarial loss	2	2	1
Amortization of past service cost	0	0	1
Amortization of regulatory asset	1	1	1
Amortization of transitional obligation related to regulated business	2	2	2
Net Benefit Cost Recognized	15	12	13
Pre-tax amounts recognized in AOCI
Net loss	40	32	33
Prior service cost	1	1	2
Total pre-tax amounts recognized in AOCI	41	33	35
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	2
Estimated prior period cost that will be amortized	0
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to OCI	-2	-2	-1
Amortization of prior service costs from AOCI to OCI	0	0	0
Funded status adjustment	9	0	5
Total pre-tax amounts recognized in OCI	7	-2	4

RISK_MANAGEMENT_AND_FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details) (Designated as a net investment hedge)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	CAD	CAD	US$ denominated	US$ denominated
			USD ($)	USD ($)
Risk management and financial instruments
Debt carrying value	17,000	14,200	$14,700	$13,400
Debt fair value	19,000	16,000	$16,400	$15,000

RISK_MANAGEMENT_AND_FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details 2)

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

In Millions, unless otherwise specified

CAD

Designated as a net investment hedge

US$ denominated

Cross-currency swaps

Forward foreign exchange contracts

USD ($)

CAD

USD ($)

CAD

US$ denominated

CAD

USD ($)

CAD

USD ($)

CAD

Risk management and financial instruments

U.S. dollar foreign exchange forward contracts (maturing 2015)

-1,160

-612

-431

-201

-28

-11

Fair value

-459

-212

Notional or Principal Amount

4,300

4,650

2,900

3,800

1,400

850

Net realized gains related to the interest component

RISK_MANAGEMENT_AND_FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details 3) (CAD)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Gross derivative instruments presented on the balance sheet	502	507
Gross derivative instruments presented on the balance sheet	-1,160	-612
Net Investment Hedging \| Cross Currency, InterestRate Contract and Foreign Exchange Forward
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	-459	-212
Net Investment Hedging \| Cross Currency, InterestRate Contract and Foreign Exchange Forward \| Other Current Assets
Derivatives, Fair Value [Line Items]
Gross derivative instruments presented on the balance sheet	5	5
Net Investment Hedging \| Cross Currency, InterestRate Contract and Foreign Exchange Forward \| Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Gross derivative instruments presented on the balance sheet	1	0
Net Investment Hedging \| Cross Currency, InterestRate Contract and Foreign Exchange Forward \| Other Current Liabilities
Derivatives, Fair Value [Line Items]
Gross derivative instruments presented on the balance sheet	-155	-50
Net Investment Hedging \| Cross Currency, InterestRate Contract and Foreign Exchange Forward \| Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Gross derivative instruments presented on the balance sheet	-310	-167

RISK_MANAGEMENT_AND_FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details 4)	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	USD ($)	CAD	USD ($)	CAD	Interest rate swap agreements	Interest rate swap agreements	Interest rate swap agreements	Interest rate swap agreements	Level II	Level II	Level II	Level II
					CAD	CAD	USD ($)	USD ($)	Carrying Amount	Carrying Amount	Fair Value	Fair Value
									CAD	CAD	CAD	CAD
Financial Assets
Notes receivable and other									213	226	263	269
Available for sale assets									62	47	62	47
Financial Liabilities
Current and Long-Term Debt		-24,757		-22,865					-24,757	-22,865	-28,713	-26,134
Junior subordinated notes		-1,160		-1,063					-1,160	-1,063	-1,157	-1,093
Total liabilities		-658		-105					-25,642	-23,655	-29,545	-26,911
Long-term Debt	400		200
Fair value adjustments (losses)					-3	-5
Long-Term Debt hedged							$400	$200

RISK_MANAGEMENT_AND_FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details 5) (CAD)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Other Current Assets (Note 5)	409	395
Intangible and Other Assets (Note 11)	93	112
Accounts Payable and Other (Note 13)	-749	-357
Other Long-Term Liabilities (Note 14)	-411	-255
Total liabilities	-658	-105
Derivatives instruments, excluding net investment hedges \| Other Current Assets
Derivatives, Fair Value [Line Items]
Other Current Assets (Note 5)	409	395
Derivatives instruments, excluding net investment hedges \| Intangible and Other Assets
Derivatives, Fair Value [Line Items]
Intangible and Other Assets (Note 11)	93	112
Derivatives instruments, excluding net investment hedges \| Accounts Payable and Other
Derivatives, Fair Value [Line Items]
Accounts Payable and Other (Note 13)	-749	-357
Derivatives instruments, excluding net investment hedges \| Other Long-Term Liabilities
Derivatives, Fair Value [Line Items]
Other Long-Term Liabilities (Note 14)	-411	-255

