View Filing Data

Accounts payable and other (Note 13)

53,898

48,396

Current Liabilities

Notes payable (Note 12)

1,842

2,275

2,155

2,344

Accrued interest

388

368

Current portion of long-term debt (Note 15)

973

894

Total Current Liabilities

5,358

5,881

Regulatory Liabilities (Note 9)

229

268

Other Long-Term Liabilities (Note 14)

656

882

Deferred Income Tax Liabilities (Note 16)

4,564

4,016

Long-Term Debt (Note 15)

21,892

18,019

Junior Subordinated Notes (Note 17)

1,063

994

Total Liabilities

33,762

30,060

EQUITY

Common shares, no par value (Note 19) Issued and outstanding: December 31, 2013 - 707 million shares December 31, 2012 - 705 million shares

12,149

12,069

Preferred shares (Note 20)

^[1]

1,813

1,224

Additional paid-in capital

401

379

Retained earnings

5,096

4,687

Accumulated other comprehensive loss (Note 21)

^[2]

(934)

(1,448)

Controlling interests

18,525

16,911

Non-controlling interests (Note 18)

1,611

1,425

Total Equity

20,136

18,336

Total Liabilities and Equity

$ 53,898

$ 48,396

[1]	Net of underwriting commissions and deferred income taxes.
[2]	All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

CONSOLIDATED BALANCE SHEET (Parenthetical) - shares shares in Millions	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Common shares issued (in shares)	707	705
Common shares outstanding (in shares)	707	705

CONSOLIDATED STATEMENT OF EQUITY - CAD ($)
$ in Millions

Total

Equity Attributable to Controlling Interests

Common Shares

Preferred Shares

Additional Paid-In Capital

Retained Earnings

Accumulated Other Comprehensive Loss

Equity Attributable to Non-Controlling Interests

TC PipeLines, LP

Equity Attributable to Non-Controlling Interests

TRANSCANADA PIPELINES LIMITED

Equity Attributable to Non-Controlling Interests

Portland

^[2]

Balance at Dec. 31, 2010

$ 11,745

$ 1,224

$ 349

$ 4,282

$ (1,243)

$ 1,157

Increase (decrease) in equity

Shares issued under dividend reinvestment plan (Note 19)

$ 202

202

Shares issued on exercise of stock options (Note 19)

Shares issued under public offering, net of issue costs

Issuance of stock options, net of exercises

Dilution impact from TC PipeLines, LP units issued (Note 25)

$ 321

Net income attributable to controlling interests

1,581

Common share dividends

(1,180)

Preferred share dividends

(55)

Other comprehensive income/(loss)

(171)

(206)

Net income attributable to non-controlling interests

101

Net income attributable to non-controlling interests

$ 22

129

101

^[1]

$ 6

Other comprehensive income/(loss) attributable to non-controlling interests

Issuance of TC PipeLines, LP units

Decrease in TransCanada's ownership of TC PipeLines, LP

(50)

Distributions declared to non-controlling interests

(131)

Redemption of subsidiary's preferred shares

Foreign exchange and other

Balance at Dec. 31, 2011

18,259

$ 16,794

12,011

1,224

380

4,628

(1,449)

1,465

Increase (decrease) in equity

Shares issued under dividend reinvestment plan (Note 19)

Shares issued on exercise of stock options (Note 19)

Shares issued under public offering, net of issue costs

Issuance of stock options, net of exercises

(1)

Dilution impact from TC PipeLines, LP units issued (Note 25)

Net income attributable to controlling interests

1,354

Common share dividends

(1,240)

Preferred share dividends

(55)

Other comprehensive income/(loss)

(20)

Net income attributable to non-controlling interests

Net income attributable to non-controlling interests

118

^[1]

Other comprehensive income/(loss) attributable to non-controlling interests

(21)

Issuance of TC PipeLines, LP units

Decrease in TransCanada's ownership of TC PipeLines, LP

Distributions declared to non-controlling interests

(135)

Redemption of subsidiary's preferred shares

Foreign exchange and other

(2)

Balance 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 under dividend reinvestment plan (Note 19)

Shares issued on exercise of stock options (Note 19)

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)

384

Net income attributable to controlling interests

1,786

Common share dividends

(1,301)

Preferred share dividends

(76)

Other comprehensive income/(loss)

580

514

Net income attributable to non-controlling interests

Net income attributable to non-controlling interests

$ 20

125

^[1]

$ 12

Other comprehensive income/(loss) attributable to non-controlling interests

Issuance of TC PipeLines, LP units

Decrease in TransCanada's ownership of TC PipeLines, LP

$ (47)

Distributions declared to non-controlling interests

(166)

Redemption of subsidiary's preferred shares

(195)

(5)

Foreign exchange and other

Balance at Dec. 31, 2013

$ 20,136

$ 18,525

$ 12,149

$ 1,813

$ 401

$ 5,096

$ (934)

$ 1,611

[1]

In May 2013, the non-controlling interest in TC PipeLines, LP increased from 66.7 per cent to 71.1 per cent due to the issuance of equity to non-controlling interests in TC PipeLines, LP. In July 2013, TransCanada sold 45 per cent interests in GTN LLC and Bison LLC to TC PipeLines, LP (See Note 25). The non-controlling interest in TC PipeLines, LP from January 2010 to May 2011 was 61.8 per cent and 66.7 per cent from May 2011 to May 2013.

[2]

The non-controlling interest in Portland as at December 31, 2013 represented the 38.3 per cent interest not owned by TransCanada (2012 and 2011 - 38.3 per cent).

DESCRIPTION OF TRANSCANADA'S BUSINESS

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

DESCRIPTION OF TRANSCANADA'S BUSINESS

TransCanada Corporation (TransCanada or the Company) is a leading North American energy company which operates in three business segments, Natural Gas Pipelines, Oil 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 regulated natural gas pipelines and regulated natural gas storage facilities. Through its Natural Gas Pipelines segment, TransCanada owns and operates:


•	a natural gas transmission system extending from the Alberta/Saskatchewan border, east into Québec (Canadian Mainline);


•	a natural gas transmission system in Alberta and northeastern B.C. (NGTL System);


•	a natural gas transmission system extending from producing fields primarily located in Texas, Oklahoma, the Gulf of Mexico and Louisiana to markets primarily located in Wisconsin, Michigan, Illinois, Ohio and Indiana, and includes regulated natural gas storage facilities in Michigan (ANR);


•	a natural gas transmission system extending from central Alberta to the B.C./Idaho border and to the Saskatchewan/Montana border (Foothills);


•	natural gas transmission systems in Alberta that supply natural gas to the oil sands region of northern Alberta and to a petrochemical complex at Joffre, Alberta (Ventures LP);


•	a natural gas transmission system in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi (Tamazunchale); and


•	a natural gas transmission system in Mexico extending from Manzanillo, Colima to Guadalajara, Jalisco (Guadalajara).

Through its Natural Gas Pipelines segment, TransCanada operates and has ownership interests in natural gas pipeline systems as follows:


•	a 53.6 per cent direct ownership interest in a natural gas transmission system that connects to the Canadian Mainline and serves markets in eastern Canada and the northeastern and midwestern U.S. (Great Lakes);


•	a 30 per cent direct ownership interest in a natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border (GTN);


•	a 30 per cent direct ownership interest in a natural gas transmission system extending from the Powder River Basin in Wyoming to Northern Border in North Dakota (Bison);


•	a 61.7 per cent interest in a natural gas transmission system that extends from a point near East Hereford, Québec, to the northeastern U.S. (Portland);


•	a 50 per cent interest in a natural gas transmission system that connects with the Canadian Mainline near the Québec/Ontario border and transports natural gas to markets in Québec and to the Portland system (TQM); and


•	a 28.9 per cent controlling interest in TC PipeLines, LP, which has the following ownership interests in pipelines operated by TransCanada:


•	a 46.4 per cent interest in Great Lakes, in which TransCanada has a combined 67 per cent effective ownership interest through TC PipeLines, LP and a direct interest described above;


•	a 50 per cent interest in a natural gas transmission system extending from a point near Monchy, Saskatchewan, to the U.S. Midwest (Northern Border), in which TransCanada has a 14.5 per cent effective ownership interest through TC PipeLines, LP;


•	a 70 per cent interest in GTN, in which TransCanada has a combined 50.2 per cent effective ownership interest through TC PipeLines, LP and a direct interest described above;


•	a 70 per cent interest in Bison, in which TransCanada has a combined 50.2 per cent effective ownership interest through TC PipeLines, LP and a direct interest described above;


•	a 100 per cent interest in a natural gas transmission system extending from Arizona to Baja California at the Mexico/California border (North Baja), in which TransCanada has a 28.9 per cent effective ownership interest through TC PipeLines, LP; and


•	a 100 per cent interest in a natural gas transmission system extending from Malin, Oregon, to Wadsworth, Nevada (Tuscarora), in which TransCanada has a 28.9 per cent effective ownership interest through TC PipeLines, LP.

TransCanada has a 44.5 per cent ownership interest in a natural gas pipeline transmission system that connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to customers in the northeastern U.S. (Iroquois). TransCanada does not operate this pipeline.

TransCanada is currently constructing natural gas pipeline systems in Mexico as follows:


•	an extension to the Tamazunchale pipeline from Tamazunchale, San Luis Potosi to El Sauz, Queretaro;


•	a natural gas transmission system that will transport natural gas from El Encino, Chihuahua to Topolobampo, Sinaloa (Topolobampo); and


•	a natural gas transmission system that will transport natural gas from El Oro to Mazatlan, Sinaloa (Mazatlan).

TransCanada is currently developing the following natural gas pipeline systems:


•	the proposed Coastal GasLink project consisting of a natural gas transmission system that will transport natural gas from the Montney gas-producing region near Dawson Creek, B.C. to a liquefied natural gas (LNG) export facility near Kitimat, B.C.; and


•	the proposed Prince Rupert Gas Transmission project consisting of a pipeline to deliver natural gas from the Fort St. John area of B.C. to the proposed Pacific Northwest LNG facility at Port Edward near Prince Rupert, B.C.

Oil Pipelines

The Oil Pipelines segment consists of a wholly owned and operated crude oil pipeline system which connects Alberta crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas (Keystone Pipeline System).

TransCanada is currently constructing oil pipeline infrastructure as follows:


•	a crude oil pipeline to connect the crude oil hub at Cushing, Oklahoma to the U.S. Gulf Coast refining market (Gulf Coast project);


•	the Cushing Marketlink receipt facilities that will transport crude oil supply from the market hub at Cushing, Oklahoma to the U.S. Gulf Coast on facilities that form part of the Keystone Pipeline System; and


•	a crude oil terminal to be located at Hardisty, Alberta (Keystone Hardisty Terminal) that will provide Western Canadian producers with new batch accumulation tankage and pipeline infrastructure and access to the Keystone Pipeline System.

TransCanada is currently developing oil pipeline infrastructure as follows:


•	a new crude oil pipeline from Hardisty, Alberta to Steele City, Nebraska (Keystone XL), subject to regulatory approval;


•	the Bakken Marketlink project that will transport crude oil supply from the Williston Basin in North Dakota and Montana to Cushing, Oklahoma on facilities that form part of Keystone XL;


•	the Energy East Pipeline that will transport crude oil from western Canada to eastern refineries and export terminals. This project will include conversion of certain Canadian Mainline natural gas assets to crude oil service;


•	the Heartland Pipeline and TC Terminals projects that will include a crude oil pipeline connecting the Edmonton and Hardisty, Alberta market regions and a terminal facility in the Heartland industrial area north of Edmonton;


•	the Northern Courier Pipeline, a pipeline that will transport bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal facilities located north of Fort McMurray, Alberta; and


•	the Grand Rapids Pipeline in northern Alberta, which includes both crude oil and diluent lines to transport volumes between the producing area northwest of Fort McMurray and the Edmonton/Heartland region. The Company has entered into a joint venture agreement with a third party to develop the pipeline.

Energy

The Energy segment primarily consists of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities. Through its Energy segment, the Company owns and operates:


•	a natural gas and oil-fired generating facility in Queens, New York, consisting of multiple units employing steam turbine, combined-cycle and combustion turbine technology (Ravenswood);


•	a natural gas-fired, combined-cycle power plant in Halton Hills, Ontario (Halton Hills);


•	hydroelectric generation assets located in New Hampshire, Vermont and Massachusetts (TC Hydro);


•	a natural gas-fired peaking facility located near Phoenix, Arizona (Coolidge);


•	a natural gas-fired, combined-cycle plant in Burrillville, Rhode Island (Ocean State Power);


•	a natural gas-fired cogeneration plant near Trois-Rivières, Québec (Bécancour);


•	natural gas-fired cogeneration plants in Alberta at Carseland, Redwater, Bear Creek and MacKay River;


•	a wind farm located in Kibby and Skinner townships in northwestern Franklin County, Maine (Kibby Wind);


•	a natural gas-fired cogeneration plant near Saint John, New Brunswick (Grandview);


•	a waste-heat fueled power plant and the Cancarb thermal carbon black facility in Medicine Hat, Alberta (Cancarb);


•	a natural gas storage facility near Edson, Alberta (Edson);


•	an underground natural gas storage facility near Crossfield, Alberta (CrossAlta); and


•	four solar facilities in Ontario (Ontario Solar).

TransCanada does not operate but has ownership interests in power generation plants as follows:


•	a 48.9 per cent partnership interest and a 31.6 per cent partnership interest in the nuclear power generation facilities of Bruce A and Bruce B (collectively Bruce Power), respectively, located near Tiverton, Ontario;


•	a 62 per cent interest in the Baie-des-Sables, Anse-à-Valleau, Carleton, Montagne-Sèche and Gros-Morne wind farms in Gaspé, Québec (Cartier Wind); and


•	a 50 per cent interest in a natural gas-fired, combined-cycle plant in Toronto, Ontario (Portlands Energy).

TransCanada has long-term power purchase arrangements (PPA) in place for:


•	a 100 per cent interest in the Sheerness power facility near Hanna, Alberta;


•	a 100 per cent interest in the Sundance A power facilities near Wabamun, Alberta

In addition, TransCanada has a 50 per cent interest in the ASTC Power Partnership which holds a PPA for a 100 per cent interest in the Sundance B power facilities near Wabamun, Alberta.

TransCanada is currently constructing a natural gas-fired power plant at Ontario Power Generation's Lennox site in Greater Napanee, Ontario (Napanee).

TransCanada also has agreed to purchase an additional five Ontario solar facilities in 2014.

ACCOUNTING POLICIES	12 Months Ended
ACCOUNTING POLICIES	Dec. 31, 2013
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 Judgements 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 judgement in making these estimates and assumptions. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies summarized below. Regulation In Canada, regulated natural gas pipelines and oil pipelines are subject to the authority of the National Energy Board (NEB) of Canada. In the U.S., natural gas pipelines, oil 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. The Company's Canadian and U.S. 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 and U.S. natural gas pipelines and regulated U.S. natural gas storage. RRA is not applicable to the Keystone Pipeline System and the Company's Mexican natural gas pipelines and, as a result, the regulators' decisions regarding operations and tolls on these pipelines generally do not have an impact on timing of recognition of revenues and expenses. Revenue Recognition Natural Gas and Oil Pipelines Revenues from the Company's natural gas and oil pipelines, with the exception of Canadian natural gas pipelines which are subject to rate regulation, 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 rate regulation 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 an appropriate 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. The cost of 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. 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. Oil Pipelines Plant, property and equipment for oil 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. When oil 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 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. The PPAs under which TransCanada buys power are accounted for as operating leases. The 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 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, oil 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. 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 period 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 period 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 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. Guarantees are recorded as an increase to Equity Investments, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Other Long-Term Liabilities.

ACCOUNTING CHANGES	12 Months Ended
ACCOUNTING CHANGES	Dec. 31, 2013
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES Changes in Accounting Policies for 2013 Balance Sheet Offsetting/Netting Effective January 1, 2013, the Company adopted the Accounting Standards Update (ASU) on disclosures about balance sheet offsetting as issued by the Financial Accounting Standards Board (FASB) to enable readers to evaluate the effects of netting arrangements on the Company’s financial position. Adoption of the ASU has resulted in increased qualitative and quantitative disclosures regarding certain derivative instruments that are either offset in accordance with current GAAP or are subject to a master netting arrangement or similar agreement. These disclosures have been included in Note 23, Risk Management and Financial Instruments. Accumulated Other Comprehensive Income Effective January 1, 2013, the Company adopted the ASU on reporting of amounts reclassified out of AOCI as issued by the FASB. Adoption of the ASU has resulted in providing additional qualitative and quantitative disclosures regarding significant amounts reclassified out of AOCI into net income. These disclosures have been included in Note 21, Other Comprehensive Income and Accumulated Other Comprehensive Loss. Future Accounting Changes Obligations Resulting from Joint and Several Liability Arrangements In February 2013, the FASB issued guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. Examples of obligations within the scope of this ASU include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. This ASU is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. 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 ASU is effective prospectively for fiscal years, and interim reporting periods within those years, beginning after December 15, 2013. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. 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 ASU is effective prospectively for fiscal years and interim reporting periods within those years, beginning after December 15, 2013. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

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

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

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

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
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-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=28359718&loc=d3e22580-107794

Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
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-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=28359718&loc=d3e22499-107794

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

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
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-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e765-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-SubTopic 10
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-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e725-108305

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 01
-Paragraph b
-Subparagraph 6
-Article 10

SEGMENTED INFORMATION

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

SEGMENTED INFORMATION



year ended December 31, 2013 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines		Energy		Corporate		Total
Revenues	4,497		1,124		3,176		—		8,797
Income from Equity Investments	145		—		452		—		597
Plant Operating Costs and Other	(1,405	)	(328	)	(833	)	(108	)	(2,674	)
Commodity Purchases Resold	—		—		(1,317	)	—		(1,317	)
Property Taxes	(329	)	(44	)	(72	)	—		(445	)
Depreciation and Amortization	(1,027	)	(149	)	(293	)	(16	)	(1,485	)
	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



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



year ended December 31, 2011 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines¹		Energy		Corporate		Total
Revenues	4,244		827		2,768		—		7,839
Income from Equity Investments	159		—		256		—		415
Plant Operating Costs and Other	(1,221	)	(209	)	(842	)	(86	)	(2,358	)
Commodity Purchases Resold	—		—		(991	)	—		(991	)
Property Taxes	(307	)	(31	)	(72	)	—		(410	)
Depreciation and Amortization	(923	)	(130	)	(261	)	(14	)	(1,328	)
	1,952		457		858		(100	)	3,167
Interest Expense									(937	)
Interest Income and Other									55
Income before Income Taxes									2,285
Income Tax Expense									(575	)
Net Income									1,710
Net Income Attributable to Non-Controlling Interests									(129	)
Net Income Attributable to Controlling Interests									1,581
Preferred Share Dividends									(55	)
Net Income Attributable to Common Shares									1,526


1	Commencing in February 2011, TransCanada began recording earnings for the Keystone Pipeline System.

Total Assets



at December 31 (millions of Canadian dollars)	2013	2012
Natural Gas Pipelines	25,165	23,210
Oil Pipelines	13,253	10,485
Energy	13,747	13,157
Corporate	1,733	1,544
	53,898	48,396

Geographic Information



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Revenues
Canada – domestic	4,659	3,527	3,929
Canada – export	997	1,121	1,087
United States	3,029	3,252	2,752
Mexico	112	107	71
	8,797	8,007	7,839



at December 31 (millions of Canadian dollars)	2013	2012
Plant, Property and Equipment
Canada	18,462	18,054
United States	17,570	14,904
Mexico	1,574	755
	37,606	33,713

Capital Expenditures



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Natural Gas Pipelines	1,776	1,389	917
Oil Pipelines	2,483	1,145	1,204
Energy	152	24	384
Corporate	50	37	8
	4,461	2,595	2,513

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
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OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2013

Other Assets [Abstract]

OTHER CURRENT ASSETS



at December 31 (millions of Canadian dollars)	2013	2012
Fair value of derivative contracts (Note 23)	395	259
Deferred income tax assets (Note 16)	119	290
Assets held for sale (Note 6)	85	—
Regulatory Assets (Note 9)	42	178
Other	206	270
	847	997

ASSETS HELD FOR SALE

12 Months Ended

Dec. 31, 2013

ASSETS HELD FOR SALE



at December 31 (millions of Canadian dollars)		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)		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

We classify assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and we expect the sale to close within the next twelve months. Upon classifying an asset as held for sale, we record the asset at the lower of its carrying amount or its estimated fair value, reduced for selling costs, and we stop recording depreciation expense on the asset.

At December 31, 2013, the Company classified Cancarb Limited and its related power generation facility as assets held for sale. The assets were recorded at their carrying amount at December 31, 2013. These assets and the related liabilities are recorded in the Energy Segment.

On January 20, 2014, the Company reached an agreement to sell these assets for aggregate gross proceeds of $190 million. Please refer to the Subsequent Events note (Note 27) for further details.

PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2013

PLANT, PROPERTY AND EQUIPMENT



	2013			2012
at December 31 (millions of Canadian dollars)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
Natural Gas Pipelines¹
Canadian Mainline
Pipeline	8,970	5,457	3,513	8,801	5,192	3,609
Compression	3,392	1,961	1,431	3,370	1,880	1,490
Metering and other	409	174	235	391	182	209
	12,771	7,592	5,179	12,562	7,254	5,308
Under construction	85	—	85	163	—	163
	12,856	7,592	5,264	12,725	7,254	5,471
NGTL System
Pipeline	7,813	3,410	4,403	7,214	3,221	3,993
Compression	2,038	1,253	785	1,885	1,177	708
Metering and other	947	418	529	958	420	538
	10,798	5,081	5,717	10,057	4,818	5,239
Under construction	290	—	290	463	—	463
	11,088	5,081	6,007	10,520	4,818	5,702
ANR
Pipeline	922	59	863	864	49	815
Compression	635	81	554	514	72	442
Metering and other	535	91	444	520	81	439
	2,092	231	1,861	1,898	202	1,696
Under construction	67	—	67	63	—	63
	2,159	231	1,928	1,961	202	1,759
Other Natural Gas Pipelines
GTN	1,685	488	1,197	1,565	411	1,154
Great Lakes	1,650	833	817	1,544	750	794
Foothills	1,649	1,120	529	1,634	1,062	572
Mexico	641	90	551	536	59	477
Other²	1,652	288	1,364	1,548	226	1,322
	7,277	2,819	4,458	6,827	2,508	4,319
Under construction	1,047	—	1,047	297	—	297
	8,324	2,819	5,505	7,124	2,508	4,616
	34,427	15,723	18,704	32,330	14,782	17,548
Oil Pipelines
Keystone
Pipeline	5,079	286	4,793	4,828	177	4,651
Pumping equipment	1,118	82	1,036	1,066	51	1,015
Tanks and other	962	71	891	935	47	888
	7,159	439	6,720	6,829	275	6,554
Under construction³	6,020	—	6,020	3,678	—	3,678
	13,179	439	12,740	10,507	275	10,232
Energy
Natural Gas – Ravenswood	1,966	377	1,589	1,799	290	1,509
Natural Gas – Other^4,5	3,061	846	2,215	2,975	746	2,229
Hydro	673	126	547	634	106	528
Wind	946	155	791	907	118	789
Natural Gas Storage	677	92	585	677	83	594
Solar⁶	226	2	224	—	—	—
Other	57	30	27	134	86	48
	7,606	1,628	5,978	7,126	1,429	5,697
Under construction	54	—	54	136	—	136
	7,660	1,628	6,032	7,262	1,429	5,833
Corporate	191	61	130	154	54	100
	55,457	17,851	37,606	50,253	16,540	33,713


1	In 2013, the Company capitalized $37 million (2012 – $32 million) relating to the equity portion of AFUDC for natural gas pipelines with a corresponding amount recorded in Interest Income and Other.


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


3	Includes $2.6 billion for Keystone XL at December 31, 2013 (2012 – $2 billion). Keystone XL remains subject to regulatory approvals.

Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $640 million and $78 million, respectively, at December 31, 2013 (2012 – $601 million and $55 million, respectively). Revenues of $78 million were recognized in 2013 (2012 – $73 million; 2011 – $53 million) through the sale of electricity under the related PPAs.


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


6	Includes the acquisitions in 2013 of four solar power facilities.

EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2013

Equity Method Investments and Joint Ventures [Abstract]

EQUITY INVESTMENTS



(millions of Canadian dollars)	Ownership Interest at December 31, 2013		Income/(Loss) from Equity Investments				Equity Investments
			year ended December 31				at December 31
			2013	2012		2011	2013	2012
Natural Gas Pipelines
Northern Border^1,2			66	72		75	557	511
Iroquois	44.5	%	41	41		40	188	174
TQM	50.0	%	13	16		17	76	80
Other	Various		25	28		27	62	60
Energy
Bruce A³	48.9	%	202	(149	)	33	3,988	4,033
Bruce B³	31.6	%	108	163		77	377	69
ASTC Power Partnership	50.0	%	110	40		84	41	42
Portlands Energy	50.0	%	31	28		33	343	341
Other⁴	Various		1	18		29	57	54
Oil Pipelines
Grand Rapids⁵	50.0	%	—	—		—	70	2
			597	257		415	5,759	5,366


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, 2013, TransCanada had an ownership interest in TC PipeLines, LP of 28.9 per cent (2012 and 2011 – 33.3 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.5 per cent (2012 and 2011 – 16.7 per cent).


2	At December 31, 2013, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$118 million (2012 – US$119 million) due to the fair value assessment of assets at the time of acquisition.


3	At December 31, 2013, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $820 million (2012 – $889 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.


5	In October 2012, TransCanada entered into a joint venture agreement with a third party to build this pipeline system to transport crude oil and diluent between the producing area northwest of Fort McMurray and the Edmonton/Heartland market region.

Distributions received from equity investments for the year ended December 31, 2013 were $725 million (2012 – $436 million; 2011 – $494 million) of which $120 million (2012 – $60 million; 2011 – $101 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, 2013 were $754 million (2012 – $883 million; 2011 – $1,062 million).

Summarized Financial Information of Equity Investments



year ended December 31 (millions of Canadian dollars)	2013		2012		2011
Income
Revenues	4,989		3,860		4,042
Operating and Other Expenses	(3,536	)	(3,090	)	(2,989	)
Net Income	1,390		717		929
Net Income attributable to TransCanada	597		257		415



at December 31 (millions of Canadian dollars)	2013		2012
Balance Sheet
Current assets	1,500		1,593
Non current assets	12,158		12,154
Current liabilities	(1,117	)	(1,187	)
Non current liabilities	(2,507	)	(3,787	)

RATE-REGULATED BUSINESSES

12 Months Ended

Dec. 31, 2013

Regulated Operations [Abstract]

RATE-REGULATED BUSINESSES

TransCanada's businesses that apply RRA currently include Canadian and U.S. natural gas pipelines and regulated U.S. natural gas storage. 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 revenues for the upcoming year or multiple years. To the extent that actual costs and revenues are more or less than the forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur.

Canadian Mainline

In March 2013, TransCanada received a decision from the NEB on the comprehensive application it filed to change the business structure and the terms and conditions of service for the Canadian Mainline, including addressing tolls for 2012 and 2013 (the NEB Decision). The decision approved the 2011 revenue requirement as filed, approved tolls charged in 2012 as final with any variance between revenues and costs deferred for recovery in future years, and set tolls for 2013 through 2017 at competitive levels, fixing tolls for some services and providing unlimited pricing discretion for others. 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 Long Term Adjustment Account (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 provides 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 is if the TSA balance becomes positive, which occurred in 2013. In December 2013, TransCanada filed an application with the NEB that addresses tolls moving forward.

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. In 2011, the Canadian Mainline operated under a five year settlement which expired in December 2011. This settlement included an allowed ROE of 8.08 per cent on a deemed common equity of 40 per cent and also allowed for incentive earnings.

NGTL System

On November 1, 2013, the NEB approved 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 10.10 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 2014.

In September 2010, the NEB approved the NGTL System’s 2010-2012 Revenue Requirement Settlement Application. The settlement provided for a 9.70 per cent ROE on a deemed common equity of 40 per cent and fixed certain annual OM&A costs during the term. Any variances between actual costs and those agreed to in the settlement accrued to TransCanada. All other costs were treated on a flow-through basis.

Other Canadian Pipelines

The Foothills operating model for 2012 and 2013 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 and 2013. 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 for 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 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 a FERC-approved tariff that establishes 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 is required to file a cost and revenue study to justify its existing, approved cost-based rates after its first three years of operations. This is expected to be filed by April 2014.

Regulatory Assets and Liabilities



at December 31 (millions of Canadian dollars)	2013	2012	Remaining Recovery/ Settlement Period (years)


Regulatory Assets
Deferred income taxes¹	1,149	1,122	n/a
Operating and debt-service regulatory assets²	16	171	1
Long Term Adjustment Account³	354	80	31
Other⁴	258	434	n/a
	1,777	1,807
Less: Current portion included in Other Current Assets (Note 5)	42	178
	1,735	1,629
Regulatory Liabilities
Foreign exchange on long-term debt⁵	84	150	1-16
Operating and debt-service regulatory liabilities²	5	84	1
Other⁴	147	134	n/a
	236	368
Less: Current portion included in Accounts Payable and Other (Note 13)	7	100
	229	268


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

Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar year. Pre-tax operating results in 2013 would have been $76 million higher (2012 – $50 million lower; 2011 - $102 million higher) had these amounts not been recorded as regulatory assets and liabilities.

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


4	Pre-tax operating results in 2013 would have been $189 million higher (2012 – $13 million higher; 2011 - $106 million lower) had these amounts not been recorded as regulatory assets and liabilities.

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.

GOODWILL

12 Months Ended

Dec. 31, 2013

GOODWILL

GOODWILL

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



(millions of Canadian dollars)	Natural Gas Pipelines		Energy		Total
Balance at January 1, 2012	2,693		841		3,534
Foreign exchange rate changes	(58	)	(18	)	(76	)
Balance at December 31, 2012	2,635		823		3,458
Foreign exchange rate changes	181		57		238
Balance at December 31, 2013	2,816		880		3,696

INTANGIBLE AND OTHER ASSETS

12 Months Ended

Dec. 31, 2013

INTANGIBLES AND OTHER ASSETS

INTANGIBLES AND OTHER ASSETS

INTANGIBLE AND OTHER ASSETS



at December 31 (millions of Canadian dollars)	2013	2012
Capital projects under development	571	34
PPAs	324	376
Deferred income tax assets and charges (Note 16)	225	168
Loans and advances¹	183	196
Fair value of derivative contracts (Note 23)	112	187
Employee post-retirement benefits (Note 22)	16	11
Other	524	434
	1,955	1,406


1	As at December 31, 2013, TransCanada held a $226 million (2012 – $236 million) note receivable from the seller of Ravenswood which bears interest at 6.75 per cent and matures in 2040. The current portion of the note receivable of $43 million (2012 – $40 million) is included in Other Current Assets.

The following amounts related to PPAs are included in Intangible and Other Assets:



	2013			2012
at December 31 (millions of Canadian dollars)	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
Sheerness	585	312	273	585	273	312
Sundance A	225	174	51	225	161	64
	810	486	324	810	434	376

Amortization expense for these PPAs was $52 million for the year ended December 31, 2013 (2012 and 2011 – $52 million). The expected annual amortization expense for 2014 to 2017 is $52 million and in 2018 is $39 million.

Sundance A

In December 2010, Sundance A Units 1 and 2 were withdrawn from service and were subject to a force majeure claim by TransAlta Corporation. In January 2011, TransCanada disputed this claim which was then subject to arbitration. In July 2012, TransCanada received the binding arbitration decision. The arbitration panel determined that the PPA should not be terminated and ordered TransAlta Corporation to return Units 1 and 2 to service. Unit 1 returned to service in September 2013, followed by Unit 2 in October 2013.

Between December 2010 and March 2012, TransCanada recorded revenues and costs related to the Sundance A PPA as though the outages of Units 1 and 2 were interruptions of supply. As a result of the above decision, TransCanada recorded a $50 million pre-tax charge in 2012, comprised of $20 million and $30 million previously accrued in 2011 and 2012, respectively, as these amounts were no longer recoverable.

NOTES PAYABLE

12 Months Ended

Dec. 31, 2013

Short-term Debt [Abstract]

NOTES PAYABLE



	2013			2012
(millions of Canadian dollars)	Outstanding December 31	Weighted Average Interest Rate per Annum at December 31		Outstanding December 31	Weighted Average Interest Rate per Annum at December 31
Canadian dollars	751	1.2	%	803	1.2	%
U.S. dollars (2013 – US$1,025; 2012 – US$1,480)	1,091	0.3	%	1,472	0.4	%
	1,842			2,275

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 line-of-credit and demand facilities. The TC Keystone facility expired in November 2013. The cost to maintain the facility was $1.4 million in 2013 (2012 - $1 million; 2011 - $4 million).

At December 31, 2013, total committed revolving and demand credit facilities of $6.2 billion (2012 - $5.3 billion) were available. When drawn, interest on the lines of credit is charged at prime rates of Canadian chartered and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:



					year ended December 31
at December 31, 2013					2013	2012	2011
Amount	Unused Capacity	Borrower	For	Matures	Cost to maintain
					(millions of Canadian dollars)
$3 billion	$3 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility	December 2018	4	4	2
US$1 billion	US$0.8 billion	TCPL USA	Committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL	November 2014	1	1	4
US$1 billion	US$1 billion	TAIL	Committed, syndicated, revolving, extendible TAIL credit facility, guaranteed by TCPL	November 2014	—	—	—
$1.1 billion	$0.3 billion	TCPL	Supports the issuance of letters of credit and provides additional liquidity	Demand	—	—	—

ACCOUNTS PAYABLE AND OTHER

12 Months Ended

Dec. 31, 2013

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE AND OTHER



at December 31 (millions of Canadian dollars)	2013	2012
Trade payables	866	923
Fair value of derivative contracts (Note 23)	357	283
Dividends payable	338	320
Deferred Income Tax Liabilities (Note 16)	26	—
Regulatory Liabilities (Note 9)	7	100
Liabilities related to assets held for sale (Note 6)	5	—
Other	556	718
	2,155	2,344

OTHER LONG-TERM LIABILITIES

12 Months Ended

Dec. 31, 2013

Deferred Costs, Noncurrent [Abstract]

OTHER LONG-TERM LIABILITIES



at December 31 (millions of Canadian dollars)	2013	2012
Employee post-retirement benefit (Note 22)	244	482
Fair value of derivative contracts (Note 23)	255	186
Asset retirement obligations	83	72
Guarantees (Note 26)	18	17
Other	56	125
	656	882

LONG-TERM DEBT

12 Months Ended

Dec. 31, 2013

Long-term Debt, Unclassified [Abstract]

LONG-TERM DEBT



		2013			2012
Outstanding loan amounts (millions of Canadian dollars)	Maturity Dates	Outstanding December 31	Interest Rate¹		Outstanding December 31	Interest Rate¹
TRANSCANADA PIPELINES LIMITED
Debentures
Canadian dollars	2014 to 2020	874	10.9	%	874	10.9	%
U.S. dollars (2013 and 2012 US$400)	2021	425	9.9	%	398	9.9	%
Medium-Term Notes
Canadian dollars	2014 to 2041	4,799	5.7	%	4,549	5.9	%
Senior Unsecured Notes
U.S. dollars (2013 – US$12,276; 2012 – US$10,126)	2015 to 2043	13,027	5.0	%	10,057	5.6	%
		19,125			15,878
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian dollars	2014 to 2024	378	11.5	%	382	11.5	%
U.S. dollars (2013 and 2012 – US$200)	2023	213	7.9	%	199	7.9	%
Medium-Term Notes
Canadian dollars	2025 to 2030	504	7.4	%	504	7.4	%
U.S. dollars (2013 and 2012 – US$33)	2026	34	7.5	%	32	7.5	%
		1,129			1,117
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. dollars (2013 and 2012 – US$432)	2021 to 2025	459	8.9	%	430	8.9	%
GAS TRANSMISSION NORTHWEST CORPORATION
Senior Unsecured Notes
U.S. dollars (2013 and 2012 – US$325)	2015 to 2035	346	5.5	%	323	5.5	%
TC PIPELINES, LP
Unsecured Loan
U.S. dollars (2013 – US$380; 2012 – US$312)	2017	404	1.4	%	310	1.5	%
Medium-Term Loan
U.S. dollars (2013 - US$500)	2018	532	1.4	%	—	—
Senior Unsecured Notes
U.S. dollars (2013 and 2012 – US$350)	2021	372	4.7	%	348	4.7	%
		1,308			658
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. dollars (2013 – US$335; 2012 – US$354)	2018 to 2030	356	7.8	%	352	7.8	%
TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
U.S. dollars (2013 – US$24; 2012 – US$27)	2017	25	4.0	%	27	4.0	%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes²
U.S. dollars (2013 – US$110; 2012 – US$129)	2018	117	6.1	%	128	6.1	%
		22,865			18,913
Less: Current Portion of Long-Term Debt		973			894
		21,892			18,019


1	Interest rates are the effective interest rates except for those pertaining to Long-Term Debt issued for the Company's Canadian regulated 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	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)	2014	2015	2016	2017	2018
Principal repayments on Long-Term Debt	973	1,659	2,092	862	1,632

TransCanada PipeLines Limited

In October 2013, TCPL issued US$625 million and US$625 million of Senior Unsecured Notes maturing October 16, 2023 and October 16, 2043, respectively, and bearing interest at 3.75 per cent and 5.00 per cent, respectively.

In August 2013, TCPL retired US$500 million of 5.05 per cent Senior Unsecured Notes.

In July 2013, TCPL issued US$500 million of London Interbank Offered Rate-based floating rate notes maturing on June 30, 2016, bearing interest at an initial annual rate of 0.95 per cent.

Also in July 2013, TCPL issued $450 million and $300 million of Medium-Term Notes maturing on July 19, 2023 and November 15, 2041, respectively, and bearing interest at rates of 3.69 and 4.55 per cent per annum, respectively.

In June 2013, TCPL retired US$350 million of 4.0 per cent Senior Unsecured Notes.

In January 2013, TCPL issued US$750 million of Senior Unsecured Notes maturing January 15, 2016 and bearing interest at 0.75 per cent.

In August 2012, TCPL issued US$1 billion of Senior Unsecured Notes maturing August 1, 2022 and bearing interest at 2.5 per cent.

In May 2012, TCPL retired US$200 million of 8.625 per cent Senior Unsecured Notes.

In March 2012, TCPL issued US$500 million of Senior Unsecured Notes maturing March 2, 2015 and bearing interest at 0.875 per cent.

In November 2011, TCPL issued $500 million and $250 million of Medium-Term Notes maturing November 15, 2021 and November 15, 2041, respectively, and bearing interest at 3.65 per cent and 4.55 per cent, respectively.

In May 2011, TCPL retired $60 million of 9.5 per cent Medium-Term Notes.

In January 2011, TCPL retired $300 million of 4.3 per cent Medium-Term Notes.

NOVA Gas Transmission Ltd.

In December 2012, NOVA Gas Transmission Ltd. (NGTL) retired US$175 million of 8.5 per cent Debentures.

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 to December 31, 2013.

TransCanada PipeLine USA Ltd.

In February 2013, TCPL USA’s US$300 million committed, syndicated, revolving credit facility matured.

TC PipeLines, LP

During 2013, TC PipeLines, LP made drawings on its syndicated revolving credit facility of US$437 million, and repayments of US$369 million. At December 31, 2013, US$380 million (2012 - US$312 million) was outstanding on the facility.

In July 2013, TC PipeLines, LP entered into and fully drew upon a new term loan agreement with a syndicate of lenders for a US$500 million medium-term loan, maturing July 1, 2018, and bearing interest at a floating rate calculated on a base rate plus an applicable margin. A portion of the loan proceeds were used to partially fund the acquisition of a 45 per cent interest in each of Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC (Bison LLC) as further described in Note 25.

In December 2011, TC PipeLines, LP repaid a maturing US$300 million term loan with a draw of US$312 million under the syndicated revolving credit facility.

In June 2011, TC PipeLines, LP issued US$350 million of 4.65 per cent Senior Unsecured Notes due 2021.

In May 2011, TC PipeLines, LP made draws of US$61 million on a bridge loan facility and US$125 million on its syndicated revolving credit facility.

Interest Expense



year ended December 31 (millions of Canadian dollars)	2013		2012		2011
Interest on Long-Term Debt	1,216		1,190		1,154
Interest on Junior Subordinated Notes	65		63		63
Interest on short-term debt	12		16		16
Capitalized interest	(287	)	(300	)	(302	)
Amortization and other financial charges¹	(21	)	7		6
	985		976		937


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 $985 million in 2013 (2012 – $966 million; 2011 – $926 million) on Long-Term Debt and Junior Subordinated Notes, net of interest capitalized on construction projects.

INCOME TAXES

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

INCOME TAXES

Provision for Income Taxes



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Current
Canada	27	167	212
Foreign	16	14	(2	)
	43	181	210
Deferred
Canada	245	69	139
Foreign	323	216	226
	568	285	365
Income Tax Expense	611	466	575

Geographic Components of Income



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Canada	1,224	842	1,176
Foreign	1,298	1,096	1,109
Income before Income Taxes	2,522	1,938	2,285

Reconciliation of Income Tax Expense



year ended December 31 (millions of Canadian dollars)	2013		2012		2011
Income before Income Taxes	2,522		1,938		2,285
Federal and provincial statutory tax rate	25.0	%	25.0	%	26.5	%
Expected income tax expense	631		485		605
Income tax differential related to regulated operations	(13	)	41		42
Higher/(lower) effective foreign tax rates	46		1		(5	)
Income from equity investments and non-controlling interests	(41	)	(40	)	(45	)
Tax legislation change	(25	)	—		—
Other	13		(21	)	(22	)
Actual Income Tax Expense	611		466		575

Deferred Income Tax Assets and Liabilities



at December 31 (millions of Canadian dollars)	2013	2012
Deferred Income Tax Assets
Operating loss carryforwards	826	1,024
Deferred amounts	223	112
Other	128	239
	1,177	1,375
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, equipment and PPAs	4,245	3,817
Equity investments	682	578
Taxes on future revenue requirement	291	283
Unrealized foreign exchange gains on long-term debt	35	159
Other	170	96
	5,423	4,933
Net Deferred Income Tax Liabilities	4,246	3,558

The above deferred tax amounts have been classified in the Consolidated Balance Sheet as follows:



at December 31 (millions of Canadian dollars)	2013	2012
Deferred Income Tax Assets
Other Current Assets (Note 5)	119	290
Intangible and Other Assets (Note 11)	225	168
	344	458
Deferred Income Tax Liabilities
Accounts Payable and Other (Note 13)	26	—
Deferred Income Tax Liabilities	4,564	4,016
	4,590	4,016
Net Deferred Income Tax Liabilities	4,246	3,558

At December 31, 2013, the Company has recognized the benefit of unused non-capital loss carryforwards of $1,026 million (2012 – $865 million) for federal and provincial purposes in Canada, which expire from 2014 to 2033.

At December 31, 2013, the Company has recognized the benefit of unused net operating loss carryforwards of US$1,432 million (2012 – US$2,174 million) for federal purposes in the U.S., which expire from 2028 to 2033.

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, 2013 by approximately $182 million (2012 – $144 million) if there had been a provision for these taxes.

Income Tax Payments

Income tax payments of $202 million, net of refunds, were made in 2013 (2012 – payments, net of refunds, of $190 million; 2011 – refunds, net of payments made, of $84 million).

Reconciliation of Unrecognized Tax Benefit

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



at December 31 (millions of Canadian dollars)	2013		2012		2011
Unrecognized tax benefits at beginning of year	49		52		62
Gross increases – tax positions in prior years	3		2		9
Gross decreases – tax positions in prior years	(28	)	(6	)	(7	)
Gross increases – tax positions in current year	2		9		11
Lapses of statute of limitations	(3	)	(8	)	(23	)
Unrecognized tax benefits at end of year	23		49		52

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 2008. 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, 2013 reflects an increase of $1 million of Interest Expense and nil for penalties (2012 – $2 million reversal of Interest Expense and nil for penalties; 2011 – $12 million reversal for Interest Expense and nil for penalties). At December 31, 2013, the Company had $6 million accrued for Interest Expense and nil accrued for penalties (December 31, 2012 – $5 million accrued for Interest Expense and nil accrued for penalties).

