Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2017shares | |
Document and Entity Information | |
Entity Registrant Name | TRANSCANADA PIPELINES LTD |
Entity Central Index Key | 99,070 |
Document Type | 40-F |
Document Period End Date | Dec. 31, 2017 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Common Stock, Shares Outstanding | 871,760,696 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | FY |
Consolidated statement of incom
Consolidated statement of income - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues | |||
Liquids Pipelines | CAD 2,009 | CAD 1,755 | CAD 1,879 |
Energy | 3,593 | 4,206 | 4,091 |
Revenues | 13,449 | 12,547 | 11,353 |
Income from Equity Investments (Note 9) | 773 | 514 | 440 |
Operating and Other Expenses | |||
Plant operating costs and other | 3,906 | 3,861 | 3,303 |
Commodity purchases resold | 2,382 | 2,172 | 2,237 |
Property taxes | 569 | 555 | 517 |
Depreciation and amortization | 2,055 | 1,939 | 1,765 |
Goodwill and other asset impairment charges (Notes 8, 11 and 12) | 1,257 | 1,388 | 3,745 |
Total Operating and Other Expenses | 10,169 | 9,915 | 11,567 |
Gain/(Loss) on Assets Held for Sale/Sold (Notes 6 and 25) | 631 | (833) | (125) |
Financial Charges | |||
Interest expense (Note 17) | 2,137 | 1,927 | 1,398 |
Allowance for funds used during construction | (507) | (419) | (295) |
Interest income and other | (183) | (117) | 103 |
Total Financial Charges | 1,447 | 1,391 | 1,206 |
Income/(Loss) before Income Taxes | 3,237 | 922 | (1,105) |
Income Tax (Recovery)/Expense (Note 16) | |||
Current | 149 | 157 | 137 |
Deferred | 548 | 192 | (102) |
Deferred – U.S. Tax Reform | (804) | 0 | 0 |
Income Tax (Recovery)/Expense | (107) | 349 | 35 |
Net Income/(Loss) | 3,344 | 573 | (1,140) |
Net income attributable to non-controlling interests (Note 19) | 238 | 252 | 6 |
Net Income/(Loss) Attributable to Controlling Interests and to Common Shares | 3,106 | 321 | (1,146) |
Canadian Natural Gas Pipelines | |||
Revenues | |||
Revenues | 3,693 | 3,682 | 3,680 |
U.S. Natural Gas Pipelines | |||
Revenues | |||
Revenues | 3,584 | 2,526 | 1,444 |
Mexico Natural Gas Pipelines | |||
Revenues | |||
Revenues | CAD 570 | CAD 378 | CAD 259 |
Consolidated statement of compr
Consolidated statement of comprehensive income - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
Net Income/(Loss) | CAD 3,344 | CAD 573 | CAD (1,140) |
Other Comprehensive (Loss)/Income, Net of Income Taxes | |||
Foreign currency translation losses and gains on net investment in foreign operations | (749) | 3 | 813 |
Reclassification of foreign currency translation gains on net investment on disposal of foreign operations | (77) | 0 | 0 |
Change in fair value of net investment hedges | 0 | (10) | (372) |
Change in fair value of cash flow hedges | 3 | 30 | (57) |
Reclassification to net income of gains and losses on cash flow hedges | (2) | 42 | 88 |
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans | (11) | (26) | 51 |
Reclassification of actuarial loss and prior service costs on pension and other post-retirement benefit plans | 16 | 16 | 32 |
Other comprehensive (loss)/income on equity investments | (106) | (87) | 47 |
Other comprehensive (loss)/income (Note 21) | (926) | (32) | 602 |
Comprehensive Income/(Loss) | 2,418 | 541 | (538) |
Comprehensive income attributable to non-controlling interests | 83 | 241 | 312 |
Comprehensive Income/(Loss) Attributable to Controlling Interests and to Common Shares | CAD 2,335 | CAD 300 | CAD (850) |
Consolidated statement of cash
Consolidated statement of cash flows - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash Generated from Operations | |||
Net income/(loss) | CAD 3,344 | CAD 573 | CAD (1,140) |
Depreciation and amortization | 2,055 | 1,939 | 1,765 |
Goodwill and other asset impairment charges (Notes 8, 11 and 12) | 1,257 | 1,388 | 3,745 |
Deferred income taxes (Note 16) | 548 | 192 | (102) |
Deferred income taxes – U.S. Tax Reform (Note 16) | (804) | 0 | 0 |
Income from equity investments (Note 9) | (773) | (514) | (440) |
Distributions received from operating activities of equity investments (Note 9) | 970 | 844 | 793 |
Employee post-retirement benefits funding, net of expense (Note 22) | (64) | (3) | 44 |
(Gain)/loss on assets held for sale/sold (Notes 6 and 26) | (631) | 833 | 125 |
Equity allowance for funds used during construction | (362) | (253) | (165) |
Unrealized (gains)/losses on financial instruments | (149) | (149) | 58 |
Other | 43 | 55 | 47 |
(Increase)/decrease in operating working capital (Note 24) | (272) | 251 | (307) |
Net cash provided by operations | 5,162 | 5,156 | 4,423 |
Investing Activities | |||
Capital expenditures (Note 4) | (7,383) | (5,007) | (3,918) |
Capital projects in development (Note 4) | (146) | (295) | (511) |
Contributions to equity investments (Notes 4 and 9) | (1,681) | (765) | (493) |
Acquisitions, net of cash acquired | 0 | (13,608) | (236) |
Proceeds from sale of assets, net of transaction costs | 5,317 | 6 | 0 |
Other distributions from equity investments (Note 9) | 362 | 727 | 9 |
Deferred amounts and other | (168) | 159 | 272 |
Net cash used in investing activities | (3,699) | (18,783) | (4,877) |
Financing Activities | |||