RISK_MANAGEMENT_AND_FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details 6)

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

In Millions, unless otherwise specified

CAD

Commodity contract

Foreign Exchange

Interest

Derivative Financial Instruments Held for Trading

Derivative Financial Instruments in Hedging Relationships

Power

Gas

CAD

Commodity contract

Foreign Exchange

Interest

Commodity contract

Foreign Exchange

Interest

Fair value hedges

CAD

Power

Gas

CAD

U.S. dollars

CAD

Canadian dollars

U.S. dollars

Power

Gas

CAD

U.S. dollars

Interest

CAD

Purchases

Sales

CAD

Purchases

Sales

USD ($)

CAD

USD ($)

CAD

Purchases

Sales

CAD

USD ($)

CAD

USD ($)

Interest expense

Bcf

MWh

CAD

Fair Values

Assets

502

507

419

415

362

265

150

Liabilities

-1,160

-612

-554

-302

-103

-72

-497

-230

-6

-8

-391

-280

-103

-72

-32

-12

-4

-7

-163

-22

-1

-2

-1

Notional Values

Volumes

42,097,000

29,301,000

35,452,000

28,534,000

60,000

88,000

38,000

60,000

11,120,000

9,758,000

3,977,000

6,906,000

Net gains and losses

Net unrealized (losses)/gains in the year

-5

-35

-20

-10

Net realized (losses)/gains in the year

-39

-49

-13

-28

-9

Net realized (losses)/gains in the year

130

-19

-2

Fair value

Notional value

$1,374

$1,015

400

$100

$16

$550

$350

$400

$200

RISK_MANAGEMENT_AND_FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details 7) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	-118	121
Cash Flow Hedges
Components of OCI related to derivatives
Reclassification of (losses)/gains on derivative instruments from AOCI to Net Income (effective portion)	-95	60
(Losses)/gains on derivative instruments recognized in Net Income (ineffective portion)	-13	8
Cash Flow Hedges \| Commodity contract \| Power
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	-126	117
Reclassification of (losses)/gains on derivative instruments from AOCI to Net Income (effective portion)	-114	40
(Losses)/gains on derivative instruments recognized in Net Income (ineffective portion)	-13	8
Cash Flow Hedges \| Commodity contract \| Gas
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	-2	-1
Reclassification of (losses)/gains on derivative instruments from AOCI to Net Income (effective portion)	3	4
Cash Flow Hedges \| Foreign Exchange
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	10	5
Cash Flow Hedges \| Interest
Components of OCI related to derivatives
Reclassification of (losses)/gains on derivative instruments from AOCI to Net Income (effective portion)	16	16

RISK_MANAGEMENT_AND_FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details 8) (CAD)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative - Asset
Gross derivative instruments presented on the balance sheet	502	507
Amounts available for offset	-395	-345
Net amounts	107	162
Derivative - Liability
Gross derivative instruments presented on the balance sheet	-1,160	-612
Amounts available for offset	395	345
Net amounts	-765	-267
Cash collateral provided by the Company	459	67
Letters of credit provided by the Company	26	85
Cash collateral received by the Company	1	11
Letters of credit received by the Company	1	32
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	15	16
Additional collateral required if credit-risk-related contingent features were triggered	15	16
Foreign Exchange
Derivative - Asset
Gross derivative instruments presented on the balance sheet	7	5
Amounts available for offset	-7	-5
Net amounts	0	0
Derivative - Liability
Gross derivative instruments presented on the balance sheet	-497	-230
Amounts available for offset	7	5
Net amounts	-490	-225
Interest
Derivative - Asset
Gross derivative instruments presented on the balance sheet	7	14
Amounts available for offset	-1	-2
Net amounts	6	12
Derivative - Liability
Gross derivative instruments presented on the balance sheet	-6	-8
Amounts available for offset	1	2
Net amounts	-5	-6
Power \| Commodity contract
Derivative - Asset
Gross derivative instruments presented on the balance sheet	419	415
Amounts available for offset	-330	-277
Net amounts	89	138
Derivative - Liability
Gross derivative instruments presented on the balance sheet	-554	-302
Amounts available for offset	330	277
Net amounts	-224	-25
Gas \| Commodity contract
Derivative - Asset
Gross derivative instruments presented on the balance sheet	69	73
Amounts available for offset	-57	-61
Net amounts	12	12
Derivative - Liability
Gross derivative instruments presented on the balance sheet	-103	-72
Amounts available for offset	57	61
Net amounts	-46	-11