JUNIOR SUBORDINATED NOTES

12 Months Ended

Dec. 31, 2013

Junior Subordinated Notes [Abstract]

JUNIOR SUBORDINATED NOTES



		2013			2012
Outstanding loan amount (millions of Canadian dollars)	Maturity Date	Outstanding December 31	Effective Interest Rate		Outstanding December 31	Effective Interest Rate
TRANSCANADA PIPELINES LIMITED
U.S. dollars (2013 and 2012 – US$1,000)	2067	1,063	6.5	%	994	6.5	%

Junior Subordinated Notes of US$1.0 billion mature in 2067 and bear interest at 6.35 per cent per year 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 and without 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.

NON-CONTROLLING INTERESTS

12 Months Ended

Dec. 31, 2013

Noncontrolling Interest [Abstract]

NON-CONTROLLING INTERESTS

The Company's Non-Controlling Interests included in the Consolidated Balance Sheet were as follows:



at December 31 (millions of Canadian dollars)	2013	2012
Non-controlling interest in TC PipeLines, LP¹	1,323	953
Preferred shares of TCPL	194	389
Non-controlling interest in Portland²	94	83
	1,611	1,425

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



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Non-controlling interest in TC PipeLines, LP¹	93	91	101
Preferred share dividends of TCPL	20	22	22
Non-controlling interest in Portland²	12	5	6
	125	118	129


2	The non-controlling interest in Portland as at December 31, 2013 represented the 38.3 per cent interest not owned by TransCanada (2012 and 2011 - 38.3 per cent).

Preferred Shares of TCPL



at December 31	Number of Shares	Annual Dividend Rate per Share		Redemption Price per Share		2013	2012
	(thousands)					(millions of Canadian dollars)¹	(millions of Canadian dollars)¹
Cumulative First Preferred Shares of Subsidiary
Series U	4,000		$2.80		$50.00	—	195
Series Y	4,000		$2.80		$50.00	194	194
						194	389

1 Net of underwriting underwriting commissions and deferred income taxes.

In October 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 January 27, 2014, TCPL announced the redemption of all of the four million outstanding Cumulative Redeemable First Preferred Shares Series Y shares at $50 per share, plus accrued and unpaid dividends. Refer to Note 27 for further details.

Cash Dividends

Cash dividends of $22 million were paid on the Series U and Series Y preferred shares in 2013 (2012 and 2011 – $22 million).

In 2013, TransCanada received fees of $3 million from TC PipeLines, LP (2012 – $3 million; 2011 – $2 million) and $7 million from Portland (2012 and 2011 – $7 million) for services provided.

COMMON SHARES

12 Months Ended

Dec. 31, 2013

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

COMMON SHARES



	Number of Shares	Amount
	(thousands)	(millions of Canadian dollars)
Outstanding at January 1, 2011	696,230	11,745
Dividend reinvestment and share purchase plan	5,371	202
Exercise of options	2,260	64
Outstanding at December 31, 2011	703,861	12,011
Exercise of options	1,600	58
Outstanding at December 31, 2012	705,461	12,069
Exercise of options	1,980	80
Outstanding at December 31, 2013	707,441	12,149

Common Shares Issued and Outstanding

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

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. During the year, the weighted average number of common shares outstanding were used to calculate basic and diluted earnings per share. The increase in the weighted average number of shares for the diluted earnings per share calculation is due to the options exercisable under TransCanada's Stock Option Plan.



Weighted Average Common Shares Outstanding (millions)	2013	2012	2011
Basic	706.7	704.6	701.6
Diluted	707.7	705.7	702.8

Stock Options



	Number of Options		Weighted Average Exercise Prices		Options Exercisable
	(thousands)				(thousands)
Outstanding at January 1, 2011	8,406			$32.57	6,458
Granted	970			$38.02
Exercised	(2,260	)		$25.86
Forfeited	(16	)		$35.83
Outstanding at December 31, 2011	7,100			$35.44	5,165
Granted	1,978			$42.03
Exercised	(1,600	)		$33.13
Forfeited	(44	)		$36.55
Outstanding at December 31, 2012	7,434			$37.69	4,588
Granted	1,939			$47.09
Exercised	(1,980	)		$36.12
Outstanding at December 31, 2013	7,393			$40.57	3,954

Stock options outstanding at December 31, 2013 were as follows:



	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
	(thousands)			(years)	(thousands)			(years)
$30.10 to $36.26	1,725		$33.72	2.5	1,725		$33.72	2.5
$36.90 to $41.65	1,781		$38.52	3.7	1,516		$38.60	3.5
$41.95 to $45.29	1,948		$42.03	5.2	690		$42.03	5.2
$47.09	1,939		$47.09	6.1	23		$47.09	6.1
	7,393		$40.57	4.3	3,954		$37.12	3.1

An additional 10.5 million common shares were reserved for future issuance under TransCanada's Stock Option Plan at December 31, 2013. The weighted average fair value of options granted to purchase common shares under the Company's Stock Option Plan was determined to be $5.74 for the year ended December 31, 2013 (2012 – $5.08; 2011 – $2.94). 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:



	2013		2012		2011
Expected life (years)	6.0		5.9		4.0
Interest rate	1.7	%	1.6	%	2.1	%
Volatility¹	18	%	19	%	14	%
Dividend yield	3.7	%	4.2	%	4.3	%
Forfeiture rate	15	%	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 $6 million in 2013 (2012 and 2011 – $5 million).

The following table summarizes additional stock option information:



Year Ended December 31 (millions of Canadian dollars unless noted otherwise)	2013	2012	2011
Total intrinsic value of options exercised	$25	$18	$34
Fair value of options that have vested	$65	$49	$42
Total options vested	1.3 million	1.0 million	0.9 million

As at December 31, 2013, the aggregate intrinsic value of the total options exercisable was $45 million and the total intrinsic value of options outstanding was $59 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.

Cash Dividends

The following table summarizes cash dividends paid:



year ended December 31 (millions of Canadian dollars except per share amounts)	2013	2012	2011
Cash dividends paid, net of Dividend Reinvestment Plan	1,285	1,226	961
Cash dividends paid per common share	$1.82	$1.74	$1.66

Dividend Reinvestment Plan

Under the Company's Dividend Reinvestment Plan (DRP), eligible holders of common or preferred shares of TransCanada and preferred shares of TCPL can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with the dividends declared in April 2011, dividends payable to shareholders who participate in the DRP were satisfied with common shares purchased on the open market determined on the basis of the weighted average purchase price of such common shares. Previously, common shares issued in lieu of cash dividends under the DRP were issued from treasury at a discount to the average market price in the five days before dividend payment. The discount was set at three per cent in 2010, was reduced to two per cent commencing with the dividends declared in February 2011 and was eliminated completely in April 2011. In 2011, TransCanada issued 5.4 million common shares from treasury in accordance with the DRP in lieu of making cash dividend payments of $202 million.

PREFERRED SHARES

12 Months Ended

Dec. 31, 2013

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

PREFERRED SHARES



at December 31	Number of Shares Authorized and Outstanding	Annual Dividend Rate per Share		Redemption Price per Share		2013	2012
	(thousands)					(millions of Canadian dollars)¹	(millions of Canadian dollars)¹
Cumulative First Preferred Shares
Series 1	22,000		$1.15		$25.00	539	539
Series 3	14,000		$1.00		$25.00	343	343
Series 5	14,000		$1.10		$25.00	342	342
Series 7	24,000		$1.00		$25.00	589	—
						1,813	1,224


1	Net of underwriting commissions and deferred income taxes.

The holders of the Series 1 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.15 per share, payable quarterly, for the initial five-year period ending December 31, 2014. The dividend rate will reset on December 31, 2014 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.92 per cent. The Series 1 preferred shares are redeemable by TransCanada on December 31, 2014 and on December 31 of every fifth year thereafter at a price of $25.00 per share plus all accrued and unpaid dividends.

The Series 1 preferred shareholders have the right to convert their shares into Series 2 cumulative redeemable first preferred shares on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 2 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.92 per cent.

The holders of the Series 3 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly, for the initial five-year period ending June 30, 2015. The dividend rate will reset on June 30, 2015 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.28 per cent. The Series 3 preferred shares are redeemable by TransCanada on June 30, 2015 and on June 30 of every fifth year thereafter at a price of $25.00 per share plus all accrued and unpaid dividends.

The Series 3 preferred shareholders have the right to convert their shares into Series 4 cumulative redeemable first preferred shares on June 30, 2015 and on June 30 of every fifth year thereafter. The holders of Series 4 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.28 per cent.

The holders of the Series 5 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.10 per share, payable quarterly, for the initial five-and-a-half-year period ending January 30, 2016. The dividend rate will reset on January 30, 2016 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.54 per cent. The Series 5 preferred shares are redeemable by TransCanada on January 30, 2016 and on January 30 of every fifth year thereafter at a price of $25.00 per share plus all accrued and unpaid dividends.

The Series 5 preferred shareholders have the right to convert their shares into Series 6 cumulative redeemable first preferred shares on January 30, 2016 and on January 30 of every fifth year thereafter. The holders of Series 6 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.54 per cent.

In March 2013, TransCanada completed a public offering of 24 million Series 7 cumulative redeemable first preferred shares at a price of $25 per share, resulting in gross proceeds of $600 million. The holders of the Series 7 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly, for the initial six-year period ending April 30, 2019. The dividend rate will reset on April 30, 2019 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 2.38 per cent. The Series 7 preferred shares are redeemable by TransCanada on April 30, 2019 and on April 30 of every fifth year thereafter at a price of $25.00 per share plus all accrued and unpaid dividends.

The Series 7 preferred shareholders have the right to convert their shares into Series 8 cumulative redeemable first preferred shares on April 30, 2019 and on April 30 of every fifth year thereafter. The holders of Series 8 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 2.38 per cent.

Cash Dividends

The Company has paid preferred share cash dividends as follows:



	2013				2012		2011
at December 31 (millions of Canadian dollars, except per share amounts)	Cash Dividend Payments¹		Annual Dividend Rate per Share		Cash Dividend Payments	Annual Dividend Rate per Share	Cash Dividend Payments (net of DRP)	Annual Dividend Rate per Share
Cumulative First Preferred Shares
Series 1	25		$1.15		25	$1.15	25	$1.15
Series 3	14		$1.00		14	$1.00	14	$1.00
Series 5	16		$1.10		16	$1.10	16	$1.10
Series 7	16	²	$1.00	²	—	—	—	—
	71				55		55


1	At December 31, 2013, there were dividends declared but not yet paid of $10 million (2012 - $4 million) included in Accounts Payable and Other (Note 13) which was paid on January 30, 2014.


2	For the year ended December 31, 2013, the cash dividend rate was prorated at $0.65 per share.

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

OTHER COMPREHENSIVE INCOME AND ACCUMMULATED OTHER COMPREHENSIVE LOSS

21. 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, 2013 (millions of Canadian dollars)	Before tax amount		Income tax recovery/(expense)		Net of tax amount
Foreign currency translation gains and losses 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 (millions of Canadian dollars)	Before tax amount		Income tax recovery/(expense)		Net of tax amount
Foreign currency translation gains and 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	)



year ended December 31, 2011 (millions of Canadian dollars)	Before tax amount		Income tax recovery/(expense)		Net of tax amount
Foreign currency translation gains and losses on net investments in foreign operations	108		29		137
Change in fair value of net investment hedges	(101	)	28		(73	)
Change in fair value of cash flow hedges	(318	)	106		(212	)
Reclassification to Net Income of gains and losses on cash flow hedges	224		(77	)	147
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(119	)	30		(89	)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	13		(3	)	10
Other comprehensive loss on Equity Investments	(94	)	3		(91	)
Other comprehensive (loss)/income	(287	)	116		(171	)

The changes in AOCI by component is as follows:



	Currency translation adjustments		Cash flow hedges		Pension and OPEB plan adjustments		Equity Investments		Total¹
AOCI Balance at January 1, 2011	(683	)	(226	)	(157	)	(177	)	(1,243	)
Other comprehensive income/(loss) before reclassifications²	40		(213	)	(89	)	(83	)	(345	)
Amounts reclassified from Accumulated Other Comprehensive Loss	—		137		10		(8	)	139
Net current period other comprehensive income/(loss)	40		(76	)	(79	)	(91	)	(206	)
AOCI Balance at December 31, 2011	(643	)	(302	)	(236	)	(268	)	(1,449	)
Other comprehensive 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 Loss³	—		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	)


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 $66 million in 2013 (2012 - $21 million losses; 2011 - $35 million gains).

Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $81 million ($50 million, net of tax) at December 31, 2013. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

Details about reclassifications out of AOCI into the Consolidated Statement of Income are as follows:



	Amounts reclassified from accumulated other comprehensive loss¹				Affected line item in the consolidated statement of income
year ended December 31 (millions of Canadian dollars)	2013		2012		Affected line item in the consolidated statement of income
Cash flow hedges
Power and Natural Gas	(44	)	(201	)	Revenue (Energy)
Interest	(16	)	(18	)	Interest Expense
	(60	)	(219	)	Income before Income Taxes
	19		81		Income Tax Expense
	(41	)	(138	)	Net of tax
Pension and other post-retirement plan adjustments
Amortization of net loss²	(34	)	(22	)	Total before tax
	11		—		Income before Income Taxes
	(23	)	(22	)	Net of tax
Equity Investments
Equity Income	(20	)	5		Income from Equity Investments
	5		(2	)	Income Tax Expense
	(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.

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 220
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

Compensation and Retirement Disclosure [Abstract]

EMPLOYEE POST-RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2013

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 (2012 – nine years; 2011 – eight 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 11 years at December 31, 2013 (2012 and 2011 – 12 years). In 2013, the Company expensed $29 million (2012 – $24 million, 2011 – $23 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 (millions of Canadian dollars)	2013	2012	2011
DB Plans	79	83	62
Other post-retirement benefit plans	6	7	8
Savings and DC Plans	29	24	23
	114	114	93

In 2013, the Company provided a $59 million letter of credit to the Canadian DB Plan (2012 – $48 million; 2011 – $27 million), resulting in a total of $134 million provided to the Canadian DB Plan under letters of credit at December 31, 2013.

The Company measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. 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 (millions of Canadian dollars)	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31 (millions of Canadian dollars)	2013		2012		2013		2012

Change in Benefit Obligation¹
Benefit obligation – beginning of year	2,142		1,836		186		170
Service cost	84		66		2		2
Interest cost	96		94		7		8
Employee contributions	4		4		—		1
Benefits paid	(83	)	(79	)	(7	)	(9	)
Actuarial (gain)/loss	(39	)	227		(2	)	16
Foreign exchange rate changes	20		(6	)	5		(2	)
Benefit obligation – end of year	2,224		2,142		191		186
Change in Plan Assets
Plan assets at fair value – beginning of year	1,825		1,656		32		29
Actual return on plan assets	313		165		2		4
Employer contributions²	79		83		6		7
Employee contributions	4		4		—		1
Benefits paid	(83	)	(79	)	(7	)	(9	)
Foreign exchange rate changes	14		(4	)	2		—
Plan assets at fair value – end of year	2,152		1,825		35		32
Funded Status – Plan Deficit	(72	)	(317	)	(156	)	(154	)


1	The benefit obligation for the Company's pension benefit plan 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 $134 million in letters of credit provided to Canadian DB Plan for funding purposes.

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 (millions of Canadian dollars)	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31 (millions of Canadian dollars)	2013		2012		2013		2012
Intangible and Other Assets (Note 11)	—		—		16		11
Other Long-Term Liabilities (Note 14)	(72	)	(317	)	(172	)	(165	)
	(72	)	(317	)	(156	)	(154	)

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 (millions of Canadian dollars)	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31 (millions of Canadian dollars)	2013		2012		2013		2012
Projected benefit obligation¹	(2,224	)	(2,142	)	(172	)	(165	)
Plan assets at fair value	2,152		1,825		—		—
Funded Status – Deficit	(72	)	(317	)	(172	)	(165	)


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, 2013 is $2,039 million (2012 – $1,966 million).

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



at December 31 (millions of Canadian dollars)	2013		2012
Accumulated benefit obligation	(2,039	)	(1,966	)
Plan assets at fair value	2,152		1,825
Funded Status – Surplus/(Deficit)	113		(141	)

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 (millions of Canadian dollars)	2013		2012
Accumulated benefit obligation	(569	)	(1,966	)
Plan assets at fair value	537		1,825
Funded Status – Deficit	(32	)	(141	)

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

Asset Category



	Percentage of Plan Assets				Target Allocations¹
at December 31	2013		2012		2013
Debt securities	31	%	36	%	25% to 35%
Equity securities	69	%	64	%	50% to 70%
Alternatives	—		—		5 % to 15%
	100	%	100	%


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

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



at December 31 (millions of Canadian dollars)			Percentage of Plan Assets
at December 31 (millions of Canadian dollars)	2013	2012	2013		2012
Debt securities	2	2	0.1	%	0.1	%
Equity securities	2	3	0.1	%	0.2	%

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 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 (millions of Canadian dollars)	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
at December 31 (millions of Canadian dollars)	2013	2012	2013	2012	2013	2012	2013	2012	2013		2012
Asset Category
Cash and Cash Equivalents	17	17	—	—	—	—	17	17	1	%	1	%
Equity Securities:
Canadian	474	400	170	113	—	—	644	513	29	%	28	%
U.S.	423	309	37	38	—	—	460	347	21	%	19	%
International	36	31	330	263	—	—	366	294	17	%	16	%
Global	—	—	14	13	—	—	14	13	1	%	—
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	304	314	—	—	304	314	14	%	17	%
Provincial	—	—	154	161	—	—	154	161	7	%	9	%
Municipal	—	—	6	5	—	—	6	5	—		—
Corporate	—	—	77	65	—	—	77	65	3	%	4	%
U.S. Bonds:
State	—	—	33	33	—	—	33	33	2	%	2	%
Corporate	—	—	48	45	—	—	48	45	2	%	2	%
International:
Corporate	—	—	20	9	—	—	20	9	1	%	—
Mortgage Backed	—	—	26	22	—	—	26	22	1	%	1	%
Other Investments:
Private Equity Funds	—	—	—	—	18	19	18	19	1	%	1	%
	950	757	1,219	1,081	18	19	2,187	1,857	100	%	100	%

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



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

Balance at December 31, 2011	20
Realized and unrealized losses	(1	)
Balance at December 31, 2012	19
Purchases and sales	(4	)
Realized and unrealized gains	3
Balance at December 31, 2013	18

The Company's expected funding contributions in 2014 are approximately $70 million for the DB Plans, approximately $6 million for the other post-retirement benefit plans and approximately $34 million for the savings plan and DC Plans. In addition, the Company expects to provide a $47 million letter of credit to the Canadian DB Plan.

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



(millions of Canadian dollars)	Pension Benefits	Other Post- Retirement Benefits
2014	93	9
2015	100	9
2016	106	10
2017	112	11
2018	118	11
2019 to 2023	684	58

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, 2013. 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	2013		2012		2013		2012
Discount rate	4.95	%	4.35	%	5.00	%	4.35	%
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 Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2013		2012		2011		2013		2012		2011
Discount rate	4.35	%	5.05	%	5.55	%	4.35	%	5.10	%	5.60	%
Expected long-term rate of return on plan assets	6.70	%	6.70	%	6.95	%	4.60	%	6.40	%	6.40	%
Rate of compensation increase	3.15	%	3.15	%	3.10	%	—		—		—

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 2014 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
Effect on total of service and interest cost components	1	—
Effect on post-retirement benefit obligation	18	(15	)

The Company's net benefit cost is as follows:



at December 31 (millions of Canadian dollars)	Pension Benefit Plans						Other Post-Retirement Benefit Plans
at December 31 (millions of Canadian dollars)	2013		2012		2011		2013		2012		2011
Service cost	84		66		54		2		2		2
Interest cost	96		94		91		7		8		9
Expected return on plan assets	(120	)	(113	)	(114	)	(2	)	(2	)	(2	)
Amortization of actuarial loss	30		18		10		2		1		1
Amortization of past service cost	2		2		2		—		1		—
Amortization of regulatory asset	30		19		12		1		1		1
Amortization of transitional obligation related to regulated business	—		—		—		2		2		2
Net Benefit Cost Recognized	122		86		55		12		13		13

Pre-tax amounts recognized in AOCI were as follows:



	2013		2012		2011
at December 31 (millions of Canadian dollars)	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
Net loss	236	32	362	33	282	29
Prior service cost	3	1	5	2	7	2
	239	33	367	35	289	31

The estimated net loss and prior service cost for the DB Plans that will be amortized from AOCI into net periodic benefit cost in 2014 are $36 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 2014 is $2 million and nil, respectively.

Pre-tax amounts recognized in OCI were as follows:



at December 31 (millions of Canadian dollars)	2013				2012				2011
at December 31 (millions of Canadian dollars)	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits
Amortization of net loss from AOCI to OCI	(30	)	(2	)	(19	)	(1	)	(10	)	(1	)
Amortization of prior service costs from AOCI to OCI	(2	)	—		(2	)	—		(2	)	—
Funded status adjustment	(96	)	—		99		5		113		6
	(128	)	(2	)	78		4		101		5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2013

Risk Management and Financial Instruments [Abstract]

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and, 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 large 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 purchased through 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, Oil 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, and 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 arise on some of the Company’s regulated assets. Certain of the realized gains and losses on these derivatives are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers in accordance with the terms of the shipping agreements.

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 (millions of Canadian dollars unless noted otherwise)	2013		2012
Carrying value	14,200	(US 13,400)	11,100	(US 11,200)
Fair value	16,000	(US 15,000)	14,300	(US 14,400)

Derivatives Designated as a Net Investment Hedge



	2013				2012
at December 31 (millions of Canadian dollars unless noted otherwise)	Fair Value¹		Notional or Principal Amount		Fair Value¹	Notional or Principal Amount
U.S. dollar cross-currency interest rate swaps (maturing 2014 to 2019)²	(201	)	US	3,800	82	US	3,800
U.S. dollar foreign exchange forward contracts (maturing 2014)	(11	)	US	850	—	US	250
	(212	)	US	4,650	82	US	4,050


1	Fair values approximate carrying values.


2	In 2013, net realized gains of $29 million (2012 – gains of $30 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 (millions of Canadian dollars)	2013		2012
Other Current Assets (Note 5)	5		71
Intangible and Other Assets (Note 11)	—		47
Accounts Payable and Other (Note 13)	(50	)	(6	)
Other Long-Term Liabilities (Note 14)	(167	)	(30	)
	(212	)	82

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, and letters of credit or cash, when they are deemed necessary.