Notes payable issued/(repaid), net | 1,038 | (329) | (1,382) |
Long-term debt issued, net of issue costs | 3,643 | 12,333 | 5,045 |
Long-term debt repaid | (7,085) | (7,153) | (2,105) |
Junior subordinated notes issued, net of issue costs | 3,468 | 1,549 | 917 |
Advances from/(to) affiliate, net | 193 | 4,523 | (189) |
Dividends on common shares | (2,121) | (1,612) | (1,446) |
Distributions paid to non-controlling interests | (283) | (279) | (224) |
Common shares issued | 780 | 4,661 | 0 |
Partnership units of TC PipeLines, LP issued, net of issue costs | 225 | 215 | 55 |
Common units of Columbia Pipeline Partners LP acquired | (1,205) | 0 | 0 |
Net cash (used in)/provided by financing activities | (1,347) | 13,908 | 671 |
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents | (39) | (127) | 112 |
Increase in Cash and Cash Equivalents | 77 | 154 | 329 |
Cash and Cash Equivalents, Beginning of year | 967 | 813 | 484 |
Cash and Cash Equivalents, End of year | CAD 1,044 | CAD 967 | CAD 813 |
Consolidated balance sheet
Consolidated balance sheet - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and cash equivalents | CAD 1,044 | CAD 967 |
Accounts receivable | 2,537 | 2,093 |
Inventories | 378 | 368 |
Assets held for sale | 0 | 3,717 |
Other (Note 7) | 691 | 908 |
Total Current Assets | 4,650 | 8,053 |
Plant, Property and Equipment (Note 8) | 57,277 | 54,475 |
Equity Investments (Note 9) | 6,366 | 6,544 |
Regulatory Assets (Note 10) | 1,376 | 1,322 |
Goodwill (Note 11) | 13,084 | 13,958 |
Loan Receivable from Affiliate (Note 9) | 919 | 0 |
Intangible and Other Assets (Note 12) | 1,423 | 2,947 |
Restricted Investments | 915 | 642 |
Total Assets | 86,010 | 87,941 |
Current Liabilities | ||
Notes payable (Note 13) | 1,763 | 774 |
Accounts payable and other (Note 14) | 4,071 | 3,876 |
Dividends payable | 552 | 491 |
Due to affiliate (Note 28) | 2,551 | 2,358 |
Accrued interest | 605 | 595 |
Liabilities related to assets held for sale | 0 | 86 |
Current portion of long-term debt (Note 17) | 2,866 | 1,838 |
Total Current Liabilities | 12,408 | 10,018 |
Regulatory Liabilities (Note 10) | 4,321 | 2,121 |
Other Long-Term Liabilities (Note 15) | 727 | 1,183 |
Deferred Income Tax Liabilities (Note 16) | 5,403 | 7,662 |
Long-Term Debt (Note 17) | 31,875 | 38,312 |
Junior Subordinated Notes (Note 18) | 7,007 | 3,931 |
Total Liabilities | 61,741 | 63,227 |
Common Units Subject to Rescission or Redemption (Note 19) | 0 | 1,179 |
EQUITY | ||
Common shares, no par value (Note 20) | 21,761 | 20,981 |
Additional paid-in capital | 0 | 211 |
Retained earnings | 2,387 | 1,577 |
Accumulated other comprehensive loss (Note 21) | (1,731) | (960) |
Controlling Interests | 22,417 | 21,809 |
Non-controlling interests (Note 19) | 1,852 | 1,726 |
Total Equity | 24,269 | 23,535 |
Total Liabilities and Equity | CAD 86,010 | CAD 87,941 |
Consolidated balance sheet (Par
Consolidated balance sheet (Parenthetical) - shares shares in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Common shares issued (in shares) | 872 | 859 |
Common shares outstanding (in shares) | 872 | 859 |
Consolidated statement of equit
Consolidated statement of equity - CAD CAD in Millions | Total | Equity Attributable to Controlling Interests | Common Shares | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Loss | Equity Attributable to Non-Controlling Interests |
Balance at beginning of year at Dec. 31, 2014 | CAD 16,320 | CAD 404 | CAD 5,606 | CAD (1,235) | CAD 1,583 | ||
Increase (decrease) in equity | |||||||
Proceeds from shares issued | 0 | ||||||
Issuance of stock options | 13 | ||||||
Dilution from TC PipeLines, LP units issued | 6 | 55 | |||||
Asset drop downs to TC PipeLines, LP | (213) | ||||||
Columbia Pipeline Partners LP acquisition | (11) | ||||||
Net income/(loss) attributable to controlling interests | CAD (1,146) | (1,146) | |||||
Common share dividends | (1,471) | ||||||
Other comprehensive (loss)/income attributable to controlling interests (Note 21) | 602 | 296 | |||||
Net income attributable to non-controlling interests | (6) | 6 | |||||
Other comprehensive (loss)/income attributable to non-controlling interests | 306 | ||||||
Issuance of TC PipeLines, LP units | |||||||
Proceeds, net of issue costs | 6 | 55 | |||||
Decrease in TCPL's ownership of TC PipeLines, LP | (11) | ||||||
Distributions declared to non-controlling interests | (222) | ||||||
Balance at end of year at Dec. 31, 2015 | 20,297 | CAD 18,580 | 16,320 | 210 | 2,989 | (939) | 1,717 |
Increase (decrease) in equity | |||||||
Proceeds from shares issued | 4,661 | ||||||
Issuance of stock options | 15 | ||||||
Dilution from TC PipeLines, LP units issued | 24 | 215 | |||||
Asset drop downs to TC PipeLines, LP | (38) | ||||||
Columbia Pipeline Partners LP acquisition | (40) | ||||||
Net income/(loss) attributable to controlling interests | 321 | 321 | |||||
Common share dividends | (1,733) | ||||||
Other comprehensive (loss)/income attributable to controlling interests (Note 21) | (32) | (21) | |||||
Acquisition of non-controlling interests in Columbia Pipeline Partners LP | 1,051 | ||||||
Net income attributable to non-controlling interests | (252) | 252 | |||||
Other comprehensive (loss)/income attributable to non-controlling interests | (11) | ||||||