Recovered_Sheet1

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details 9) (CAD)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value Hierarchy
Assets	502	507
Liabilities	-1,160	-612
Commodity contract \| Power
Fair Value Hierarchy
Assets	419	415
Liabilities	-554	-302
Commodity contract \| Gas
Fair Value Hierarchy
Assets	69	73
Liabilities	-103	-72
Foreign exchange contracts
Fair Value Hierarchy
Assets	7	5
Liabilities	-497	-230
Interest rate contracts
Fair Value Hierarchy
Assets	7	14
Liabilities	-6	-8
Recurring basis
Fair Value Hierarchy
Non-Derivative Financial Instruments: Available-for-sale assets	62	47
Assets and liabilities, net	-596	-58
Recurring basis \| Commodity contract \| Power
Fair Value Hierarchy
Assets	419	415
Liabilities	-554	-302
Recurring basis \| Commodity contract \| Gas
Fair Value Hierarchy
Assets	69	73
Liabilities	-103	-72
Recurring basis \| Foreign exchange contracts
Fair Value Hierarchy
Assets	7	5
Liabilities	-497	-230
Recurring basis \| Interest rate contracts
Fair Value Hierarchy
Assets	7	14
Liabilities	-6	-8
Recurring basis \| Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Non-Derivative Financial Instruments: Available-for-sale assets	0	0
Assets and liabilities, net	-46	-2
Recurring basis \| Quoted Prices in Active Markets (Level I) \| Commodity contract \| Gas
Fair Value Hierarchy
Assets	40	48
Liabilities	-86	-50
Recurring basis \| Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Non-Derivative Financial Instruments: Available-for-sale assets	62	47
Assets and liabilities, net	-554	-57
Recurring basis \| Significant Other Observable Inputs (Level II) \| Commodity contract \| Power
Fair Value Hierarchy
Assets	417	411
Liabilities	-551	-299
Recurring basis \| Significant Other Observable Inputs (Level II) \| Commodity contract \| Gas
Fair Value Hierarchy
Assets	24	25
Liabilities	-17	-22
Recurring basis \| Significant Other Observable Inputs (Level II) \| Foreign exchange contracts
Fair Value Hierarchy
Assets	7	5
Liabilities	-497	-230
Recurring basis \| Significant Other Observable Inputs (Level II) \| Interest rate contracts
Fair Value Hierarchy
Assets	7	14
Liabilities	-6	-8
Recurring basis \| Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and liabilities, net	4	1
Recurring basis \| Significant Unobservable Inputs (Level III) \| Commodity contract \| Power
Fair Value Hierarchy
Assets	2	4
Liabilities	-3	-3
Recurring basis \| Significant Unobservable Inputs (Level III) \| Commodity contract \| Gas
Fair Value Hierarchy
Assets	5

Recovered_Sheet2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details 10) (CAD)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Net change in the Level III fair value category
Decrease or increase in the fair value of outstanding derivative financial instruments included in Level III	1,000,000
Commodity contract \| Power
Net change in the Level III fair value category
Balance at beginning of year	1,000,000	-2,000,000
Transfers out of Level III	0	-2,000,000
Total gains/(losses) included in Net Income	3,000,000	-1,000,000
Total gains included in OCI	0	6,000,000
Balance at end of year	4,000,000	1,000,000
Commodity contract \| Power \| Level III
Net change in the Level III fair value category
Derivative Financial Instruments Specified Percentage of Increase (Decrease) in Commodity Prices Resulting in Change in Fair Value	10.00%
Energy Revenue
Net change in the Level III fair value category
Fair Value, Liabilities Measured on Recurring Basis, Change in Unrealized Gain (Loss)	3,000,000	0

Recovered_Sheet3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Counterparty Credit Risk) (Details)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2013
	USD ($)	CAD	USD ($)	CAD
Risk Management and Financial Instruments [Abstract]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$222	258	$225	240

CHANGES_IN_OPERATING_WORKING_C2

CHANGES IN OPERATING WORKING CAPITAL (Details) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CHANGES IN OPERATING WORKING CAPITAL
(Increase)/decrease in Accounts Receivable	-189	-54	67
(Increase)/decrease in Inventories	-28	-30	27
(Increase)/decrease in Other Current Assets	-385	40	66
Increase/(decrease) in Accounts Payable and Other	377	-290	127
Increase in Accrued Interest	36	8	0
(Increase)/Decrease in Operating Working Capital	-189	-326	287

ACQUISITIONS_AND_DISPOSITIONS_

ACQUISITIONS AND DISPOSITIONS (Details)

12 Months Ended

0 Months Ended

1 Months Ended

3 Months Ended

4 Months Ended

12 Months Ended

24 Months Ended

1 Months Ended

0 Months Ended

In Millions, except Share data, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Oct. 01, 2014