There is no guarantee, however, that these techniques will protect the Company from material losses.

TransCanada's maximum counterparty credit exposure with respect to financial instruments at the Balance Sheet date, 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, 2013, there were no significant amounts past due or impaired, and there were no significant credit losses during the year.

At December 31, 2013, the Company had a credit risk concentration of $240 million (2012 – $259 million) due from a counterparty. 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 purchases 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 equal 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:



	2013				2012
at December 31 (millions of Canadian dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Notes receivable and other¹	226		269		237		286
Available for sale assets²	47		47		44		44
Current and Long-Term Debt^3,4 (Note 15)	(22,865	)	(26,134	)	(18,913	)	(24,573	)
Junior Subordinated Notes (Note 17)	(1,063	)	(1,093	)	(994	)	(1,054	)
	(23,655	)	(26,911	)	(19,626	)	(25,297	)


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$200 million (2012 - US$350 million) that is attributed to hedged risk and recorded at fair value.

Consolidated Net Income in 2013 included losses of $5 million (2012 - losses of $10 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$200 million of Long-Term Debt at December 31, 2013 (2012 - US$350 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

The following tables detail the remaining contractual maturities for TransCanada's non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2013:

Contractual Principal Repayments of Non-Derivative Financial Liabilities



at December 31 (millions of Canadian dollars)	Total	2014	2015 and 2016	2017 and 2018	2019 and Thereafter
Notes Payable (Note 12)	1,842	1,842	—	—	—
Long-Term Debt (Note 15)	22,865	973	3,751	2,494	15,647
Junior Subordinated Notes (Note 17)	1,063	—	—	—	1,063
	25,770	2,815	3,751	2,494	16,710

Interest Payments on Non-Derivative Financial Liabilities



at December 31 (millions of Canadian dollars)	Total	2014	2015 and 2016	2017 and 2018	2019 and Thereafter
Long-Term Debt (Note 15)	16,798	1,254	2,315	2,111	11,118
Junior Subordinated Notes (Note 17)	3,614	68	135	135	3,276
	20,412	1,322	2,450	2,246	14,394

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.

Where possible, derivative instruments are designated as hedges, but 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 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 (millions of Canadian dollars)	2013		2012
Other Current Assets (Note 5)	395		259
Intangible and Other Assets (Note 11)	112		187
Accounts Payable and Other (Note 13)	(357	)	(283	)
Other Long-Term Liabilities (Note 14)	(255	)	(186	)
	(105	)	(23	)

2013 Derivative Instruments Summary

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



(millions of Canadian dollars unless noted otherwise)	Power			Natural Gas			Foreign Exchange			Interest
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 Relationships^5,6
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	All derivative instruments held for trading have been entered into for risk management purposes and 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.

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.

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.

2012 Derivative Instruments Summary

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



(millions of Canadian dollars unless noted otherwise)	Power			Natural Gas			Foreign Exchange			Interest
Derivative Instruments Held for Trading¹
Fair Values²
Assets		$139			$88			$1			$14
Liabilities		($176	)		($104	)		($2	)		($14	)
Notional Values
Volumes³
Purchases	31,135			83			—			—
Sales	31,066			65			—			—
Canadian dollars	—			—			—			620
U.S. dollars	—			—			US 1,408			US 200
Net unrealized (losses)/gains in the year⁴		($30	)		$2			($1	)		$—
Net realized gains/(losses) in the year⁴		$5			($10	)		$26			$—
Maturity dates	2013-2017			2013-2016			2013			2013-2016

Derivative Instruments in Hedging Relationships^5,6
Fair Values²
Assets		$76			$—			$—			$10
Liabilities		($97	)		($2	)		($38	)		$—
Notional Values
Volumes³
Purchases	15,184			1			—			—
Sales	7,200			—			—			—
U.S. dollars	—			—			US 12			US 350
Cross-currency	—			—			136/US 100			—
Net realized (losses)/gains in the year⁴		($130	)		($23	)		$—			$7
Maturity dates	2013-2018			2013			2013-2014			2013-2015


1	All derivative instruments held for trading have been entered into for risk management purposes and 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.

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 $10 million and a notional amount of US$350 million. In 2012, net realized gains on fair value hedges were $7 million and were included in Interest Expense. In 2012, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.


6	In 2012, 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 (millions of Canadian dollars, pre-tax)	2013		2012
Change in fair value of derivative instruments recognized in OCI (effective portion)¹
Power	117		83
Natural Gas	(1	)	(21	)
Foreign Exchange	5		(1	)
	121		61
Reclassification of gains on derivative instruments from AOCI to Net Income (effective portion)¹
Power²	40		147
Natural Gas²	4		54
Interest	16		18
	60		219
Gains on derivative instruments recognized in Net Income (ineffective portion)
Power	8		7
	8		7


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.

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, 2013 (millions of Canadian dollars)	Gross derivative instruments presented on the balance sheet		Amounts available for offset¹		Net amounts
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, 2013, the Company had provided cash collateral of $67 million and letters of credit of $85 million to its counterparties. The Company held $11 million in cash collateral and $32 million in letters of credit from counterparties on asset exposures at December 31, 2013.

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, 2012:



at December 31, 2012 (millions of Canadian dollars)	Gross derivative instruments presented on the balance sheet		Amounts available for offset¹		Net amounts
Derivative - Asset
Power	215		(132	)	83
Natural Gas	88		(83	)	5
Foreign exchange	119		(37	)	82
Interest	24		(6	)	18
	446		(258	)	188
Derivative - Liability
Power	(273	)	132		(141	)
Natural gas	(106	)	83		(23	)
Foreign exchange	(76	)	37		(39	)
Interest	(14	)	6		(8	)
	(469	)	258		(211	)


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, 2012, the Company had provided cash collateral of $189 million and letters of credit of $45 million to its counterparties. The Company held $2 million in cash collateral and $5 million in letters of credit from counterparties on asset exposures at December 31, 2012.

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, 2013, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $16 million (2012 – $37 million), for which the Company has provided collateral in the normal course of business of nil (2012 – nil). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2013, the Company would have been required to provide additional collateral of $16 million (2012 – $37 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 inputs that are unobservable and significant to the overall fair value measurement. This category includes long-dated commodity transactions in certain markets where liquidity is low. Long-term electricity prices are estimated using a third-party modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which we operate.
	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 are based 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 is 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 2013, are categorized as follows:



at December 31, 2013 (millions of Canadian dollars, pre-tax)	Quoted prices in active markets Level I¹		Significant other observable inputs Level II¹		Significant unobservable inputs Level III¹		Total
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 fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2012, are categorized as follows:



at December 31, 2012 (millions of Canadian dollars, pre-tax)	Quoted prices in active markets Level I¹		Significant other observable inputs Level II¹		Significant unobservable inputs Level III¹		Total
Derivative Instrument Assets:
Power commodity contracts	—		213		2		215
Natural gas commodity contracts	75		13		—		88
Foreign exchange contracts	—		119		—		119
Interest rate contracts	—		24		—		24
Derivative Instrument Liabilities:
Power commodity contracts	—		(269	)	(4	)	(273	)
Natural gas commodity contracts	(95	)	(11	)	—		(106	)
Foreign exchange contracts	—		(76	)	—		(76	)
Interest rate contracts	—		(14	)	—		(14	)
Non-Derivative Financial Instruments:
Available for sale assets	—		44		—		44
	(20	)	43		(2	)	21


1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2012.

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)	2013		2012
Balance at beginning of year	(2	)	(15	)
Settlements	—		(1	)
Transfers out of Level III	(2	)	(21	)
Total (losses)/gains included in Net Income	(1	)	11
Total gains included in OCI	6		24
Balance at end of year¹	1		(2	)


1	Energy Revenues include unrealized gains or losses attributed to derivatives in the Level III category that were still held at December 31, 2013 of nil (2012 – $1 million).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2013.

CHANGES IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2013

CHANGES IN OPERATING WORKING CAPITAL

CHANGES IN OPERATING WORKING CAPITAL



year ended December 31 (millions of Canadian dollars)	2013		2012	2011
(Increase)/decrease in Accounts Receivable	(54	)	67	(15	)
(Increase)/decrease in Inventories	(30	)	27	3
Decrease/(increase) in Other Current Assets	40		66	(27	)
(Decrease)/increase in Accounts Payable and Other	(290	)	127	266
Increase in Accrued Interest	8		—	8
(Increase)/Decrease in Operating Working Capital	(326	)	287	235

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
ACQUISITIONS AND DISPOSITIONS	Dec. 31, 2013
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS Energy Ontario Solar In 2011, TransCanada agreed to purchase nine Ontario solar facilities with a combined capacity of 86 MW from Canadian Solar Solutions Inc. for approximately $500 million. Under the terms of the agreement, TransCanada will purchase each facility once construction and acceptance testing have been completed and operations have begun under 20-year PPAs with the Ontario Power Authority as part of the Feed-in Tariff program in Ontario. In 2013, TransCanada acquired the first four of these solar power facilities for $216 million. TransCanada measured the assets and liabilities acquired at fair value with substantially all of the purchase price allocated to Plant, Property and Equipment and no Goodwill was recorded. TransCanada anticipates the remaining facilities will come into service and be acquired in 2014. 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 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 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. In May 2011, TransCanada completed the sale of a 25 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an aggregate purchase price of US$605 million which included US$81 million of long-term debt, or 25 per cent of GTN LLC's outstanding debt, plus normal closing adjustments. In May 2011, TC PipeLines, LP completed a public offering of 7,245,000 common units at a price of US$47.58 per unit, resulting in gross proceeds of approximately US$345 million and net proceeds of US$331 million after unit issuance costs. TransCanada contributed approximately US$7 million to maintain its two per cent general partnership interest and did not purchase any other units. As a result of the common units offering, TransCanada's ownership in TC PipeLines, LP decreased from 38.2 per cent to 33.3 per cent and an after-tax dilution gain of $30 million ($50 million pre-tax) was recorded in Additional Paid-In Capital.

COMMITMENTS, CONTINGENCIES AND GUARANTEES

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

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 (millions of Canadian dollars)	Minimum Lease Payments	Amounts Recoverable under Sub-leases	Net Payments
2014	98	8	90
2015	97	7	90
2016	92	5	87
2017	86	5	81
2018	82	3	79
2019 and thereafter	325	—	325
	780	28	752

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 10 years. Net rental expense on operating leases in 2013 was $98 million (2012 – $84 million; 2011 – $79 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. Future payments under these PPAs have been excluded from operating leases in the above table, as these payments are dependent upon plant availability and other factors. TransCanada's share of payments under the PPAs in 2013 was $242 million (2012 – $238 million; 2011 – $309 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 signed contracts 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, 2013, TransCanada was committed to Natural Gas Pipelines capital expenditures totaling approximately $1.3 billion (2012 – $1.3 billion), primarily related to construction costs related to the NGTL System and other natural gas pipeline projects.

At December 31, 2013, the Company was committed to Oil Pipelines capital expenditures totaling approximately $2.5 billion (2012 – $1.7 billion), primarily related to construction costs of Keystone XL and Grand Rapids.

At December 31, 2013, the Company was committed to Energy capital expenditures totaling approximately $0.1 billion (2012 – $0.1 billion), primarily related to capital costs of the Napanee Generating Station.

At December 31, 2013, the Company was committed to purchase the remaining five solar facilities from Canadian Solar Solutions Inc. for approximately $280 million.

Contingencies

TransCanada is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2013, the Company had accrued approximately $32 million (2012 - $37 million; 2011 – $49 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 partners on Bruce Power, Cameco Corporation and BPC Generation Infrastructure Trust (BPC), have severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, a lease agreement and contractor 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:



		2013		2012
year ended December 31 (millions of Canadian dollars)	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value
Bruce Power	Ranging to 2019²	629	8	897	10
Other jointly owned entities	Ranging to 2040	51	10	89	7
		680	18	986	17


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


2	Except for one guarantee with no termination date

SUBSEQUENT EVENT	12 Months Ended
SUBSEQUENT EVENT	Dec. 31, 2013
Subsequent Events [Abstract]
SUBSEQUENT EVENT	SUBSEQUENT EVENTS Preferred Shares On January 20, 2014, TransCanada completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at a price of $25 per share, resulting in gross proceeds of $450 million. The holders of the Series 9 preferred shares will be entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly for the initial fixed rate period ending October 30, 2019. The dividend rate will reset on October 30, 2019 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 2.35 per cent. The Series 9 Preferred Shares are redeemable by TransCanada on October 30, 2019 and on October 30 of every fifth year thereafter at a price of $25.00 per share plus accrued and unpaid dividends. The Series 9 preferred shareholders will have the right to convert their shares into Series 10 cumulative redeemable first preferred shares on October 30, 2019 or October 30 of every fifth year thereafter. The holders of Series 10 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate plus 2.35 percent. Cancarb Asset Sale On January 20, 2014, TransCanada reached an agreement to sell Cancarb Limited and its related power generation facility for aggregate gross proceeds of $190 million, subject to closing adjustments. The transaction is expected to close late in the first quarter of 2014, subject to various approvals. The related assets were classified as assets held for sale at December 31, 2013 (Note 6). TCPL Preferred Share Redemption On January 27, 2014, TCPL announced the redemption of all of the four million outstanding 5.60 per cent Cumulative Redeemable First Preferred Shares Series Y on March 5, 2014 at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends to such redemption date. The total par value of the outstanding Series Y Shares is $200 million and they carry an aggregate of $11.2 million in annualized dividends.

ACCOUNTING POLICIES (Policies)	12 Months Ended
ACCOUNTING POLICIES (Policies)	Dec. 31, 2013
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 Judgements 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 judgement in making these estimates and assumptions. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies summarized below.
Disclosure of accounting policy for rate regulated natural gas pipelines	Regulation In Canada, regulated natural gas pipelines and oil pipelines are subject to the authority of the National Energy Board (NEB) of Canada. In the U.S., natural gas pipelines, oil 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. The Company's Canadian and U.S. 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 and U.S. natural gas pipelines and regulated U.S. natural gas storage. RRA is not applicable to the Keystone Pipeline System and the Company's Mexican natural gas pipelines and, as a result, the regulators' decisions regarding operations and tolls on these pipelines generally do not have an impact on timing of recognition of revenues and expenses.
Revenue Recognition	Revenue Recognition Natural Gas and Oil Pipelines Revenues from the Company's natural gas and oil pipelines, with the exception of Canadian natural gas pipelines which are subject to rate regulation, 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 rate regulation 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 an appropriate 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. The cost of 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. 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. Oil Pipelines Plant, property and equipment for oil 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. When oil 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 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. The PPAs under which TransCanada buys power are accounted for as operating leases. The 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 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, oil 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. 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 period 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 period 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 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. 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)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment



year ended December 31, 2013 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines		Energy		Corporate		Total
Revenues	4,497		1,124		3,176		—		8,797
Income from Equity Investments	145		—		452		—		597
Plant Operating Costs and Other	(1,405	)	(328	)	(833	)	(108	)	(2,674	)
Commodity Purchases Resold	—		—		(1,317	)	—		(1,317	)
Property Taxes	(329	)	(44	)	(72	)	—		(445	)
Depreciation and Amortization	(1,027	)	(149	)	(293	)	(16	)	(1,485	)
	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



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



year ended December 31, 2011 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines¹		Energy		Corporate		Total
Revenues	4,244		827		2,768		—		7,839
Income from Equity Investments	159		—		256		—		415
Plant Operating Costs and Other	(1,221	)	(209	)	(842	)	(86	)	(2,358	)
Commodity Purchases Resold	—		—		(991	)	—		(991	)
Property Taxes	(307	)	(31	)	(72	)	—		(410	)
Depreciation and Amortization	(923	)	(130	)	(261	)	(14	)	(1,328	)
	1,952		457		858		(100	)	3,167
Interest Expense									(937	)
Interest Income and Other									55
Income before Income Taxes									2,285
Income Tax Expense									(575	)
Net Income									1,710
Net Income Attributable to Non-Controlling Interests									(129	)
Net Income Attributable to Controlling Interests									1,581
Preferred Share Dividends									(55	)
Net Income Attributable to Common Shares									1,526


1	Commencing in February 2011, TransCanada began recording earnings for the Keystone Pipeline System.

Reconciliation of Assets from Segment to Consolidated



at December 31 (millions of Canadian dollars)	2013	2012
Natural Gas Pipelines	25,165	23,210
Oil Pipelines	13,253	10,485
Energy	13,747	13,157
Corporate	1,733	1,544
	53,898	48,396

Revenue from External Customers by Geographic Areas



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Revenues
Canada – domestic	4,659	3,527	3,929
Canada – export	997	1,121	1,087
United States	3,029	3,252	2,752
Mexico	112	107	71
	8,797	8,007	7,839

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



at December 31 (millions of Canadian dollars)	2013	2012
Plant, Property and Equipment
Canada	18,462	18,054
United States	17,570	14,904
Mexico	1,574	755
	37,606	33,713

Reconciliation of Other Significant Reconciling Items from Segments to Consolidated



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Natural Gas Pipelines	1,776	1,389	917
Oil Pipelines	2,483	1,145	1,204
Energy	152	24	384
Corporate	50	37	8
	4,461	2,595	2,513

OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2013

Other Assets [Abstract]

Schedule of other current assets



at December 31 (millions of Canadian dollars)	2013	2012
Fair value of derivative contracts (Note 23)	395	259
Deferred income tax assets (Note 16)	119	290
Assets held for sale (Note 6)	85	—
Regulatory Assets (Note 9)	42	178
Other	206	270
	847	997

ASSETS HELD FOR SALE (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Assets Held for Sale



at December 31 (millions of Canadian dollars)		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)		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 (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of plant, property and equipment



	2013			2012
at December 31 (millions of Canadian dollars)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
Natural Gas Pipelines¹
Canadian Mainline
Pipeline	8,970	5,457	3,513	8,801	5,192	3,609
Compression	3,392	1,961	1,431	3,370	1,880	1,490
Metering and other	409	174	235	391	182	209
	12,771	7,592	5,179	12,562	7,254	5,308
Under construction	85	—	85	163	—	163
	12,856	7,592	5,264	12,725	7,254	5,471
NGTL System
Pipeline	7,813	3,410	4,403	7,214	3,221	3,993
Compression	2,038	1,253	785	1,885	1,177	708
Metering and other	947	418	529	958	420	538
	10,798	5,081	5,717	10,057	4,818	5,239
Under construction	290	—	290	463	—	463
	11,088	5,081	6,007	10,520	4,818	5,702
ANR
Pipeline	922	59	863	864	49	815
Compression	635	81	554	514	72	442
Metering and other	535	91	444	520	81	439
	2,092	231	1,861	1,898	202	1,696
Under construction	67	—	67	63	—	63
	2,159	231	1,928	1,961	202	1,759
Other Natural Gas Pipelines
GTN	1,685	488	1,197	1,565	411	1,154
Great Lakes	1,650	833	817	1,544	750	794
Foothills	1,649	1,120	529	1,634	1,062	572
Mexico	641	90	551	536	59	477
Other²	1,652	288	1,364	1,548	226	1,322
	7,277	2,819	4,458	6,827	2,508	4,319
Under construction	1,047	—	1,047	297	—	297
	8,324	2,819	5,505	7,124	2,508	4,616
	34,427	15,723	18,704	32,330	14,782	17,548
Oil Pipelines
Keystone
Pipeline	5,079	286	4,793	4,828	177	4,651
Pumping equipment	1,118	82	1,036	1,066	51	1,015
Tanks and other	962	71	891	935	47	888
	7,159	439	6,720	6,829	275	6,554
Under construction³	6,020	—	6,020	3,678	—	3,678
	13,179	439	12,740	10,507	275	10,232
Energy
Natural Gas – Ravenswood	1,966	377	1,589	1,799	290	1,509
Natural Gas – Other^4,5	3,061	846	2,215	2,975	746	2,229
Hydro	673	126	547	634	106	528
Wind	946	155	791	907	118	789
Natural Gas Storage	677	92	585	677	83	594
Solar⁶	226	2	224	—	—	—
Other	57	30	27	134	86	48
	7,606	1,628	5,978	7,126	1,429	5,697
Under construction	54	—	54	136	—	136
	7,660	1,628	6,032	7,262	1,429	5,833
Corporate	191	61	130	154	54	100
	55,457	17,851	37,606	50,253	16,540	33,713


1	In 2013, the Company capitalized $37 million (2012 – $32 million) relating to the equity portion of AFUDC for natural gas pipelines with a corresponding amount recorded in Interest Income and Other.


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


3	Includes $2.6 billion for Keystone XL at December 31, 2013 (2012 – $2 billion). Keystone XL remains subject to regulatory approvals.


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


6	Includes the acquisitions in 2013 of four solar power facilities.

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2013

Equity Method Investments and Joint Ventures [Abstract]

Schedule of equity investments



(millions of Canadian dollars)	Ownership Interest at December 31, 2013		Income/(Loss) from Equity Investments				Equity Investments
			year ended December 31				at December 31
			2013	2012		2011	2013	2012
Natural Gas Pipelines
Northern Border^1,2			66	72		75	557	511
Iroquois	44.5	%	41	41		40	188	174
TQM	50.0	%	13	16		17	76	80
Other	Various		25	28		27	62	60
Energy
Bruce A³	48.9	%	202	(149	)	33	3,988	4,033
Bruce B³	31.6	%	108	163		77	377	69
ASTC Power Partnership	50.0	%	110	40		84	41	42
Portlands Energy	50.0	%	31	28		33	343	341
Other⁴	Various		1	18		29	57	54
Oil Pipelines
Grand Rapids⁵	50.0	%	—	—		—	70	2
			597	257		415	5,759	5,366


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, 2013, TransCanada had an ownership interest in TC PipeLines, LP of 28.9 per cent (2012 and 2011 – 33.3 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.5 per cent (2012 and 2011 – 16.7 per cent).


2	At December 31, 2013, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$118 million (2012 – US$119 million) due to the fair value assessment of assets at the time of acquisition.


3	At December 31, 2013, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $820 million (2012 – $889 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.


5	In October 2012, TransCanada entered into a joint venture agreement with a third party to build this pipeline system to transport crude oil and diluent between the producing area northwest of Fort McMurray and the Edmonton/Heartland market region.