Issuance of TC PipeLines, LP units | |||||||
Proceeds, net of issue costs | 24 | 215 | |||||
Decrease in TCPL's ownership of TC PipeLines, LP | (40) | ||||||
Reclassification from/(to) common units subject to rescission or redemption (Note 19) | (1,179) | ||||||
Distributions declared to non-controlling interests | (279) | ||||||
Balance at end of year at Dec. 31, 2016 | 23,535 | 21,809 | 20,981 | 211 | 1,577 | (960) | 1,726 |
Increase (decrease) in equity | |||||||
Proceeds from shares issued | 780 | ||||||
Issuance of stock options | 12 | ||||||
Dilution from TC PipeLines, LP units issued | 26 | 225 | |||||
Asset drop downs to TC PipeLines, LP | (202) | ||||||
Columbia Pipeline Partners LP acquisition | (171) | (41) | |||||
Reclassification of additional paid-in capital deficit to retained earnings | 124 | ||||||
Net income/(loss) attributable to controlling interests | 3,106 | 3,106 | |||||
Common share dividends | (2,184) | ||||||
Reclassification of additional paid-in capital deficit to retained earnings | (124) | ||||||
Other comprehensive (loss)/income attributable to controlling interests (Note 21) | (926) | (771) | |||||
Net income attributable to non-controlling interests | (238) | 238 | |||||
Other comprehensive (loss)/income attributable to non-controlling interests | (155) | ||||||
Issuance of TC PipeLines, LP units | |||||||
Proceeds, net of issue costs | 26 | 225 | |||||
Decrease in TCPL's ownership of TC PipeLines, LP | (171) | (41) | |||||
Reclassification from/(to) common units subject to rescission or redemption (Note 19) | 106 | ||||||
Distributions declared to non-controlling interests | (280) | ||||||
Impact of Columbia Pipeline Partners LP acquisition | 33 | ||||||
Balance at end of year at Dec. 31, 2017 | CAD 24,269 | CAD 22,417 | CAD 21,761 | CAD 0 | 2,387 | CAD (1,731) | CAD 1,852 |
Increase (decrease) in equity | |||||||
Adjustment related to employee share-based payments (Note 3) | CAD 12 |
DESCRIPTION OF TCPL'S BUSINESS
DESCRIPTION OF TCPL'S BUSINESS | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
DESCRIPTION OF TCPL'S BUSINESS | DESCRIPTION OF TCPL'S BUSINESS TransCanada PipeLines Limited (TCPL or the Company) is a leading North American energy infrastructure company which operates in five business segments, Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy, each of which offers different products and services. The Company also has a Corporate segment which is non-operational, consisting of corporate and administrative functions. The Company is a wholly-owned subsidiary of TransCanada Corporation (TransCanada). Canadian Natural Gas Pipelines The Canadian Natural Gas Pipelines segment consists of the Company's investments in 40,429 km ( 25,121 miles ) of regulated natural gas pipelines. U.S. Natural Gas Pipelines The U.S. Natural Gas Pipelines segment consists of the Company's investments in 49,779 km ( 30,931 miles ) of regulated natural gas pipelines, 535 Bcf of regulated natural gas storage facilities, midstream and other assets. Mexico Natural Gas Pipelines The Mexico Natural Gas Pipelines segment consists of the Company's investments in 1,680 km ( 1,044 miles ) of regulated natural gas pipelines. Liquids Pipelines The Liquids Pipelines segment consists of the Company's investments in 4,874 km ( 3,030 miles ) of crude oil pipeline systems which connect Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas. Energy The Energy segment primarily consists of the Company's investments in 11 power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These include assets in Alberta, Ontario, Québec, New Brunswick and Arizona. |
ACCOUNTING POLICIES
ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
ACCOUNTING POLICIES | ACCOUNTING POLICIES The Company's consolidated financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles (GAAP). Amounts are stated in Canadian dollars unless otherwise indicated. Basis of Presentation These consolidated financial statements include the accounts of TCPL and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. TCPL uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TCPL records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation. Use of Estimates and Judgments In preparing these consolidated financial statements, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Significant estimates and judgments used in the preparation of the consolidated financial statements include, but are not limited to: • fair value of assets and liabilities acquired in a business combination (Note 5) • fair value and depreciation rates of plant, property and equipment (Note 8) • carrying value of regulatory assets and liabilities (Note 10) • fair value of goodwill (Note 11) • fair value of intangible assets (Note 12) • carrying value of asset retirement obligations (Note 15) • provisions for income taxes, including U.S. Tax Reform (Note 16) • assumptions used to measure retirement and other post-retirement obligations (Note 22) • fair value of financial instruments (Note 23) and • provision for commitments, contingencies, guarantees (Note 26) and restructuring costs (Note 27). Actual results could differ from these estimates. Regulation Certain Canadian, U.S. and