Jul. 31, 2013

Sep. 30, 2014

Dec. 31, 2014

Sep. 30, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2012

Dec. 31, 2013

Jul. 31, 2013

31-May-13

Dec. 31, 2014

Dec. 31, 2013

Apr. 30, 2013

Dec. 31, 2012

Apr. 15, 2014

Nov. 26, 2014

CAD

Natural Gas

Ontario solar projects

CrossAlta

Bison LLC

Gas Transmission Northwest LLC

TC PipeLines, LP

Cancarb Limited

Gas Pacifico and INNERGY

Bison LLC

GTN LLC and Bison LLC

Energy

Natural Gas

USD ($)

CAD

Disposal Group, Not Discontinued Operations

USD ($)

facility

CAD

facility

CAD

facility

CAD

facility

ACQUISITIONS AND DISPOSITIONS

Number of facilities acquired

Amount for which interest is acquired in cash, net of cash acquired

241

216

214

181

457

216

214

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

196

190

Business Acquisition, Percentage of Voting Interests Acquired

40.00%

Ownership interest after acquisition (as a percent)

100.00%

Ownership interest prior to acquisition (as a percent)

60.00%

Sale of Stock, Percentage of Ownership before Transaction

30.00%

45.00%

Proceeds from Sale of Equity Method Investments

215

1,050

Long-term debt included in aggregate purchase price

146

Percentage of acquired long-term debt

45.00%

Number of common units sold in an underwritten public offering (in shares)

8,855,000

Price per common unit issued (in dollars per unit)

$43.85

Partners' Capital Account, Public Sale of Units

388

Net proceeds from issuance of common units

373

Capital contribution made to maintain general partnership interest

General partnership interest (as a percent)

2.00%

Ownership interest in subsidiary (as a percent)

28.90%

28.30%

28.90%

33.30%

After-tax dilution gain recorded in additional paid-in capital

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

Ownership interest (as a percent)

30.00%

Proceeds from sale of assets

117

Proceeds from Disposition of Assets, Net Proceeds

COMMITMENTS_CONTINGENCIES_AND_2

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Details) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Minimum Lease Payments
2015	348
2016	335
2017	335
2018	250
2019	232
2020 and thereafter	407
Minimum Lease Payments	1,907
Amounts Recoverable under Sub-leases
2015	48
2016	47
2017	48
2018	27
2019	23
2020 and thereafter	20
Amounts Recoverable under Sub-leases	213
Net Payments
2015	300
2016	288
2017	287
2018	223
2019	209
2020 and thereafter	387
Net Payments	1,694
Rent Expense
Operating leases optional renewable terms, low end of range	1 year
Operating leases optional renewable terms, high end of range	5 years
Net rental expense on operating leases	114	98	84

COMMITMENTS_CONTINGENCIES_AND_3

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Details 2) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Alberta PPAs
Commitments under operating leases
Share of payments under PPAs	391	242	238
Sundance A
Commitments under operating leases
Power generating capacities under PPAs (in Megawatt)	560
Sheerness
Commitments under operating leases
Power generating capacities under PPAs (in Megawatt)	756

COMMITMENTS_CONTINGENCIES_AND_4

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Details 3) (CAD)	12 Months Ended
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Details 3) (CAD)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites	31,000,000	32,000,000	37,000,000
Natural Gas Pipelines \| Capital expenditures
Other Commitments
Commitment for capital expenditures	900,000,000	1,300,000,000
Liquids Pipelines \| Capital expenditures
Other Commitments
Commitment for capital expenditures	1,800,000,000	2,500,000,000
Energy \| Capital expenditures
Other Commitments
Commitment for capital expenditures	200,000,000	100,000,000

COMMITMENTS_CONTINGENCIES_AND_5

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Details 4) (Contingent financial obligation, CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Guarantees
Potential Exposure	738	791
Carrying Value	20	18
Bruce Power
Guarantees
Potential Exposure	634	740
Carrying Value	6	8
Bruce A
Guarantees
Percent of guarantee exposure	50.00%
Other
Guarantees
Potential Exposure	104	51
Carrying Value	14	10

SUBSEQUENT_EVENTS_Details

SUBSEQUENT EVENTS (Details) (TransCanada PipeLines Limited, Subsequent Event, CAD)	0 Months Ended
	Jan. 12, 2015	Jan. 12, 2015
Senior Notes, 1.88%, Due January 12, 2018
Subsequent Event [Line Items]
Notes offering, amount	500,000,000
Stated interest rate	1.88%	1.88%
Senior Notes, Floating Rate, Due January 12, 2018
Subsequent Event [Line Items]
Notes offering, amount	250,000,000