Summary of financial information for the equity investees



year ended December 31 (millions of Canadian dollars)	2013		2012		2011
Income
Revenues	4,989		3,860		4,042
Operating and Other Expenses	(3,536	)	(3,090	)	(2,989	)
Net Income	1,390		717		929
Net Income attributable to TransCanada	597		257		415



at December 31 (millions of Canadian dollars)	2013		2012
Balance Sheet
Current assets	1,500		1,593
Non current assets	12,158		12,154
Current liabilities	(1,117	)	(1,187	)
Non current liabilities	(2,507	)	(3,787	)

RATE-REGULATED BUSINESSES (Tables)

12 Months Ended

Dec. 31, 2013

Regulated Operations [Abstract]

Schedule of regulatory assets and liabilities



at December 31 (millions of Canadian dollars)	2013	2012	Remaining Recovery/ Settlement Period (years)


Regulatory Assets
Deferred income taxes¹	1,149	1,122	n/a
Operating and debt-service regulatory assets²	16	171	1
Long Term Adjustment Account³	354	80	31
Other⁴	258	434	n/a
	1,777	1,807
Less: Current portion included in Other Current Assets (Note 5)	42	178
	1,735	1,629
Regulatory Liabilities
Foreign exchange on long-term debt⁵	84	150	1-16
Operating and debt-service regulatory liabilities²	5	84	1
Other⁴	147	134	n/a
	236	368
Less: Current portion included in Accounts Payable and Other (Note 13)	7	100
	229	268


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


4	Pre-tax operating results in 2013 would have been $189 million higher (2012 – $13 million higher; 2011 - $106 million lower) had these amounts not been recorded as regulatory assets and liabilities.

GOODWILL (Tables)

12 Months Ended

Dec. 31, 2013

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 Pipelines		Energy		Total
Balance at January 1, 2012	2,693		841		3,534
Foreign exchange rate changes	(58	)	(18	)	(76	)
Balance at December 31, 2012	2,635		823		3,458
Foreign exchange rate changes	181		57		238
Balance at December 31, 2013	2,816		880		3,696

INTANGIBLE AND OTHER ASSETS (Tables)

12 Months Ended

Dec. 31, 2013

INTANGIBLES AND OTHER ASSETS

Schedule of intangible and other assets



at December 31 (millions of Canadian dollars)	2013	2012
Capital projects under development	571	34
PPAs	324	376
Deferred income tax assets and charges (Note 16)	225	168
Loans and advances¹	183	196
Fair value of derivative contracts (Note 23)	112	187
Employee post-retirement benefits (Note 22)	16	11
Other	524	434
	1,955	1,406


1	As at December 31, 2013, TransCanada held a $226 million (2012 – $236 million) note receivable from the seller of Ravenswood which bears interest at 6.75 per cent and matures in 2040. The current portion of the note receivable of $43 million (2012 – $40 million) is included in Other Current Assets.

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:



	2013			2012
at December 31 (millions of Canadian dollars)	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
Sheerness	585	312	273	585	273	312
Sundance A	225	174	51	225	161	64
	810	486	324	810	434	376

NOTES PAYABLE (Tables)

12 Months Ended

Dec. 31, 2013

Short-term Debt [Abstract]

Schedule of notes payable



	2013			2012
(millions of Canadian dollars)	Outstanding December 31	Weighted Average Interest Rate per Annum at December 31		Outstanding December 31	Weighted Average Interest Rate per Annum at December 31
Canadian dollars	751	1.2	%	803	1.2	%
U.S. dollars (2013 – US$1,025; 2012 – US$1,480)	1,091	0.3	%	1,472	0.4	%
	1,842			2,275

Schedule of credit facilities

These unsecured credit facilities included the following:



					year ended December 31
at December 31, 2013					2013	2012	2011
Amount	Unused Capacity	Borrower	For	Matures	Cost to maintain
					(millions of Canadian dollars)
$3 billion	$3 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility	December 2018	4	4	2
US$1 billion	US$0.8 billion	TCPL USA	Committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL	November 2014	1	1	4
US$1 billion	US$1 billion	TAIL	Committed, syndicated, revolving, extendible TAIL credit facility, guaranteed by TCPL	November 2014	—	—	—
$1.1 billion	$0.3 billion	TCPL	Supports the issuance of letters of credit and provides additional liquidity	Demand	—	—	—

ACCOUNTS PAYABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2013

Payables and Accruals [Abstract]

Schedule of accounts payable and other



at December 31 (millions of Canadian dollars)	2013	2012
Trade payables	866	923
Fair value of derivative contracts (Note 23)	357	283
Dividends payable	338	320
Deferred Income Tax Liabilities (Note 16)	26	—
Regulatory Liabilities (Note 9)	7	100
Liabilities related to assets held for sale (Note 6)	5	—
Other	556	718
	2,155	2,344

OTHER LONG-TERM LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2013

Deferred Costs, Noncurrent [Abstract]

Schedule of deferred amounts



at December 31 (millions of Canadian dollars)	2013	2012
Employee post-retirement benefit (Note 22)	244	482
Fair value of derivative contracts (Note 23)	255	186
Asset retirement obligations	83	72
Guarantees (Note 26)	18	17
Other	56	125
	656	882

LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2013

Long-term Debt, Unclassified [Abstract]

Schedule of long-term debt



		2013			2012
Outstanding loan amounts (millions of Canadian dollars)	Maturity Dates	Outstanding December 31	Interest Rate¹		Outstanding December 31	Interest Rate¹
TRANSCANADA PIPELINES LIMITED
Debentures
Canadian dollars	2014 to 2020	874	10.9	%	874	10.9	%
U.S. dollars (2013 and 2012 US$400)	2021	425	9.9	%	398	9.9	%
Medium-Term Notes
Canadian dollars	2014 to 2041	4,799	5.7	%	4,549	5.9	%
Senior Unsecured Notes
U.S. dollars (2013 – US$12,276; 2012 – US$10,126)	2015 to 2043	13,027	5.0	%	10,057	5.6	%
		19,125			15,878
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian dollars	2014 to 2024	378	11.5	%	382	11.5	%
U.S. dollars (2013 and 2012 – US$200)	2023	213	7.9	%	199	7.9	%
Medium-Term Notes
Canadian dollars	2025 to 2030	504	7.4	%	504	7.4	%
U.S. dollars (2013 and 2012 – US$33)	2026	34	7.5	%	32	7.5	%
		1,129			1,117
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. dollars (2013 and 2012 – US$432)	2021 to 2025	459	8.9	%	430	8.9	%
GAS TRANSMISSION NORTHWEST CORPORATION
Senior Unsecured Notes
U.S. dollars (2013 and 2012 – US$325)	2015 to 2035	346	5.5	%	323	5.5	%
TC PIPELINES, LP
Unsecured Loan
U.S. dollars (2013 – US$380; 2012 – US$312)	2017	404	1.4	%	310	1.5	%
Medium-Term Loan
U.S. dollars (2013 - US$500)	2018	532	1.4	%	—	—
Senior Unsecured Notes
U.S. dollars (2013 and 2012 – US$350)	2021	372	4.7	%	348	4.7	%
		1,308			658
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. dollars (2013 – US$335; 2012 – US$354)	2018 to 2030	356	7.8	%	352	7.8	%
TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
U.S. dollars (2013 – US$24; 2012 – US$27)	2017	25	4.0	%	27	4.0	%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes²
U.S. dollars (2013 – US$110; 2012 – US$129)	2018	117	6.1	%	128	6.1	%
		22,865			18,913
Less: Current Portion of Long-Term Debt		973			894
		21,892			18,019


1	Interest rates are the effective interest rates except for those pertaining to Long-Term Debt issued for the Company's Canadian regulated 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	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)	2014	2015	2016	2017	2018
Principal repayments on Long-Term Debt	973	1,659	2,092	862	1,632

Schedule of interest expense



year ended December 31 (millions of Canadian dollars)	2013		2012		2011
Interest on Long-Term Debt	1,216		1,190		1,154
Interest on Junior Subordinated Notes	65		63		63
Interest on short-term debt	12		16		16
Capitalized interest	(287	)	(300	)	(302	)
Amortization and other financial charges¹	(21	)	7		6
	985		976		937


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.

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

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 235
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

Schedule of provision for income taxes

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Current
Canada	27	167	212
Foreign	16	14	(2	)
	43	181	210
Deferred
Canada	245	69	139
Foreign	323	216	226
	568	285	365
Income Tax Expense	611	466	575

Schedule of geographic components of income



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Canada	1,224	842	1,176
Foreign	1,298	1,096	1,109
Income before Income Taxes	2,522	1,938	2,285

Schedule of reconciliation of income tax expense



year ended December 31 (millions of Canadian dollars)	2013		2012		2011
Income before Income Taxes	2,522		1,938		2,285
Federal and provincial statutory tax rate	25.0	%	25.0	%	26.5	%
Expected income tax expense	631		485		605
Income tax differential related to regulated operations	(13	)	41		42
Higher/(lower) effective foreign tax rates	46		1		(5	)
Income from equity investments and non-controlling interests	(41	)	(40	)	(45	)
Tax legislation change	(25	)	—		—
Other	13		(21	)	(22	)
Actual Income Tax Expense	611		466		575

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



at December 31 (millions of Canadian dollars)	2013	2012
Deferred Income Tax Assets
Operating loss carryforwards	826	1,024
Deferred amounts	223	112
Other	128	239
	1,177	1,375
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, equipment and PPAs	4,245	3,817
Equity investments	682	578
Taxes on future revenue requirement	291	283
Unrealized foreign exchange gains on long-term debt	35	159
Other	170	96
	5,423	4,933
Net Deferred Income Tax Liabilities	4,246	3,558

The above deferred tax amounts have been classified in the Consolidated Balance Sheet as follows:



at December 31 (millions of Canadian dollars)	2013	2012
Deferred Income Tax Assets
Other Current Assets (Note 5)	119	290
Intangible and Other Assets (Note 11)	225	168
	344	458
Deferred Income Tax Liabilities
Accounts Payable and Other (Note 13)	26	—
Deferred Income Tax Liabilities	4,564	4,016
	4,590	4,016
Net Deferred Income Tax Liabilities	4,246	3,558

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 (millions of Canadian dollars)	2013		2012		2011
Unrecognized tax benefits at beginning of year	49		52		62
Gross increases – tax positions in prior years	3		2		9
Gross decreases – tax positions in prior years	(28	)	(6	)	(7	)
Gross increases – tax positions in current year	2		9		11
Lapses of statute of limitations	(3	)	(8	)	(23	)
Unrecognized tax benefits at end of year	23		49		52

JUNIOR SUBORDINATED NOTES (Tables)

12 Months Ended

Dec. 31, 2013

Junior Subordinated Notes [Abstract]

Schedule of junior subordinated notes



		2013			2012
Outstanding loan amount (millions of Canadian dollars)	Maturity Date	Outstanding December 31	Effective Interest Rate		Outstanding December 31	Effective Interest Rate
TRANSCANADA PIPELINES LIMITED
U.S. dollars (2013 and 2012 – US$1,000)	2067	1,063	6.5	%	994	6.5	%

NON-CONTROLLING INTERESTS (Tables)

12 Months Ended

Dec. 31, 2013

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 (millions of Canadian dollars)	2013	2012
Non-controlling interest in TC PipeLines, LP¹	1,323	953
Preferred shares of TCPL	194	389
Non-controlling interest in Portland²	94	83
	1,611	1,425

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



year ended December 31 (millions of Canadian dollars)	2013	2012	2011
Non-controlling interest in TC PipeLines, LP¹	93	91	101
Preferred share dividends of TCPL	20	22	22
Non-controlling interest in Portland²	12	5	6
	125	118	129


2	The non-controlling interest in Portland as at December 31, 2013 represented the 38.3 per cent interest not owned by TransCanada (2012 and 2011 - 38.3 per cent).

Schedule of Preferred Shares of Subsidiary



at December 31	Number of Shares	Annual Dividend Rate per Share		Redemption Price per Share		2013	2012
	(thousands)					(millions of Canadian dollars)¹	(millions of Canadian dollars)¹
Cumulative First Preferred Shares of Subsidiary
Series U	4,000		$2.80		$50.00	—	195
Series Y	4,000		$2.80		$50.00	194	194
						194	389

COMMON SHARES (Tables)

12 Months Ended

Dec. 31, 2013

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

Schedule of common shares



	Number of Shares	Amount
	(thousands)	(millions of Canadian dollars)
Outstanding at January 1, 2011	696,230	11,745
Dividend reinvestment and share purchase plan	5,371	202
Exercise of options	2,260	64
Outstanding at December 31, 2011	703,861	12,011
Exercise of options	1,600	58
Outstanding at December 31, 2012	705,461	12,069
Exercise of options	1,980	80
Outstanding at December 31, 2013	707,441	12,149

Schedule of weighted average shares



Weighted Average Common Shares Outstanding (millions)	2013	2012	2011
Basic	706.7	704.6	701.6
Diluted	707.7	705.7	702.8

Schedule of stock options activity



	Number of Options		Weighted Average Exercise Prices		Options Exercisable
	(thousands)				(thousands)
Outstanding at January 1, 2011	8,406			$32.57	6,458
Granted	970			$38.02
Exercised	(2,260	)		$25.86
Forfeited	(16	)		$35.83
Outstanding at December 31, 2011	7,100			$35.44	5,165
Granted	1,978			$42.03
Exercised	(1,600	)		$33.13
Forfeited	(44	)		$36.55
Outstanding at December 31, 2012	7,434			$37.69	4,588
Granted	1,939			$47.09
Exercised	(1,980	)		$36.12
Outstanding at December 31, 2013	7,393			$40.57	3,954

Schedule of stock options outstanding and exercisable by the range of exercise price

Stock options outstanding at December 31, 2013 were as follows:



	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
	(thousands)			(years)	(thousands)			(years)
$30.10 to $36.26	1,725		$33.72	2.5	1,725		$33.72	2.5
$36.90 to $41.65	1,781		$38.52	3.7	1,516		$38.60	3.5
$41.95 to $45.29	1,948		$42.03	5.2	690		$42.03	5.2
$47.09	1,939		$47.09	6.1	23		$47.09	6.1
	7,393		$40.57	4.3	3,954		$37.12	3.1

Schedule of options valuation assumptions

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



	2013		2012		2011
Expected life (years)	6.0		5.9		4.0
Interest rate	1.7	%	1.6	%	2.1	%
Volatility¹	18	%	19	%	14	%
Dividend yield	3.7	%	4.2	%	4.3	%
Forfeiture rate	15	%	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 (millions of Canadian dollars unless noted otherwise)	2013	2012	2011
Total intrinsic value of options exercised	$25	$18	$34
Fair value of options that have vested	$65	$49	$42
Total options vested	1.3 million	1.0 million	0.9 million

Schedule of dividends

The following table summarizes cash dividends paid:



year ended December 31 (millions of Canadian dollars except per share amounts)	2013	2012	2011
Cash dividends paid, net of Dividend Reinvestment Plan	1,285	1,226	961
Cash dividends paid per common share	$1.82	$1.74	$1.66

PREFERRED SHARES (Tables)

12 Months Ended

Dec. 31, 2013

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

Schedule of preferred shares



at December 31	Number of Shares Authorized and Outstanding	Annual Dividend Rate per Share		Redemption Price per Share		2013	2012
	(thousands)					(millions of Canadian dollars)¹	(millions of Canadian dollars)¹
Cumulative First Preferred Shares
Series 1	22,000		$1.15		$25.00	539	539
Series 3	14,000		$1.00		$25.00	343	343
Series 5	14,000		$1.10		$25.00	342	342
Series 7	24,000		$1.00		$25.00	589	—
						1,813	1,224


1	Net of underwriting commissions and deferred income taxes.

Schedule of preferred dividends

The Company has paid preferred share cash dividends as follows:



	2013				2012		2011
at December 31 (millions of Canadian dollars, except per share amounts)	Cash Dividend Payments¹		Annual Dividend Rate per Share		Cash Dividend Payments	Annual Dividend Rate per Share	Cash Dividend Payments (net of DRP)	Annual Dividend Rate per Share
Cumulative First Preferred Shares
Series 1	25		$1.15		25	$1.15	25	$1.15
Series 3	14		$1.00		14	$1.00	14	$1.00
Series 5	16		$1.10		16	$1.10	16	$1.10
Series 7	16	²	$1.00	²	—	—	—	—
	71				55		55


1	At December 31, 2013, there were dividends declared but not yet paid of $10 million (2012 - $4 million) included in Accounts Payable and Other (Note 13) which was paid on January 30, 2014.


2	For the year ended December 31, 2013, the cash dividend rate was prorated at $0.65 per share.

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

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 480
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
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-Article 5

Schedule of components of other comprehensive income

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Components of OCI including Non-Controlling Interests and the related tax effects are as follows:



year ended December 31, 2013 (millions of Canadian dollars)	Before tax amount		Income tax recovery/(expense)		Net of tax amount
Foreign currency translation gains and losses 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 (millions of Canadian dollars)	Before tax amount		Income tax recovery/(expense)		Net of tax amount
Foreign currency translation gains and 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	)



year ended December 31, 2011 (millions of Canadian dollars)	Before tax amount		Income tax recovery/(expense)		Net of tax amount
Foreign currency translation gains and losses on net investments in foreign operations	108		29		137
Change in fair value of net investment hedges	(101	)	28		(73	)
Change in fair value of cash flow hedges	(318	)	106		(212	)
Reclassification to Net Income of gains and losses on cash flow hedges	224		(77	)	147
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(119	)	30		(89	)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	13		(3	)	10
Other comprehensive loss on Equity Investments	(94	)	3		(91	)
Other comprehensive (loss)/income	(287	)	116		(171	)

Schedule of changes in accumulated other comprehensive income

The changes in AOCI by component is as follows:



	Currency translation adjustments		Cash flow hedges		Pension and OPEB plan adjustments		Equity Investments		Total¹
AOCI Balance at January 1, 2011	(683	)	(226	)	(157	)	(177	)	(1,243	)
Other comprehensive income/(loss) before reclassifications²	40		(213	)	(89	)	(83	)	(345	)
Amounts reclassified from Accumulated Other Comprehensive Loss	—		137		10		(8	)	139
Net current period other comprehensive income/(loss)	40		(76	)	(79	)	(91	)	(206	)
AOCI Balance at December 31, 2011	(643	)	(302	)	(236	)	(268	)	(1,449	)
Other comprehensive 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 Loss³	—		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	)


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 $66 million in 2013 (2012 - $21 million losses; 2011 - $35 million gains).

Schedule of reclassifications out of accumulated other comprehensive income

Details about reclassifications out of AOCI into the Consolidated Statement of Income are as follows:



	Amounts reclassified from accumulated other comprehensive loss¹				Affected line item in the consolidated statement of income
year ended December 31 (millions of Canadian dollars)	2013		2012		Affected line item in the consolidated statement of income
Cash flow hedges
Power and Natural Gas	(44	)	(201	)	Revenue (Energy)
Interest	(16	)	(18	)	Interest Expense
	(60	)	(219	)	Income before Income Taxes
	19		81		Income Tax Expense
	(41	)	(138	)	Net of tax
Pension and other post-retirement plan adjustments
Amortization of net loss²	(34	)	(22	)	Total before tax
	11		—		Income before Income Taxes
	(23	)	(22	)	Net of tax
Equity Investments
Equity Income	(20	)	5		Income from Equity Investments
	5		(2	)	Income Tax Expense
	(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 POST-RETIREMENT BENEFITS (Tables)

12 Months Ended

Dec. 31, 2013

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 (millions of Canadian dollars)	2013	2012	2011
DB Plans	79	83	62
Other post-retirement benefit plans	6	7	8
Savings and DC Plans	29	24	23
	114	114	93

Schedule of change in benefit obligations, change in plan assets, and funded status



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

Change in Benefit Obligation¹
Benefit obligation – beginning of year	2,142		1,836		186		170
Service cost	84		66		2		2
Interest cost	96		94		7		8
Employee contributions	4		4		—		1
Benefits paid	(83	)	(79	)	(7	)	(9	)
Actuarial (gain)/loss	(39	)	227		(2	)	16
Foreign exchange rate changes	20		(6	)	5		(2	)
Benefit obligation – end of year	2,224		2,142		191		186
Change in Plan Assets
Plan assets at fair value – beginning of year	1,825		1,656		32		29
Actual return on plan assets	313		165		2		4
Employer contributions²	79		83		6		7
Employee contributions	4		4		—		1
Benefits paid	(83	)	(79	)	(7	)	(9	)
Foreign exchange rate changes	14		(4	)	2		—
Plan assets at fair value – end of year	2,152		1,825		35		32
Funded Status – Plan Deficit	(72	)	(317	)	(156	)	(154	)


1	The benefit obligation for the Company's pension benefit plan 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 $134 million in letters of credit provided to Canadian DB Plan for funding purposes.