Mexico natural gas pipeline and storage assets are regulated with respect to construction, operations and the determination of tolls. In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB) or the Alberta Energy Regulator (AER). In the U.S., regulated natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TCPL's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TCPL's businesses that apply RRA currently include Canadian, U.S. and Mexico natural gas pipelines, and regulated U.S. natural gas storage. RRA is not applicable to liquids pipelines as the regulators' decisions regarding operations and tolls on those systems generally do not have an impact on timing of recognition of revenues and expenses. Revenue Recognition Natural Gas Pipelines and Liquids Pipelines Capacity Arrangements and Transportation Revenues from the Company's natural gas and liquids pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made. Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline tolls are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines generally are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines, at times, are subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues on firm contracted capacity are recognized ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenues are recorded when the NEB decision is received. The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and recognized ratably over the contract period. Other volumes shipped on these pipelines are subject to CRE-approved tariffs. The Company does not take ownership of the natural gas that it transports for its customers. Regulated Natural Gas Storage Revenues from the Company's regulated natural gas storage services are recognized either ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, or when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the natural gas that it stores for its customers. Midstream and Other Revenues from the Company's midstream natural gas services, including gathering, treating, conditioning, processing, compression and liquids handling services, are generated from contractual arrangements and are recognized ratably over the contract period regardless of the amount of natural gas that is subject to these services. The Company also owns mineral rights associated with certain storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest. Royalties from mineral interests are recognized when commodities are produced. Energy Power Generation Revenues from the Company's Energy business are primarily derived from the sale of electricity, which is recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative instruments and hedging activities policy in this note. Non-Regulated Natural Gas Storage Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded net of the cost of the proprietary natural gas in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues. Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. Inventories Inventories primarily consist of natural gas inventory in storage, crude oil in transit, materials and supplies including spare parts and fuel. Inventories are carried at the lower of cost and net realizable value. Assets Held For Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next twelve months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, net of selling costs, and any losses are recognized in net income. Depreciation expense is no longer recorded once an asset is classified as held for sale. Plant, Property and Equipment Natural Gas Pipelines Plant, property and equipment for natural gas pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to six per cent, and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in plant, property and equipment with a corresponding credit recognized in Allowance for funds used during construction in the Consolidated statement of income. The equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines. Regulated natural gas storage base gas, which is valued at cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver natural gas held in storage. Base gas is not depreciated. When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove a plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Midstream and Other Plant, property and equipment for midstream assets is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Gathering and processing facilities are depreciated at annual rates ranging from 1.7 per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. The Company participates as a working interest partner in the development of certain Marcellus and Utica acreage. The working interest allows the Company to invest in drilling activities in addition to receiving a royalty interest in well production. The Company uses the successful efforts method of accounting for natural gas and crude oil resulting from its portion of drilling activities. Capitalized well costs are depleted based on the units of production method. Liquids Pipelines Plant, property and equipment for liquids pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. Energy Plant, property and equipment for Energy assets are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. Non-regulated natural gas storage base gas, which is valued at original cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver gas held in storage. Base gas is not depreciated. Corporate Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful life at average annual rates ranging from three per cent to 20 per cent. Capitalized Project Costs The Company capitalizes project costs once advancement of the project to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest costs for non-regulated projects in development and AFUDC for regulated projects in development. Capital projects in development are included in Intangible and other assets on the Consolidated balance sheet. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to Plant, property and equipment under construction. When the asset is ready for its intended use and available for operations, capitalized project costs are depreciated in accordance with the Company's plant, property and equipment depreciation policies. Impairment of Long-Lived Assets The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows or the estimated selling price is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset. Acquisitions and Goodwill The Company accounts for business combinations using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair values at the date of acquisition. The excess of the fair value of the consideration transferred over the estimated fair value of the net assets acquired is classified as goodwill. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that it might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company can initially assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the first step of a two- step impairment test is performed by comparing the fair value of the reporting unit to its carrying value, which includes goodwill. If the fair value of the reporting unit is less than its carrying value, an impairment is indicated and the second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference. The Company can elect to move directly to the first step of the two-step impairment test for any of its reporting units when performing its annual impairment test. Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at cost. Power Purchase Arrangements A power purchase arrangement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. TCPL has PPAs for the sale of power that are accounted for as operating leases where TCPL is the lessor. During 2016, the Company terminated its Alberta PPAs under which it purchased power and recorded an impairment charge. Prior to their termination, substantially all of these PPAs were also accounted for as operating leases, where TCPL was the lessee, and initial payments to acquire these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts. A portion of these PPAs were subleased to third parties under terms and conditions similar to the PPAs, and were also accounted for as operating leases with the margin earned from the subleases recorded in Revenues. Refer to Note 12, Intangible and other assets, for further information. Restricted Investments The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are classified as available for sale and are recorded at fair value on the Consolidated balance sheet. As a result of the NEB’s Land Matters Consultation Initiative (LMCI), TCPL is required to collect funds to cover estimated future pipeline abandonment costs for all NEB regulated Canadian pipelines. Funds collected are placed in trusts that hold and invest the funds and are accounted for as restricted investments. LMCI restricted investments may only be used to fund the abandonment of the NEB regulated pipeline facilities; therefore, a corresponding regulatory liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. Income Taxes The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net income in the period during which they occur, except for changes in balances related to regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the regulator. D eferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet. Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Operating and other expenses. The Company has recorded AROs related to its non-regulated natural gas storage operations, mineral rights and power generation facilities. The scope and timing of asset retirements related to most of the Company's natural gas pipelines and liquids pipelines is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities and certain facilities expected to be retired as part of an ongoing modernization program that will improve system integrity and enhance service reliability and flexibility on its Columbia Gas pipeline. Environmental Liabilities The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. These estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. These estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability. Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and expensed when they are utilized. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TCPL are not attributed a value for accounting purposes. When required, TCPL accrues emission liabilities on the Consolidated balance sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues. Stock Options and Other Compensation Programs TransCanada's Stock Option Plan permits options for the purchase of TransCanada common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period with an offset to Additional paid-in capital. TCPL records the compensation expense associated with these stock options. The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets. Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service, and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five -year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service life of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income/(loss) (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated other comprehensive income/(loss) (AOCI) and into net income over the average remaining service life of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees. Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or reporting subsidiary operates. This is referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in net income except for exchange gains and losses of the foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB. Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI until the operations are sold, at which time the gains and losses are reclassified to net income. Asset and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt and certain derivative hedging instruments have been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar denominated debt are also reflected in OCI. Derivative Instruments and Hedging Activities All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions. The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment. This includes fair value and cash flow hedges and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in net income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. In hedging the foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in net income. The amounts recognized previously in AOCI are reclassified to net income in the event the Company reduces its net investment in a foreign operation. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as Regulatory assets or Regulatory liabilities and are refunded to or collected from the ratepayers, in subsequent years when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in net income. Long-Term Debt Transaction Costs and Issuance Costs The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the related debt liability and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms. Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of partially owned entity or by partially owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments, Plant, property and equipment, or a charge to net income, and a corresponding liability is recorded in Other long-term liabilities. The |
ACCOUNTING CHANGES
ACCOUNTING CHANGES | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Changes and Error Corrections [Abstract] | |
ACCOUNTING CHANGES | ACCOUNTING CHANGES Changes in Accounting Policies for 2017 Inventory In July 2015, the Financial Accounting Standards Board (FASB) issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this guidance at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Company's Consolidated balance sheet. Derivatives and hedging In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks of their debt hosts. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements. Equity method investments In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements. Employee share-based payments In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. The Company has elected to account for forfeitures when they occur. This new guidance was effective January 1, 2017 and resulted in a cumulative-effect adjustment of $12 million to retained earnings and the recognition of a deferred tax asset related to employee share-based payments that were made prior to the adoption of this guidance. Consolidation In October 2016, the FASB issued new guidance on consolidation relating to VIEs held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to the Company's consolidation conclusions. Future Accounting Changes Revenue from contracts with customers In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Company will adopt the new guidance on the effective date of January 1, 2018. There are two methods in which the new guidance can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Company will adopt the guidance using the modified retrospective approach with the cumulative-effect of the adjustment, if any, recognized at the date of adoption, subject to allowable and elected practical expedients. The Company identified all existing customer contracts that are within the scope of the new guidance by operating segment. The Company has completed its analysis of the contracts and has not identified any material differences in the amount and timing of revenue recognition as a result of implementing the new guidance. Therefore, the Company will not require a cumulative-effect adjustment to opening retained earnings on January 1, 2018. Although consolidated revenues will not be materially impacted by the new guidance, the Company will be required to add significant disclosures based on the prescribed requirements. These