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 (millions of Canadian dollars)	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31 (millions of Canadian dollars)	2013		2012		2013		2012
Intangible and Other Assets (Note 11)	—		—		16		11
Other Long-Term Liabilities (Note 14)	(72	)	(317	)	(172	)	(165	)
	(72	)	(317	)	(156	)	(154	)

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 (millions of Canadian dollars)	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31 (millions of Canadian dollars)	2013		2012		2013		2012
Projected benefit obligation¹	(2,224	)	(2,142	)	(172	)	(165	)
Plan assets at fair value	2,152		1,825		—		—
Funded Status – Deficit	(72	)	(317	)	(172	)	(165	)


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 (millions of Canadian dollars)	2013		2012
Accumulated benefit obligation	(2,039	)	(1,966	)
Plan assets at fair value	2,152		1,825
Funded Status – Surplus/(Deficit)	113		(141	)

Schedule of accumulated benefit obligations in excess of fair value of plan assets for plans not fully funded



at December 31 (millions of Canadian dollars)	2013		2012
Accumulated benefit obligation	(569	)	(1,966	)
Plan assets at fair value	537		1,825
Funded Status – Deficit	(32	)	(141	)

Schedule of the Company's pension plans weighted average asset allocations and target allocations by asset category



	Percentage of Plan Assets				Target Allocations¹
at December 31	2013		2012		2013
Debt securities	31	%	36	%	25% to 35%
Equity securities	69	%	64	%	50% to 70%
Alternatives	—		—		5 % to 15%
	100	%	100	%


1	Target allocations were revised in November 2013 and the investment mix is being adjusted 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 (millions of Canadian dollars)			Percentage of Plan Assets
at December 31 (millions of Canadian dollars)	2013	2012	2013		2012
Debt securities	2	2	0.1	%	0.1	%
Equity securities	2	3	0.1	%	0.2	%

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 (millions of Canadian dollars)	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
at December 31 (millions of Canadian dollars)	2013	2012	2013	2012	2013	2012	2013	2012	2013		2012
Asset Category
Cash and Cash Equivalents	17	17	—	—	—	—	17	17	1	%	1	%
Equity Securities:
Canadian	474	400	170	113	—	—	644	513	29	%	28	%
U.S.	423	309	37	38	—	—	460	347	21	%	19	%
International	36	31	330	263	—	—	366	294	17	%	16	%
Global	—	—	14	13	—	—	14	13	1	%	—
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	304	314	—	—	304	314	14	%	17	%
Provincial	—	—	154	161	—	—	154	161	7	%	9	%
Municipal	—	—	6	5	—	—	6	5	—		—
Corporate	—	—	77	65	—	—	77	65	3	%	4	%
U.S. Bonds:
State	—	—	33	33	—	—	33	33	2	%	2	%
Corporate	—	—	48	45	—	—	48	45	2	%	2	%
International:
Corporate	—	—	20	9	—	—	20	9	1	%	—
Mortgage Backed	—	—	26	22	—	—	26	22	1	%	1	%
Other Investments:
Private Equity Funds	—	—	—	—	18	19	18	19	1	%	1	%
	950	757	1,219	1,081	18	19	2,187	1,857	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 Equity Funds

Balance at December 31, 2011	20
Realized and unrealized losses	(1	)
Balance at December 31, 2012	19
Purchases and sales	(4	)
Realized and unrealized gains	3
Balance at December 31, 2013	18

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 Benefits	Other Post- Retirement Benefits
2014	93	9
2015	100	9
2016	106	10
2017	112	11
2018	118	11
2019 to 2023	684	58

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	2013		2012		2013		2012
Discount rate	4.95	%	4.35	%	5.00	%	4.35	%
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 Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2013		2012		2011		2013		2012		2011
Discount rate	4.35	%	5.05	%	5.55	%	4.35	%	5.10	%	5.60	%
Expected long-term rate of return on plan assets	6.70	%	6.70	%	6.95	%	4.60	%	6.40	%	6.40	%
Rate of compensation increase	3.15	%	3.15	%	3.10	%	—		—		—

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
Effect on total of service and interest cost components	1	—
Effect on post-retirement benefit obligation	18	(15	)

Schedule of the Company's net benefit cost

The Company's net benefit cost is as follows:



at December 31 (millions of Canadian dollars)	Pension Benefit Plans						Other Post-Retirement Benefit Plans
at December 31 (millions of Canadian dollars)	2013		2012		2011		2013		2012		2011
Service cost	84		66		54		2		2		2
Interest cost	96		94		91		7		8		9
Expected return on plan assets	(120	)	(113	)	(114	)	(2	)	(2	)	(2	)
Amortization of actuarial loss	30		18		10		2		1		1
Amortization of past service cost	2		2		2		—		1		—
Amortization of regulatory asset	30		19		12		1		1		1
Amortization of transitional obligation related to regulated business	—		—		—		2		2		2
Net Benefit Cost Recognized	122		86		55		12		13		13

Schedule of the pre-tax amounts recognized in AOCI

Pre-tax amounts recognized in AOCI were as follows:



	2013		2012		2011
at December 31 (millions of Canadian dollars)	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
Net loss	236	32	362	33	282	29
Prior service cost	3	1	5	2	7	2
	239	33	367	35	289	31

Schedule of the pre-tax amounts recognized in OCI

Pre-tax amounts recognized in OCI were as follows:



at December 31 (millions of Canadian dollars)	2013				2012				2011
at December 31 (millions of Canadian dollars)	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits
Amortization of net loss from AOCI to OCI	(30	)	(2	)	(19	)	(1	)	(10	)	(1	)
Amortization of prior service costs from AOCI to OCI	(2	)	—		(2	)	—		(2	)	—
Funded status adjustment	(96	)	—		99		5		113		6
	(128	)	(2	)	78		4		101		5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2013

Derivative financial instruments

Schedule of the carrying and fair values of non-derivative financial instruments



	2013				2012
at December 31 (millions of Canadian dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Notes receivable and other¹	226		269		237		286
Available for sale assets²	47		47		44		44
Current and Long-Term Debt^3,4 (Note 15)	(22,865	)	(26,134	)	(18,913	)	(24,573	)
Junior Subordinated Notes (Note 17)	(1,063	)	(1,093	)	(994	)	(1,054	)
	(23,655	)	(26,911	)	(19,626	)	(25,297	)


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$200 million (2012 - US$350 million) that is attributed to hedged risk and recorded at fair value.

Schedule of the remaining contractual maturities for the non-derivative financial liabilities, including both the principal and interest cash flows

Contractual Principal Repayments of Non-Derivative Financial Liabilities



at December 31 (millions of Canadian dollars)	Total	2014	2015 and 2016	2017 and 2018	2019 and Thereafter
Notes Payable (Note 12)	1,842	1,842	—	—	—
Long-Term Debt (Note 15)	22,865	973	3,751	2,494	15,647
Junior Subordinated Notes (Note 17)	1,063	—	—	—	1,063
	25,770	2,815	3,751	2,494	16,710

Interest Payments on Non-Derivative Financial Liabilities



at December 31 (millions of Canadian dollars)	Total	2014	2015 and 2016	2017 and 2018	2019 and Thereafter
Long-Term Debt (Note 15)	16,798	1,254	2,315	2,111	11,118
Junior Subordinated Notes (Note 17)	3,614	68	135	135	3,276
	20,412	1,322	2,450	2,246	14,394

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 (millions of Canadian dollars)	2013		2012
Other Current Assets (Note 5)	395		259
Intangible and Other Assets (Note 11)	112		187
Accounts Payable and Other (Note 13)	(357	)	(283	)
Other Long-Term Liabilities (Note 14)	(255	)	(186	)
	(105	)	(23	)

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 (millions of Canadian dollars, pre-tax)	2013		2012
Change in fair value of derivative instruments recognized in OCI (effective portion)¹
Power	117		83
Natural Gas	(1	)	(21	)
Foreign Exchange	5		(1	)
	121		61
Reclassification of gains on derivative instruments from AOCI to Net Income (effective portion)¹
Power²	40		147
Natural Gas²	4		54
Interest	16		18
	60		219
Gains on derivative instruments recognized in Net Income (ineffective portion)
Power	8		7
	8		7


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.

Schedule of offsetting assets



at December 31, 2012 (millions of Canadian dollars)	Gross derivative instruments presented on the balance sheet		Amounts available for offset¹		Net amounts
Derivative - Asset
Power	215		(132	)	83
Natural Gas	88		(83	)	5
Foreign exchange	119		(37	)	82
Interest	24		(6	)	18
	446		(258	)	188
Derivative - Liability
Power	(273	)	132		(141	)
Natural gas	(106	)	83		(23	)
Foreign exchange	(76	)	37		(39	)
Interest	(14	)	6		(8	)
	(469	)	258		(211	)


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



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



at December 31, 2012 (millions of Canadian dollars)	Gross derivative instruments presented on the balance sheet		Amounts available for offset¹		Net amounts
Derivative - Asset
Power	215		(132	)	83
Natural Gas	88		(83	)	5
Foreign exchange	119		(37	)	82
Interest	24		(6	)	18
	446		(258	)	188
Derivative - Liability
Power	(273	)	132		(141	)
Natural gas	(106	)	83		(23	)
Foreign exchange	(76	)	37		(39	)
Interest	(14	)	6		(8	)
	(469	)	258		(211	)


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 2013, are categorized as follows:



at December 31, 2013 (millions of Canadian dollars, pre-tax)	Quoted prices in active markets Level I¹		Significant other observable inputs Level II¹		Significant unobservable inputs Level III¹		Total
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 fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2012, are categorized as follows:



at December 31, 2012 (millions of Canadian dollars, pre-tax)	Quoted prices in active markets Level I¹		Significant other observable inputs Level II¹		Significant unobservable inputs Level III¹		Total
Derivative Instrument Assets:
Power commodity contracts	—		213		2		215
Natural gas commodity contracts	75		13		—		88
Foreign exchange contracts	—		119		—		119
Interest rate contracts	—		24		—		24
Derivative Instrument Liabilities:
Power commodity contracts	—		(269	)	(4	)	(273	)
Natural gas commodity contracts	(95	)	(11	)	—		(106	)
Foreign exchange contracts	—		(76	)	—		(76	)
Interest rate contracts	—		(14	)	—		(14	)
Non-Derivative Financial Instruments:
Available for sale assets	—		44		—		44
	(20	)	43		(2	)	21


1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2012

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)	2013		2012
Balance at beginning of year	(2	)	(15	)
Settlements	—		(1	)
Transfers out of Level III	(2	)	(21	)
Total (losses)/gains included in Net Income	(1	)	11
Total gains included in OCI	6		24
Balance at end of year¹	1		(2	)


1	Energy Revenues include unrealized gains or losses attributed to derivatives in the Level III category that were still held at December 31, 2013 of nil (2012 – $1 million)

Designated as a net investment hedge

Derivative financial instruments

Schedule of fair values and notional or principal amounts for the derivatives



	2013				2012
at December 31 (millions of Canadian dollars unless noted otherwise)	Fair Value¹		Notional or Principal Amount		Fair Value¹	Notional or Principal Amount
U.S. dollar cross-currency interest rate swaps (maturing 2014 to 2019)²	(201	)	US	3,800	82	US	3,800
U.S. dollar foreign exchange forward contracts (maturing 2014)	(11	)	US	850	—	US	250
	(212	)	US	4,650	82	US	4,050


1	Fair values approximate carrying values.


2	In 2013, net realized gains of $29 million (2012 – gains of $30 million) related to the interest component of cross-currency swap settlements are included in Interest Expense.

Schedule of the carrying and fair values of non-derivative financial instruments



at December 31 (millions of Canadian dollars unless noted otherwise)	2013		2012
Carrying value	14,200	(US 13,400)	11,100	(US 11,200)
Fair value	16,000	(US 15,000)	14,300	(US 14,400)

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 (millions of Canadian dollars)	2013		2012
Other Current Assets (Note 5)	5		71
Intangible and Other Assets (Note 11)	—		47
Accounts Payable and Other (Note 13)	(50	)	(6	)
Other Long-Term Liabilities (Note 14)	(167	)	(30	)
	(212	)	82

Derivative financial instrument, excluding net investment hedges

Derivative financial instruments

Schedule of fair values and notional or principal amounts for the derivatives



(millions of Canadian dollars unless noted otherwise)	Power			Natural Gas			Foreign Exchange			Interest
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 Relationships^5,6
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	All derivative instruments held for trading have been entered into for risk management purposes and 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.


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.



(millions of Canadian dollars unless noted otherwise)	Power			Natural Gas			Foreign Exchange			Interest
Derivative Instruments Held for Trading¹
Fair Values²
Assets		$139			$88			$1			$14
Liabilities		($176	)		($104	)		($2	)		($14	)
Notional Values
Volumes³
Purchases	31,135			83			—			—
Sales	31,066			65			—			—
Canadian dollars	—			—			—			620
U.S. dollars	—			—			US 1,408			US 200
Net unrealized (losses)/gains in the year⁴		($30	)		$2			($1	)		$—
Net realized gains/(losses) in the year⁴		$5			($10	)		$26			$—
Maturity dates	2013-2017			2013-2016			2013			2013-2016

Derivative Instruments in Hedging Relationships^5,6
Fair Values²
Assets		$76			$—			$—			$10
Liabilities		($97	)		($2	)		($38	)		$—
Notional Values
Volumes³
Purchases	15,184			1			—			—
Sales	7,200			—			—			—
U.S. dollars	—			—			US 12			US 350
Cross-currency	—			—			136/US 100			—
Net realized (losses)/gains in the year⁴		($130	)		($23	)		$—			$7
Maturity dates	2013-2018			2013			2013-2014			2013-2015


1	All derivative instruments held for trading have been entered into for risk management purposes and 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.


6	In 2012, 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.

CHANGES IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2013

CHANGES IN OPERATING WORKING CAPITAL

Schedule of changes in operating working capital



year ended December 31 (millions of Canadian dollars)	2013		2012	2011
(Increase)/decrease in Accounts Receivable	(54	)	67	(15	)
(Increase)/decrease in Inventories	(30	)	27	3
Decrease/(increase) in Other Current Assets	40		66	(27	)
(Decrease)/increase in Accounts Payable and Other	(290	)	127	266
Increase in Accrued Interest	8		—	8
(Increase)/Decrease in Operating Working Capital	(326	)	287	235

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2013

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 (millions of Canadian dollars)	Minimum Lease Payments	Amounts Recoverable under Sub-leases	Net Payments
2014	98	8	90
2015	97	7	90
2016	92	5	87
2017	86	5	81
2018	82	3	79
2019 and thereafter	325	—	325
	780	28	752

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:



		2013		2012
year ended December 31 (millions of Canadian dollars)	Term	Potential Exposure¹	Carrying Value	Potential Exposure¹	Carrying Value
Bruce Power	Ranging to 2019²	629	8	897	10
Other jointly owned entities	Ranging to 2040	51	10	89	7
		680	18	986	17


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


2	Except for one guarantee with no termination date.

DESCRIPTION OF TRANSCANADA'S BUSINESS (Details) - segment

12 Months Ended

Dec. 31, 2013

May 31, 2013

Apr. 30, 2013

Dec. 31, 2012

May 31, 2011

Apr. 30, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Number of business segments in which the entity operates

TC PipeLines, LP

Natural Gas Pipelines | TC PipeLines, LP

28.90%

33.30%

38.20%

Natural Gas Pipelines | TQM

28.90%

Natural Gas Pipelines | Northern Border

50.00%

Natural Gas Pipelines | Northern Border | TC PipeLines, LP

14.50%

16.70%

Natural Gas Pipelines | Iroquois

50.00%

Natural Gas Pipelines | Great Lakes

44.50%

Combined effective ownership interest (as a percent)

53.60%

67.00%

Natural Gas Pipelines | Great Lakes | TC PipeLines, LP

Natural Gas Pipelines | GTN

46.40%

Combined effective ownership interest (as a percent)

30.00%

50.20%

Natural Gas Pipelines | GTN | TC PipeLines, LP

Natural Gas Pipelines | Bison

70.00%

Combined effective ownership interest (as a percent)

30.00%

50.20%

Natural Gas Pipelines | Bison | TC PipeLines, LP

Natural Gas Pipelines | Portland

70.00%

Natural Gas Pipelines | North Baja

61.70%

Combined effective ownership interest (as a percent)

28.90%

Natural Gas Pipelines | North Baja | TC PipeLines, LP

Natural Gas Pipelines | Tuscarora

100.00%

Combined effective ownership interest (as a percent)

28.90%

Natural Gas Pipelines | Tuscarora | TC PipeLines, LP

100.00%

Energy | Sundance A

Interest purchased (as a percent)

100.00%

Energy | Sheerness

Interest purchased (as a percent)

100.00%

Energy | Bruce A

^[1]

48.90%

Energy | Bruce B

Energy | Portlands Energy

^[1]

31.60%

Energy | ASTC Power Partnership

50.00%

50.00%

Energy | Cartier Wind

62.00%

[1]	At December 31, 2013, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $820 million (2012 – $889 million) due to the fair value assessment of assets at the time of acquisition.

ACCOUNTING POLICIES (Details)	12 Months Ended
ACCOUNTING POLICIES (Details)	Dec. 31, 2013 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%
Oil Pipelines \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.00%
Oil Pipelines \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.50%
Oil Pipelines \| Pumping equipment \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.00%
Oil 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) - CAD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

$ 8,797

$ 8,007

$ 7,839

597

257

415

Commodity Purchases Resold

(2,674)

(2,577)

(2,358)

(1,317)

(1,049)

(991)

(445)

(434)

(410)

1,485

1,375

1,328

Interest Income and Other

3,473

2,829

3,167

Interest Expense

(985)

(976)

(937)

2,522

1,938

2,285

Net Income Attributable to Non-Controlling Interests

(611)

(466)

(575)

Net Income

1,911

1,472

1,710

(125)

(118)

(129)

Preferred Share Dividends

1,786

1,354

1,581

(74)

(55)

Net Income Attributable to Common Shares

1,712

1,299

1,526

53,898

48,396

8,797

8,007

7,839

37,606

33,713

4,461

2,595

2,513

Canada

18,462

18,054

Canada - domestic

4,659

3,527

3,929

4,659

3,527

3,929

Canada - export

997

1,121

1,087

997

1,121

1,087

United States

3,029

3,252

2,752

3,029

3,252

2,752

17,570

14,904

Mexico

112

107

112

107

1,574

755

Corporate

(108)

(97)

(86)

(124)

(111)

(100)

1,733

1,544

130

100

Natural Gas Pipelines | Operating segments

4,497

4,264

4,244

145

157

159

(1,405)

(1,365)

(1,221)

(329)

(315)

(307)

1,027

933

923

1,881

1,808

1,952

25,165

23,210

4,497

4,264

4,244

^[1]

18,704

17,548

Oil Pipelines | Operating segments

1,776

1,389

917

1,124

1,039

827

^[2]

(328)

(296)

(209)

^[2]

(44)

(45)

(31)

^[2]

149

145

130

^[2]

603

553

457

^[2]

13,253

10,485

1,124

1,039

827

^[2]

12,740

10,232

Energy | Operating segments

2,483

1,145

1,204

3,176

2,704

2,768

452

100

256

Commodity Purchases Resold

(833)

(819)

(842)

(1,317)

(1,049)

(991)

(72)

(74)

(72)

293

283

261

1,113

579

858

13,747

13,157

3,176

2,704

2,768

6,032

5,833

$ 152

$ 24

$ 384

[1]	In 2013, the Company capitalized $37 million (2012 – $32 million) relating to the equity portion of AFUDC for natural gas pipelines with a corresponding amount recorded in Interest Income and Other.
[2]	Commencing in February 2011, TransCanada began recording earnings for the Keystone Pipeline System.

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Other Assets [Abstract]
Fair value of derivative contracts (Note 23)	$ 395	$ 259
Deferred income tax assets (Note 16)	119	290
Assets held for sale (Note 6)	85	0
Regulatory Assets (Note 9)	42	178
Other	206	270
Total other current assets	$ 847	$ 997

ASSETS HELD FOR SALE (Details) - CAD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
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	$ 0
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 (Details)
$ in Millions

12 Months Ended

Dec. 31, 2013

CAD ($)

facility

Dec. 31, 2012

CAD ($)

Dec. 31, 2011

CAD ($)

$ 55,457

$ 50,253

17,851

16,540

37,606

33,713

Mexico

1,574

755

Natural Gas Pipelines

Amount capitalized relating to the equity portion of AFUDC

Oil Pipelines | Keystone | Under construction

Amount of construction in progress, which remains subject to regulatory approvals

2,600

2,000

Energy | Facilities under PPAs

640

601

Revenues recognized through the sale of electricity

$ 53

Operating segments | Natural Gas Pipelines

^[1]

34,427

32,330

^[1]

15,723

14,782

Operating segments | Natural Gas Pipelines | Pipeline | Mexico

^[1]

18,704

17,548

^[1]

641

536

^[1]

Operating segments | Natural Gas Pipelines | Canadian Mainline

^[1]

551

477

^[1]

12,856

12,725

^[1]

7,592

7,254

Operating segments | Natural Gas Pipelines | Canadian Mainline | Pipeline

^[1]

5,264

5,471

^[1]

8,970

8,801

^[1]

5,457

5,192

Operating segments | Natural Gas Pipelines | Canadian Mainline | Compression

^[1]

3,513

3,609

^[1]

3,392

3,370

^[1]

1,961

1,880

Operating segments | Natural Gas Pipelines | Canadian Mainline | Metering and other

^[1]

1,431

1,490

^[1]

409

391

^[1]

174

182

Operating segments | Natural Gas Pipelines | Canadian Mainline | Property, plant and equipment excluding under construction

^[1]

235

209

^[1]

12,771

12,562

^[1]

7,592

7,254

Operating segments | Natural Gas Pipelines | Canadian Mainline | Under construction

^[1]

5,179

5,308

^[1]

163

Operating segments | Natural Gas Pipelines | NGTL System

^[1]

163

^[1]

11,088

10,520

^[1]

5,081

4,818

Operating segments | Natural Gas Pipelines | NGTL System | Pipeline

^[1]

6,007

5,702

^[1]

7,813

7,214

^[1]

3,410

3,221

Operating segments | Natural Gas Pipelines | NGTL System | Compression

^[1]

4,403

3,993

^[1]

2,038

1,885

^[1]

1,253

1,177

Operating segments | Natural Gas Pipelines | NGTL System | Metering and other

^[1]

785

708

^[1]

947

958

^[1]

418

420

Operating segments | Natural Gas Pipelines | NGTL System | Property, plant and equipment excluding under construction

^[1]

529

538

^[1]

10,798

10,057

^[1]

5,081

4,818

Operating segments | Natural Gas Pipelines | NGTL System | Under construction

^[1]

5,717

5,239

^[1]

290

463

Operating segments | Natural Gas Pipelines | ANR

^[1]

290

463

^[1]

2,159

1,961

^[1]

231

202

Operating segments | Natural Gas Pipelines | ANR | Pipeline

^[1]

1,928

1,759

^[1]

922

864

^[1]

Operating segments | Natural Gas Pipelines | ANR | Compression

^[1]

863

815

^[1]

635

514

^[1]

Operating segments | Natural Gas Pipelines | ANR | Metering and other

^[1]

554

442

^[1]

535

520

^[1]

Operating segments | Natural Gas Pipelines | ANR | Property, plant and equipment excluding under construction

^[1]

444

439

^[1]

2,092

1,898

^[1]

231

202

Operating segments | Natural Gas Pipelines | ANR | Under construction

^[1]

1,861

1,696

^[1]

Operating segments | Natural Gas Pipelines | Other Natural Gas Pipelines

^[1]

^[1]

8,324

7,124

^[1]

2,819

2,508

Operating segments | Natural Gas Pipelines | Other Natural Gas Pipelines | Property, plant and equipment excluding under construction

^[1]

5,505

4,616

^[1]

7,277

6,827

^[1]

2,819

2,508

Operating segments | Natural Gas Pipelines | Other Natural Gas Pipelines | Under construction

^[1]

4,458

4,319

^[1]

1,047

297

Operating segments | Natural Gas Pipelines | GTN | Pipeline

^[1]

1,047

297

^[1]

1,685

1,565

^[1]

488

411

Operating segments | Natural Gas Pipelines | Great Lakes | Pipeline

^[1]

1,197

1,154

^[1]

1,650

1,544

^[1]

833

750

Operating segments | Natural Gas Pipelines | Foothills | Pipeline

^[1]

817

794

^[1]

1,649

1,634

^[1]

1,120

1,062

Operating segments | Natural Gas Pipelines | Other | Pipeline

^[1]

529

572

^[1],[2]

1,652

1,548

^[1],[2]

288

226

Operating segments | Oil Pipelines

^[1],[2]

1,364

1,322

13,179

10,507

439

275

Operating segments | Oil Pipelines | Under construction

12,740

10,232

^[3]

6,020

3,678

Operating segments | Oil Pipelines | Keystone | Pipeline

^[3]

6,020

3,678

5,079

4,828

286

177

Operating segments | Oil Pipelines | Keystone | Property, plant and equipment excluding under construction

4,793

4,651

7,159

6,829

439

275

Operating segments | Oil Pipelines | Keystone | Pumping equipment

6,720

6,554

1,118

1,066

Operating segments | Oil Pipelines | Keystone | Tanks and other

1,036

1,015

962

935

Operating segments | Energy

891

888

7,660

7,262

1,628

1,429

Operating segments | Energy | Property, plant and equipment excluding under construction

6,032

5,833

7,606

7,126

1,628

1,429

Operating segments | Energy | Under construction

5,978

5,697

136

Operating segments | Energy | Natural Gas – Ravenswood

136

1,966

1,799

377

290

Operating segments | Energy | Natural Gas - Other

1,589

1,509

^[4],[5]

3,061

2,975

^[4],[5]

846

746

Operating segments | Energy | Hydro

^[4],[5]

2,215

2,229

673

634

126

106

Operating segments | Energy | Wind

547

528

946

907

155

118

Operating segments | Energy | Natural Gas Storage

791

789

677

Operating segments | Energy | Solar

585

594

^[6]

226

^[6]

Number of facilities acquired | facility

^[6]

$ 224

Operating segments | Energy | Other

$ 57

134

Corporate

191

154

$ 130

$ 100

[1]	In 2013, the Company capitalized $37 million (2012 – $32 million) relating to the equity portion of AFUDC for natural gas pipelines with a corresponding amount recorded in Interest Income and Other.
[2]	Includes Bison, Portland, North Baja, Tuscarora and Ventures LP.
[3]	Includes $2.6 billion for Keystone XL at December 31, 2013 (2012 – $2 billion). Keystone XL remains subject to regulatory approvals.
[4]	Includes Halton Hills, Coolidge, Bécancour, Ocean State Power, Mackay River and other natural gas-fired facilities.
[5]	Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $640 million and $78 million, respectively, at December 31, 2013 (2012 – $601 million and $55 million, respectively). Revenues of $78 million were recognized in 2013 (2012 – $73 million; 2011 – $53 million) through the sale of electricity under the related PPAs.
[6]	Includes the acquisitions in 2013 of four solar power facilities.

EQUITY INVESTMENTS (Details)
$ in Millions, $ in Millions

1 Months Ended

12 Months Ended

Dec. 31, 2012

CAD ($)

Dec. 31, 2013

CAD ($)

Dec. 31, 2012

CAD ($)

Dec. 31, 2011

CAD ($)

Dec. 31, 2013

USD ($)

May 31, 2013

Apr. 30, 2013

Dec. 31, 2012

USD ($)

Nov. 30, 2012

May 31, 2011

Apr. 30, 2011

Distributions received from equity investments

$ 5,366

$ 5,759

$ 5,366

725

436

$ 494

Returns of capital

120

101

Undistributed earnings

754

883

1,062

Income

Operating and Other Expenses

4,989

3,860

4,042

(3,536)

(3,090)

(2,989)

Net Income

1,390

717

929

597

257

415

Balance Sheet

Current assets

1,593

1,500

1,593

Non current assets

12,154

12,158

12,154

Current liabilities

(1,187)

(1,117)

(1,187)

Non current liabilities

$ (3,787)

$ (2,507)

$ (3,787)

TC PipeLines, LP

TransCanada ownership (as a percent)

33.30%

28.90%

33.30%

28.90%

33.30%

38.20%

Northern Border

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

$ 118

$ 119

Bruce Power

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

$ 889

$ 820

$ 889

Cross Alta Gas Storage and Services Ltd [Member]

Ownership interest after acquisition (as a percent)

40.00%

60.00%

100.00%

Natural Gas Pipelines | TC PipeLines, LP

TransCanada ownership (as a percent)

28.90%

Natural Gas Pipelines | Northern Border

16.70%

14.50%

16.70%

14.50%

16.70%

^[1],[2]

$ 511

$ 557

$ 511

Income

Natural Gas Pipelines | Northern Border | TC PipeLines, LP

^[1],[2]

$ 66

Natural Gas Pipelines | Iroquois

50.00%

44.50%

174

$ 188

174

Income

Natural Gas Pipelines | TQM

$ 41

50.00%

$ 76

Income

Natural Gas Pipelines | Other

Income

Energy | Other

^[3]

Income

^[3]

$ 1

Energy | Bruce A

^[4]

48.90%

^[4]

4,033

$ 3,988

4,033

Income

^[4]

$ 202

(149)

Energy | Bruce B

^[4]

31.60%

^[4]

$ 377

Income

Energy | ASTC Power Partnership

^[4]

$ 108

163

50.00%

$ 41

Income

Energy | Portlands Energy

$ 110

50.00%

341

$ 343

341

Income

Oil Pipelines | Grand Rapids

$ 31

$ 33

^[5]

50.00%

^[5]

$ 2

$ 70

$ 2

[1]	At December 31, 2013, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$118 million (2012 – US$119 million) due to the fair value assessment of assets at the time of acquisition.
[2]	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, 2013, TransCanada had an ownership interest in TC PipeLines, LP of 28.9 per cent (2012 and 2011 – 33.3 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.5 per cent (2012 and 2011 – 16.7 per cent).
[3]	D
[4]	At December 31, 2013, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $820 million (2012 – $889 million) due to the fair value assessment of assets at the time of acquisition.
[5]	In October 2012, TransCanada entered into a joint venture agreement with a third party to build this pipeline system to transport crude oil and diluent between the producing area northwest of Fort McMurray and the Edmonton/Heartland market region.

RATE-REGULATED BUSINESSES (Details)	1 Months Ended		11 Months Ended	12 Months Ended
RATE-REGULATED BUSINESSES (Details)	Nov. 30, 2013	Mar. 31, 2013	Dec. 31, 2010	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Rate-regulated business
Composite depreciation rate					305.00%
Forecast
Rate-regulated business
Composite depreciation rate				3.12%
Canadian Mainline \| Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity (as a percent)		11.50%				8.08%	8.08%
Deemed common equity (as a percent)		40.00%				40.00%	40.00%
Term of regulatory decisions		5 years			5 years		5 years
NGTL System \| Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity (as a percent)	10.10%		9.70%
Deemed common equity (as a percent)	40.00%		40.00%
ANR \| U.S. Regulated Operations \| TC Offshore LLC
Rate-regulated business
Period of operation after which cost and revenue study is required to be filed					3 years

RATE-REGULATED BUSINESSES (Details 2) - CAD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

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

$ 1,777

$ 1,807

178

Regulatory assets, noncurrent

1,735

1,629

Less: Current portion included in Accounts Payable

236

368

100

Regulated liabilities, noncurrent

229

268

Foreign exchange on long-term debt

Operating and debt-service regulatory liabilities

^[1]

150

Remaining Recovery/Settlement Period

^[2]

$ 5

^[2]

1 year

Other

^[3]

$ 147

134

Deferred income taxes

Operating and debt-service regulatory assets

^[4]

1,149

1,122

Remaining Recovery/ Settlement Period

^[2]

$ 16

171

^[2]

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

$ 76

(50)

$ 102

Adjustment account

Remaining Recovery/ Settlement Period

^[5]

$ 354

^[5]

31 years

Other

Other disclosures pertaining to regulated assets and liabilities

^[3]

$ 258

434

Other | Other

Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded

$ 189

$ 13

$ (106)

Minimum | Foreign exchange on long-term debt

Remaining Recovery/Settlement Period

^[1]

1 year

Maximum | Foreign exchange on long-term debt

Remaining Recovery/Settlement Period

^[1]

16 years

[1]	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.
[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 2013 would have been $76 million higher (2012 – $50 million lower; 2011 - $102 million higher) had these amounts not been recorded as regulatory assets and liabilities.
[3]	Pre-tax operating results in 2013 would have been $189 million higher (2012 – $13 million higher; 2011 - $106 million lower) had these amounts not been recorded as regulatory assets and liabilities.
[4]	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.
[5]	The LTAA was established in compliance with the NEB Decision which is comprised of amounts that are deferred and recovered in future years. The TSA, also established in the NEB Decision, includes the variances between revenue and costs. A positive balance in the TSA was realized in 2013 and, as specified in the NEB Decision, the TSA, net of incentive earnings, was combined with the LTAA on December 31, 2013.

GOODWILL (Details) - CAD ($) $ in Millions	12 Months Ended
GOODWILL (Details) - CAD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Goodwill
Balance at the beginning of the period	$ 3,458	$ 3,534
Foreign exchange rate changes	238	(76)
Balance at the end of the period	3,696	3,458
Natural Gas Pipelines
Goodwill
Balance at the beginning of the period	2,635	2,693
Foreign exchange rate changes	181	(58)
Balance at the end of the period	2,816	2,635
Energy
Goodwill
Balance at the beginning of the period	823	841
Foreign exchange rate changes	57	(18)
Balance at the end of the period	$ 880	$ 823

INTANGIBLE AND OTHER ASSETS (Details) - CAD ($)
$ in Millions

3 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Goodwill and Intangible Assets Disclosure [Abstract]

Capital projects under development

$ 571

$ 34

PPAs

324

376

Deferred income tax assets and charges (Note 16)

225

168

Loans and advances1

^[1]

183

196

Fair value of derivative contracts (Note 23)

112

187

Employee post-retirement benefits (Note 22)

Other

524

434

Intangibles and Other Assets

1,955

1,406

Note receivable

Notes receivable

$ 226

236

Interest rate on notes receivable

6.75%

Current portion of note receivable

$ 43

810

Accumulated Amortization

486

434

Expected annual amortization expense

324

376

Amortization expense

$ 52

2,522

1,938

2,285

Sheerness

Goodwill and Intangible Assets Disclosure [Abstract]

PPAs

273

312

585

Accumulated Amortization

312

273

Goodwill and Intangible Assets Disclosure [Abstract]

273

312

Sundance A

PPAs

225

Accumulated Amortization

174

161

Expected annual amortization expense

$ 51

Pre-tax charges

$ (50)

$ 30

$ 20

[1]	As at December 31, 2013, TransCanada held a $226 million (2012 – $236 million) note receivable from the seller of Ravenswood which bears interest at 6.75 per cent and matures in 2040. The current portion of the note receivable of $43 million (2012 – $40 million) is included in Other Current Assets.

NOTES PAYABLE (Details) $ in Millions, $ in Millions	12 Months Ended
NOTES PAYABLE (Details) $ in Millions, $ in Millions	Dec. 31, 2013 CAD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2011 CAD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Notes payable
Amount outstanding	$ 1,842.0	$ 2,275.0
Notes payable \| Canadian dollars
Notes payable
Amount outstanding	$ 751.0	$ 803.0
Weighted Average Interest Rate per Annum (as a percent)	1.20%	1.20%		1.20%	1.20%
Notes payable \| U.S. dollars
Notes payable
Amount outstanding	$ 1,091.0	$ 1,472.0		$ 1,025	$ 1,480
Weighted Average Interest Rate per Annum (as a percent)	0.30%	0.40%		0.30%	0.40%
Revolving and demand credit facilities
Notes payable
Remaining borrowing capacity	$ 6,200.0	$ 5,300.0
Committed, syndicated, revolving, extendible credit facility \| Trans Canada Keystone Pipe Line LP
Notes payable
Cost to maintain the facility	1.4	1.0	$ 4.0
Committed, syndicated, revolving, extendible credit facility \| TransCanada PipeLines Limited
Notes payable
Cost to maintain the facility	4.0	4.0	2.0
Committed, syndicated, revolving, extendible credit facility \| TCPL USA
Notes payable
Cost to maintain the facility	1.0	1.0	4.0
Committed, syndicated, revolving, extendible credit facility \| TAIL
Notes payable
Cost to maintain the facility	0.0	0.0	0.0
Committed, syndicated, revolving, extendible credit facility \| Canadian dollars \| TransCanada PipeLines Limited
Notes payable
Maximum borrowing capacity	3,000.0
Remaining borrowing capacity	3,000.0
Committed, syndicated, revolving, extendible credit facility \| U.S. dollars \| TCPL USA
Notes payable
Maximum borrowing capacity				$ 1,000
Remaining borrowing capacity				750
Committed, syndicated, revolving, extendible credit facility \| U.S. dollars \| TAIL
Notes payable
Maximum borrowing capacity				1,000
Remaining borrowing capacity				$ 1,000
Demand credit facility
Notes payable
Cost to maintain the facility	0.0	$ 0.0	$ 0.0
Demand credit facility \| Canadian dollars
Notes payable
Maximum borrowing capacity	1,100.0
Remaining borrowing capacity	$ 300.0

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Payables and Accruals [Abstract]
Trade payables	$ 866	$ 923
Fair value of derivative contracts (Note 23)	357	283
Dividends payable	338	320
Deferred Income Tax Liabilities (Note 16)	26	0
Regulatory Liabilities (Note 9)	7	100
Liabilities related to assets held for sale (Note 6)	5	0
Other	556	718
Accounts payable and other	$ 2,155	$ 2,344

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

+ References + Details

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Deferred Costs, Noncurrent [Abstract]
Employee post-retirement benefit (Note 22)	$ 244	$ 482
Fair value of derivative contracts (Note 23)	255	186
Asset retirement obligations	83	72
Guarantees (Note 26)	18	17
Other	56	125
Other Long-Term Liabilities	$ 656	$ 882

LONG-TERM DEBT (Details)

1 Months Ended

12 Months Ended

Oct. 31, 2013

USD ($)

Aug. 31, 2013

USD ($)

Jul. 31, 2013

CAD ($)

Jul. 31, 2013

USD ($)

Jun. 30, 2013

USD ($)

Feb. 28, 2013

USD ($)

Jan. 31, 2013

USD ($)

Dec. 31, 2012

USD ($)

Aug. 31, 2012

USD ($)

May 31, 2012

USD ($)

Mar. 31, 2012

USD ($)

Dec. 31, 2011

USD ($)

Nov. 30, 2011

CAD ($)

Jun. 30, 2011

USD ($)

May 31, 2011

CAD ($)

May 31, 2011

USD ($)

Jan. 31, 2011

CAD ($)

Dec. 31, 2013

CAD ($)

Dec. 31, 2013

USD ($)

Dec. 31, 2012

CAD ($)

Dec. 31, 2011

CAD ($)

Dec. 31, 2011

USD ($)

Dec. 31, 2013

USD ($)

Dec. 31, 2012

USD ($)

Less: Current Portion of Long-Term Debt

$ 22,865,000,000

$ 18,913,000,000

973,000,000

894,000,000

Non-current portion of long-term debt

21,892,000,000

18,019,000,000

Principal repayments on long-term debt for the next five years

973,000,000

1,659,000,000

2,092,000,000

862,000,000

1,632,000,000

Repayment of long-term debt

1,286,000,000

980,000,000

$ 1,272,000,000

Amortization and other financial charges

Capitalized interest

(287,000,000)

(300,000,000)

(302,000,000)

^[1]

(21,000,000)

7,000,000

6,000,000

Interest expense (Note 15)

985,000,000

976,000,000

937,000,000

Interest payments

Interest payments on long-term debt and junior subordinated notes, net of interest capitalized on construction projects

985,000,000

966,000,000

926,000,000

Short-term debt

Total long-term debt (excluding junior subordinated notes)

Interest expense

12,000,000

16,000,000

Junior subordinated notes

Interest expense

1,216,000,000

1,190,000,000

1,154,000,000

TRANSCANADA PIPELINES LIMITED

Interest expense

65,000,000

63,000,000

$ 63,000,000

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes [Member] | U.S. dollars

19,125,000,000

15,878,000,000

$ 13,027,000,000

^[2]

$ 10,057,000,000

^[2]

$ 12,276,000,000

$ 10,126,000,000

TRANSCANADA PIPELINES LIMITED | Debentures | Canadian dollars

^[2],[3]

5.00%

5.60%

5.00%

5.60%

$ 874,000,000

TRANSCANADA PIPELINES LIMITED | Debentures | U.S. dollars

^[3]

10.90%

$ 425,000,000

$ 398,000,000

$ 400,000,000

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes

^[3]

9.90%

$ 500,000,000

TRANSCANADA PIPELINES LIMITED | 3.75% senior unsecured notes, due October 16, 2023

5.05%

$ 625,000,000

TRANSCANADA PIPELINES LIMITED | 5.0% senior unsecured notes, due October 16, 2043

3.75%

$ 625,000,000

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

5.00%

$ 500,000,000

TRANSCANADA PIPELINES LIMITED | 4.0% senior unsecured notes

0.95%

$ 350,000,000

TRANSCANADA PIPELINES LIMITED | 0.75 % senior notes, due January 15, 2016

4.00%

$ 750,000,000

TRANSCANADA PIPELINES LIMITED | 2.5 % senior unsecured notes, due August 1, 2022 | U.S. dollars

0.75%

$ 1,000,000,000

TRANSCANADA PIPELINES LIMITED | 8.625 % senior unsecured notes | U.S. dollars

2.50%

$ 200,000,000

TRANSCANADA PIPELINES LIMITED | 0.875 % senior unsecured notes, due March 2, 2015 | U.S. dollars

8.625%

$ 500,000,000

TRANSCANADA PIPELINES LIMITED | Medium-Term Notes | Canadian dollars

0.875%

$ 4,799,000,000

$ 4,549,000,000

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

^[3]

5.70%

5.90%

5.70%

5.90%

$ 450,000,000

$ 250,000,000

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

3.69%

$ 300,000,000

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

4.55%

TRANSCANADA PIPELINES LIMITED | 3.65 % medium-term notes, due November 15, 2021

4.55%

$ 500,000,000

TRANSCANADA PIPELINES LIMITED | 9.5 % medium term notes

3.65%

$ 60,000,000

TRANSCANADA PIPELINES LIMITED | 4.3 % medium term notes

9.50%

$ 300,000,000

TRANSCANADA PIPELINES LIMITED | Term loan | U.S. dollars

4.30%

Amount drawn on credit facility

$ 380,000,000

TRANSCANADA PIPELINES LIMITED | Junior subordinated notes | U.S. dollars

6.50%

NOVA GAS TRANSMISSION LTD

6.35%

NOVA GAS TRANSMISSION LTD | 8.5 % debentures | U.S. dollars

$ 1,129,000,000

$ 1,117,000,000

$ 175,000,000

NOVA GAS TRANSMISSION LTD | Debentures with retraction provisions

8.50%

NOVA GAS TRANSMISSION LTD | Debentures with retraction provisions | Maximum

Face amount

$ 225,000,000

Percentage of principal plus accrued and unpaid interest redeemable at specified repayment dates

8.00%

NOVA GAS TRANSMISSION LTD | Medium-Term Notes | Canadian dollars

$ 504,000,000

NOVA GAS TRANSMISSION LTD | Medium-Term Notes | U.S. dollars

^[3]

7.40%

$ 34,000,000

$ 32,000,000

$ 33,000,000

NOVA GAS TRANSMISSION LTD | Debentures and Notes | Canadian dollars

^[3]

7.50%

$ 378,000,000

$ 382,000,000

NOVA GAS TRANSMISSION LTD | Debentures and Notes | U.S. dollars

^[3]

11.50%

$ 213,000,000

$ 199,000,000

$ 200,000,000

TRANSCANADA PIPELINE USA LTD | Committed, syndicated, revolving, extendible credit facility | U.S. dollars

^[3]

7.90%

Trans Canada Keystone Pipe Line LP | Medium-Term Notes | U.S. dollars

$ 300,000,000

ANR PIPELINE COMPANY | Senior Unsecured Notes [Member] | U.S. dollars

Borrowing capacity

$ 500,000,000

$ 459,000,000

$ 430,000,000

$ 432,000,000

GAS TRANSMISSION NORTHWEST CORPORATION | Senior Unsecured Notes [Member] | U.S. dollars

^[3]

8.90%

$ 346,000,000

$ 323,000,000

$ 325,000,000

^[3]

5.50%

TC PIPELINES, LP

TC PIPELINES, LP | U.S. dollars | GTN LLC

$ 1,308,000,000

$ 658,000,000

TC PIPELINES, LP | U.S. dollars | Bison LLC

45.00%

TC PIPELINES, LP | Senior Unsecured Notes [Member] | U.S. dollars

45.00%

$ 372,000,000

$ 348,000,000

$ 350,000,000

TC PIPELINES, LP | 4.65 % senior unsecured notes, due 2021 | U.S. dollars

^[3]

4.70%

$ 350,000,000

TC PIPELINES, LP | Term loan | U.S. dollars

4.65%

TC PIPELINES, LP | Revolving facility | U.S. dollars

$ 300,000,000

Amount drawn on credit facility

$ 312,000,000

Draws from credit facility

$ 125,000,000

$ 437,000,000

Repayments of Lines of Credit

$ 369,000,000

TC PIPELINES, LP | Unsecured Loan | U.S. dollars

$ 404,000,000

$ 310,000,000

$ 380,000,000

$ 312,000,000

TC PIPELINES, LP | Medium-Term Loan | U.S. dollars

^[3]

1.40%

1.50%

1.40%

1.50%

$ 532,000,000

$ 500,000,000

TC PIPELINES, LP | Bridge loan facility | U.S. dollars

^[3]

1.40%

Draws from credit facility

$ 61,000,000

$ 312,000,000

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes [Member] | U.S. dollars

$ 356,000,000

$ 352,000,000

$ 335,000,000

$ 354,000,000

TUSCARORA GAS TRANSMISSION COMPANY | Senior Secured Notes | U.S. dollars

^[3]

7.80%

$ 25,000,000

$ 27,000,000

$ 24,000,000

$ 27,000,000

PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Senior Secured Notes | U.S. dollars

^[3]

4.00%

^[2]

$ 117,000,000

$ 128,000,000

$ 110,000,000

$ 129,000,000

Non-controlling interest included in the Consolidated Balance Sheet

^[2],[3]

6.10%

[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.
[2]	Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements
[3]	Interest rates are the effective interest rates except for those pertaining to Long-Term Debt issued for the Company's Canadian regulated 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.

INCOME TAXES (Details) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
INCOME TAXES (Details) - CAD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current
Canada		$ 27	$ 167	$ 212
Foreign		16	14	(2)
Total		43	181	210
Deferred
Canada		245	69	139
Foreign		323	216	226
Total		568	285	365
Total Income Tax Expense/ (Recovery)		611	466	575
Geographic Components of Income
Canada		1,224	842	1,176
Foreign		1,298	1,096	1,109
Income before Income Taxes		2,522	1,938	2,285
Reconciliation of Income Tax Expense
Income before Income Taxes		$ 2,522	$ 1,938	$ 2,285
Federal and provincial statutory tax rate (as a percent)		25.00%	25.00%	26.50%
Expected income tax expense		$ 631	$ 485	$ 605
Income tax differential related to regulated operations		(13)	41	42
Higher/(lower) effective foreign tax rates		46	1	(5)
Income from equity investments and non-controlling interests		(41)	(40)	(45)
Tax legislation change	$ (25)	(25)	0	0
Other		13	(21)	(22)
Total Income Tax Expense/ (Recovery)		611	466	$ 575
Deferred Income Tax Assets
Operating loss carryforwards		826	1,024
Deferred amounts		223	112
Other		128	239
Total		1,177	1,375
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, equipment and PPAs		4,245	3,817
Equity investments		682	578
Taxes on future revenue requirement		291	283
Unrealized foreign exchange gains on long-term debt		35	159
Other		170	96
Total		5,423	4,933
Net Deferred Income Tax Liabilities		4,246	3,558
Deferred Income Tax Assets
Other Current Assets (Note 5)		119	290
Intangible and Other Assets (Note 11)		225	168
Total		344	458
Deferred Income Tax Liabilities
Accounts Payable and Other (Note 13)		26	0
Deferred Income Tax Liabilities		4,564	4,016
Total		4,590	4,016
Net Deferred Income Tax Liabilities
Net Deferred Income Tax Liabilities		$ 4,246	$ 3,558

INCOME TAXES (Details 2) $ in Millions, $ in Millions	12 Months Ended
INCOME TAXES (Details 2) $ in Millions, $ in Millions	Dec. 31, 2013 CAD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2011 CAD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Net operating loss carryforwards
Deferred income tax liabilities on the unremitted earnings of foreign investments	$ 182	$ 144
Income tax payments, net of refunds	202	190	$ (84)
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards	$ 1,026	$ 865
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards				$ 1,432	$ 2,174

INCOME TAXES (Details 3) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
INCOME TAXES (Details 3) - CAD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of the annual changes in the total unrecognized tax benefit
Unrecognized tax benefits at beginning of year		$ 49	$ 52	$ 62
Gross increases – tax positions in prior years		3	2	9
Gross decreases – tax positions in prior years		(28)	(6)	(7)
Gross increases – tax positions in current year		2	9	11
Lapses of statute of limitations		(3)	(8)	(23)
Unrecognized tax benefits at end of year		23	49	52
Favorable tax adjustment	$ 25	25	0	0
Income tax interest and penalties
Interest expense (reversal) reflected within net tax expense		1	(2)	$ (12)
Accrued interest expense		$ 6	$ 5

JUNIOR SUBORDINATED NOTES (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2013 CAD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2012 USD ($)
Junior subordinated notes
Amount outstanding	$ 1,063		$ 994
TRANSCANADA PIPELINES LIMITED \| Junior subordinated notes \| U.S. dollars
Junior subordinated notes
Amount outstanding	$ 1,063	$ 1,000	$ 994	$ 1,000
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%
Variable rate basis after May 15, 2017	3 months LIBOR
Interest rate margin after May 15, 2017 (as a percent)	2.21%
Optional period for which payment of interest can be deferred	10 years
Redemption price as a percentage of principal amount plus accrued and unpaid interest to the date of redemption	100.00%

NON-CONTROLLING INTERESTS (Details) - CAD ($)
$ / shares in Units, $ in Millions

1 Months Ended

12 Months Ended

Jan. 27, 2014

May 03, 2011

Oct. 31, 2013

Jul. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 15, 2013

May 31, 2013

Apr. 30, 2013

May 31, 2011

Non-controlling interest

$ 1,611

$ 1,425

Non-controlling interests included in the Consolidated Statement of Income

Net income attributable to non-controlling interests

125

118

$ 129

^[1]

TC PipeLines, LP

Fees received for services provided

TC PipeLines, LP | GTN LLC

Ownership interest from TransCanada to TC Pipelines

25.00%

45.00%

TC PipeLines, LP | Bison LLC

Ownership interest from TransCanada to TC Pipelines

25.00%

45.00%

TransCanada PipeLines Limited | Series U & Y Preferred Stock

TransCanada PipeLines Limited | Series U

Non-controlling interest included in the Consolidated Balance Sheet

Preferred shares of TCPL

^[2]

$ 0

$ 195

Preferred Shares of TCPL

Number of Shares

4,000,000

Dividend rate per share (in Canadian dollars per share)

$ 2.80

Redemption price per share (in Canadian dollars per share)

$ 50.00

$ 50

Number of Shares Outstanding

4,000,000

Preferred stock dividend rate

5.60%

Accrued and unpaid dividends, in CAD per share

$ 0.5907

TransCanada PipeLines Limited | Series Y

Non-controlling interest included in the Consolidated Balance Sheet

Preferred shares of TCPL

^[2]

$ 194

Preferred Shares of TCPL

Number of Shares

4,000,000

Dividend rate per share (in Canadian dollars per share)

$ 2.80

Redemption price per share (in Canadian dollars per share)

$ 50.00

TransCanada PipeLines Limited | Series Y | Subsequent events

Preferred Shares of TCPL

Redemption price per share (in Canadian dollars per share)

$ 50

Preferred stock dividend rate

5.60%

Accrued and unpaid dividends, in CAD per share

$ 0.2455

Number of shares authorized to be redeemed

4,000,000

Portland

Fees received for services provided

$ 7

Noncontrolling Interest | TC PipeLines, LP

Non-controlling interest included in the Consolidated Balance Sheet

Non-controlling interest

^[3]

1,323

953

Non-controlling interests included in the Consolidated Statement of Income

Net income attributable to non-controlling interests

^[3]

$ 93

101

Percentage of non-controlling interests

71.10%

66.70%

61.80%

Noncontrolling Interest | TransCanada PipeLines Limited

Non-controlling interest included in the Consolidated Balance Sheet

Preferred shares of TCPL

^[2]

$ 194

389

Non-controlling interests included in the Consolidated Statement of Income

Noncontrolling Interest | Portland

Non-controlling interest included in the Consolidated Balance Sheet

Non-controlling interest

^[4]

Non-controlling interests included in the Consolidated Statement of Income

Net income attributable to non-controlling interests

^[4]

$ 12

$ 5

$ 6

Percentage of non-controlling interests

38.30%

[1]	At December 31, 2013, there were dividends declared but not yet paid of $10 million (2012 - $4 million) included in Accounts Payable and Other (Note 13) which was paid on January 30, 2014
[2]	Net of underwriting underwriting commissions and deferred income taxes.
[3]	In May 2013, the non-controlling interest in TC PipeLines, LP increased from 66.7 per cent to 71.1 per cent due to the issuance of equity to non-controlling interests in TC PipeLines, LP. In July 2013, TransCanada sold 45 per cent interests in GTN LLC and Bison LLC to TC PipeLines, LP (See Note 25). The non-controlling interest in TC PipeLines, LP from January 2010 to May 2011 was 61.8 per cent and 66.7 per cent from May 2011 to May 2013.
[4]	The non-controlling interest in Portland as at December 31, 2013 represented the 38.3 per cent interest not owned by TransCanada (2012 and 2011 - 38.3 per cent).

COMMON SHARES (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in common shares during the period
Outstanding at the beginning of the period (in shares)	705,000
Outstanding at the beginning of the period	$ 12,069
Dividend reinvestment and share purchase plan (in shares)			5,400
Dividend reinvestment and share purchase plan			$ 202
Exercise of options (in shares)	1,980	1,600	2,260
Outstanding at the end of the period (in shares)	707,000	705,000
Outstanding at the end of the period	$ 12,149	$ 12,069
Net Income per Share
Weighted average number of common shares outstanding used to calculate basic earnings per share	707,000	705,000	702,000
Weighted average number of common shares outstanding used to calculate diluted earnings per share	708,000	706,000	703,000
Common Shares
Changes in common shares during the period
Outstanding at the beginning of the period (in shares)	705,461	703,861	696,230
Outstanding at the beginning of the period	$ 12,069	$ 12,011	$ 11,745
Dividend reinvestment and share purchase plan (in shares)			5,371
Dividend reinvestment and share purchase plan	$ 0	$ 0	$ 202
Exercise of options (in shares)	1,980	1,600	2,260
Exercise of options	$ 80	$ 58	$ 64
Outstanding at the end of the period (in shares)	707,441	705,461	703,861
Outstanding at the end of the period	$ 12,149	$ 12,069	$ 12,011
Net Income per Share
Weighted average number of common shares outstanding used to calculate basic earnings per share	706,700	704,600	701,600
Weighted average number of common shares outstanding used to calculate diluted earnings per share	707,700	705,700	702,800

COMMON SHARES (Details 2) - $ / shares shares in Thousands	12 Months Ended
COMMON SHARES (Details 2) - $ / shares shares in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Number of Options
Outstanding at the beginning of the period (in shares)	7,434	7,100	8,406
Granted (in shares)	1,939	1,978	970
Exercised (in shares)	(1,980)	(1,600)	(2,260)
Forfeited (in shares)		(44)	(16)
Outstanding at the end of the period (in shares)	7,393	7,434	7,100
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share)	$ 37.69	$ 35.44	$ 32.57
Granted (in Canadian dollars per share)	47.09	42.03	38.02
Exercised (in Canadian dollars per share)	36.12	33.13	25.86
Forfeited (in Canadian dollars per share)		36.55	35.83
Outstanding at the end of the period (in Canadian dollars per share)	$ 40.57	$ 37.69	$ 35.44
Options Exercisable
Options Exercisable (in shares)	3,954	4,588	5,165	6,458

COMMON SHARES (Details 3) - CAD ($)
$ / shares in Units, shares in Thousands, $ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Weighted Average Exercise Price (in Canadian dollars per share)

7,393

$ 40.57

4 years 3 months 18 days

Weighted Average Exercise Price (in Canadian dollars per share)

3,954

$ 37.12

Common shares reserved for future issuance under stock option plan

3 years 1 month 6 days

Additional disclosure

10,500

Weighted average fair value of options granted (in Canadian dollars per share)

$ 5.74

$ 5.08

$ 2.94

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

6 years

5 years 10 months 24 days

4 years

Interest rate (as a percent)

1.70%

1.60%

2.10%

Volatility (as a percent)

^[1]

18.00%

19.00%

14.00%

Dividend yield (as a percent)

3.70%

4.20%

4.30%

Forfeiture rate (as a percent)

15.00%

Amount expensed for stock awards, with a corresponding increase in additional paid-in capital

$ 6

$ 5

Total intrinsic value of options exercised

Fair value of shares vested

$ 65

$ 49

$ 42

Number of shares vested

1,000

Aggregate intrinsic value of total options exercisable

$ 45

Total intrinsic value of options outstanding

$ 59

Range of exercise price per share $30.10 to $36.26

Stock options outstanding and exercisable by exercise price range

Exercise price, low end of range (in Canadian dollars per share)

$ 30.10

Exercise price, high end of range (in Canadian dollars per share)

$ 36.26

Weighted Average Exercise Price (in Canadian dollars per share)

1,725

$ 33.72

2 years 6 months

Weighted Average Exercise Price (in Canadian dollars per share)

1,725

$ 33.72

Range of exercise price per share $36.90 to $41.65

2 years 6 months

Stock options outstanding and exercisable by exercise price range

Exercise price, low end of range (in Canadian dollars per share)

$ 36.90

Exercise price, high end of range (in Canadian dollars per share)

$ 41.65

Weighted Average Exercise Price (in Canadian dollars per share)

1,781

$ 38.52

3 years 8 months 12 days

Weighted Average Exercise Price (in Canadian dollars per share)

1,516

$ 38.60

Range of exercise price per share $41.95 to $45.29

3 years 6 months

Stock options outstanding and exercisable by exercise price range

Exercise price, low end of range (in Canadian dollars per share)

$ 41.95

Exercise price, high end of range (in Canadian dollars per share)

$ 45.29

Weighted Average Exercise Price (in Canadian dollars per share)

1,948

$ 42.03

5 years 2 months 12 days

Weighted Average Exercise Price (in Canadian dollars per share)

690

$ 42.03

Exercise price per share $47.09

5 years 2 months 12 days

Stock options outstanding and exercisable by exercise price range

Exercise price, low end of range (in Canadian dollars per share)

$ 47.09

Weighted Average Exercise Price (in Canadian dollars per share)

1,939

$ 47.09

6 years 1 month 6 days

Weighted Average Exercise Price (in Canadian dollars per share)

$ 47.09

6 years 1 month 6 days

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

COMMON SHARES (Details 4) $ / shares in Units, $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
	Apr. 28, 2011	Feb. 28, 2011	Dec. 31, 2010	Dec. 31, 2013 CAD ($) right $ / shares shares	Dec. 31, 2012 CAD ($) $ / shares	Dec. 31, 2011 CAD ($) $ / shares shares
Shareholder Rights Plan
Number of rights entitled to each common share \| right				1
Number of common shares entitled to be purchased under each right \| shares				2
Cash Dividends
Cash dividends paid \| $				$ 1,285	$ 1,226	$ 961
Cash dividends paid (in Canadian dollars per share) \| $ / shares				$ 1.82	$ 1.74	$ 1.66
Dividend Reinvestment Plan
Period before dividend payment during which common shares from Treasury were issued at a discount in lieu of cash dividends	5 days
Discount on issuance of common shares from the average market price (as a percent)		2.00%	3.00%
Common stock issued in accordance with the DRP (in shares) \| shares						5,400,000
Value of common shares issued in accordance with the DRP in lieu of making cash dividend payments \| $						$ 202

PREFERRED SHARES (Details) - CAD ($)

1 Months Ended

12 Months Ended

Mar. 31, 2013

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

^[1]

$ 1,813,000,000

$ 1,224,000,000

Dividends, Preferred Stock, Paid-in-kind

71,000,000

^[2]

55,000,000

$ 55,000,000

$ 10,000,000

$ 4,000,000

Series 1

22,000,000

Dividend rate per share (in Canadian dollars per share)

22,000,000

$ 1.15

Redemption price per share (in Canadian dollars per share)

$ 25.00

Initial period of fixed cumulative quarterly dividend payment

^[1]

$ 539,000,000

5 years

Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum

5 years

5 years

Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum

1.92%

Period of subsequent interval for redemption of preferred stock

5 years

Period of subsequent interval for conversion of preferred stock

5 years

Annual Dividend Rate per Share (in Canadian dollars per share)

$ 25,000,000

^[2]

$ 25,000,000

$ 1.15

Series 2

Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum

90 days

Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum

1.92%

Series 3

14,000,000

Dividend rate per share (in Canadian dollars per share)

14,000,000

$ 1.00

Redemption price per share (in Canadian dollars per share)

$ 25.00

Initial period of fixed cumulative quarterly dividend payment

^[1]

$ 343,000,000

5 years

Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum

5 years

5 years

Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum

1.28%

Period of subsequent interval for redemption of preferred stock

5 years

Period of subsequent interval for conversion of preferred stock

5 years

Annual Dividend Rate per Share (in Canadian dollars per share)

$ 14,000,000

^[2]

$ 14,000,000

$ 1.00

Series 4

Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum

90 days

Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum

1.28%

Series 5

14,000,000

Dividend rate per share (in Canadian dollars per share)

14,000,000

$ 1.10

Redemption price per share (in Canadian dollars per share)

$ 25.00

Initial period of fixed cumulative quarterly dividend payment

^[1]

$ 342,000,000

5 years 6 months

Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum

5 years

5 years

Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum

1.54%

Period of subsequent interval for redemption of preferred stock

5 years

Period of subsequent interval for conversion of preferred stock

5 years

Annual Dividend Rate per Share (in Canadian dollars per share)

$ 16,000,000

^[2]

$ 16,000,000

$ 1.10

Series 6

Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum

90 days

Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum

1.54%

Series 7

24,000,000

Dividend rate per share (in Canadian dollars per share)

24,000,000

^[3]

$ 1.00

Redemption price per share (in Canadian dollars per share)

$ 25

Initial period of fixed cumulative quarterly dividend payment

^[1]

$ 589,000,000

6 years

Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum

5 years

5 years

Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum

2.38%

Proceeds from (Repurchase of) Redeemable Preferred Stock

$ 600,000,000.00

Annual Dividend Rate per Share (in Canadian dollars per share)

^[2],[3]

$ 16,000,000

^[3]

$ 1.00

Cash dividends paid (in Canadian dollars per share)

$ 0.65

Series 8

Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum

90 days

Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum

2.38%

[1]	Net of underwriting commissions and deferred income taxes.
[2]	At December 31, 2013, there were dividends declared but not yet paid of $10 million (2012 - $4 million) included in Accounts Payable and Other (Note 13) which was paid on January 30, 2014
[3]	For the year ended December 31, 2013, the cash dividend rate was prorated at $0.65 per share.

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Before tax amount
Foreign currency translation gains and losses on net investments in foreign operations	$ 269	$ (97)	$ 108
Change in fair value of net investment hedges	(323)	59	(101)
Change in fair value of cash flow hedges	121	61	(318)
Reclassification to Net Income of gains and losses on cash flow hedges	(60)	(219)	(224)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	96	(104)	(119)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	34	22	13
Other comprehensive income on Equity Investments	313	(93)	(94)
Other comprehensive income/(loss)	570	67	(287)
Income tax recovery/(expense)
Foreign currency translation gains and losses on net investments in foreign operations	(114)	32	(29)
Change in fair value of net investment hedges	(84)	15	(28)
Change in fair value of cash flow hedges	50	13	(106)
Reclassification to Net Income of gains and losses on cash flow hedges	(19)	(81)	(77)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	29	(31)	(30)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	11	0	3
Other comprehensive income on Equity Investments	79	(23)	(3)
Other comprehensive income/(loss)	(10)	87	(116)
Net of tax amount
Foreign currency translation gains and losses on net investments in foreign operations	383	(129)	137
Change in fair value of net investment hedges	(239)	44	(73)
Change in fair value of cash flow hedges	71	48	(212)
Reclassification to Net Income of gains and losses on cash flow hedges	(41)	(138)	(147)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	67	(73)	(89)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	23	22	10
Other comprehensive income on Equity Investments	234	(70)	(91)
Other Comprehensive Income/(Loss) (Note 21)	$ 580	$ (20)	$ (171)

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Details 2) - CAD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Other comprehensive income/(loss) before reclassifications

^[1]

$ (1,448)

$ (1,449)

$ (1,243)

^[1],[2]

435

(156)

(345)

Amounts reclassified from Accumulated Other Comprehensive Loss

^[1]

^[3]

157

139

Net current period other comprehensive income/(loss)

^[1]

514

(206)

Other comprehensive income/(loss) before reclassifications attributable to noncontrolling interest

^[1]

(934)

(1,448)

(1,449)

^[1],[2]

(21)

Cash flow hedge losses expected to be reclassified within the next twelve months, before tax

Cash flow hedge losses expected to be reclassified within the next twelve months, net of tax

Currency translation adjustments

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Other comprehensive income/(loss) before reclassifications

(707)

(643)

(683)

^[2]

(64)

Amounts reclassified from Accumulated Other Comprehensive Loss

^[3]

Net current period other comprehensive income/(loss)

(64)

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

(629)

(707)

(643)

Cash flow hedges

Other comprehensive income/(loss) before reclassifications

(116)

(302)

(226)

^[2]

(213)

Amounts reclassified from Accumulated Other Comprehensive Loss

^[3]

138

137

Net current period other comprehensive income/(loss)

112

186

(76)

Pension and OPEB plan adjustments

(4)

(116)

(302)

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Other comprehensive income/(loss) before reclassifications

(287)

(236)

(157)

^[2]

(73)

(89)

Amounts reclassified from Accumulated Other Comprehensive Loss

^[3]

Net current period other comprehensive income/(loss)

(51)

(79)

(197)

(287)

(236)

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Other comprehensive income/(loss) before reclassifications

(338)

(268)

(177)

^[2]

219

(67)

(83)

Amounts reclassified from Accumulated Other Comprehensive Loss

^[3]

(3)

(8)

Net current period other comprehensive income/(loss)

234

(70)

(91)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

$ (104)

$ (338)

$ (268)

[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 $66 million in 2013 (2012 - $21 million losses; 2011 - $35 million gains).
[3]	Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $81 million ($50 million, net of tax) at December 31, 2013. 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.

OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Details 3) - CAD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Revenue (Energy)

$ 3,176

$ 2,704

$ 2,768

Interest Expense

(985)

(976)

(937)

597

257

415

2,522

1,938

2,285

(611)

(466)

(575)

Cash flow hedges | Amounts reclassified from accumulated other comprehensive loss

1,786

1,354

$ 1,581

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(60)

(219)

^[1]

Cash flow hedges | Power and Natural Gas | Amounts reclassified from accumulated other comprehensive loss

^[1]

(41)

(138)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Revenue (Energy)

^[1]

(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

^[1]

(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 net loss

^[1],[2]

(34)

(22)

^[1]

Equity Investments | Amounts reclassified from accumulated other comprehensive loss

^[1]

(23)

(22)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(20)

^[1]

(2)