new disclosures will include information regarding the significant judgments used in evaluating when and how revenues, are recognized and information related to contract assets and deferred revenues. In addition, the new guidance requires that the Company’s revenue recognition policy disclosure include additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenues and cash flows generated from contracts with customers. The Company has developed draft disclosures required in first quarter 2018 with a particular focus on the scope of contracts subject to disclosure of future revenues from remaining performance obligations. The Company has addressed system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. Financial instruments In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in the fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018 and a method of adoption is specified for each component of the guidance. The Company has completed its analysis and does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the lessor to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for an arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is continuing to identify and analyze existing lease agreements to determine the effect of application of the new guidance on its consolidated financial statements. The Company is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance and continues to monitor and analyze additional guidance and clarification provided by the FASB. Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Income taxes In October 2016, the FASB issued new guidance on the income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied using a modified retrospective approach. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. Restricted cash In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents balance, and amounts generally described as restricted cash or restricted cash equivalents. Restricted cash and cash equivalents will be included with Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively. Goodwill impairment In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating Step 2 of the impairment test, which is the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted. Employee post-retirement benefits In March 2017, the FASB issued new guidance that will require entities to disaggregate the current service cost component from the other components of net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance is effective January 1, 2018. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. Amortization on purchased callable debt securities In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Hedge accounting In August 2017, the FASB issued new guidance on hedge accounting, making more financial and non-financial hedging strategies eligible for hedge accounting. The new guidance also amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019, with early adoption permitted. The Company has elected to apply this guidance effective January 1, 2018. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. |
SEGMENTED INFORMATION
SEGMENTED INFORMATION | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
SEGMENTED INFORMATION | SEGMENTED INFORMATION year ended December 31, 2017 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,693 3,584 570 2,009 3,593 — 13,449 Intersegment revenues — 51 — — — (51 ) — 3,693 3,635 570 2,009 3,593 (51 ) 13,449 Income from equity investments 11 240 (9 ) (3 ) 471 63 2 773 Plant operating costs and other (1,300 ) (1,340 ) (42 ) (623 ) (550 ) (51 ) (3,906 ) Commodity purchases resold — — — — (2,382 ) — (2,382 ) Property taxes (260 ) (181 ) — (89 ) (39 ) — (569 ) Depreciation and amortization (908 ) (594 ) (93 ) (309 ) (151 ) — (2,055 ) Goodwill and other asset impairment charges — — — (1,236 ) (21 ) — (1,257 ) Gain on assets held for sale/sold — — — — 631 — 631 Segmented earnings/(losses) 1,236 1,760 426 (251 ) 1,552 (39 ) 4,684 Interest expense (2,137 ) Allowance for funds used during construction 507 Interest income and other 183 Income before income taxes 3,237 Income tax recovery 107 Net income 3,344 Net income attributable to non-controlling interests (238 ) Net income attributable to controlling interests and to common shares 3,106 Capital spending Capital expenditures 2,106 3,712 833 341 350 41 7,383 Capital projects in development 75 — — 71 — — 146 Contributions to equity investments — 118 1,121 117 325 — 1,681 2,181 3,830 1,954 529 675 41 9,210 1 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. 2 This Inc ome from equity investments relates to foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture. Refer to Note 9, Equity investments, for further information. year ended December 31, 2016 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,682 2,526 378 1,755 4,206 — 12,547 Intersegment revenues — 56 — — — (56 ) — 3,682 2,582 378 1,755 4,206 (56 ) 12,547 Income from equity investments 12 214 (3 ) (1 ) 292 — 514 Plant operating costs and other (1,245 ) (1,057 ) (43 ) (568 ) (884 ) (64 ) (3,861 ) Commodity purchases resold — — — — (2,172 ) — (2,172 ) Property taxes (267 ) (120 ) — (88 ) (80 ) — (555 ) Depreciation and amortization (875 ) (425 ) (45 ) (292 ) (302 ) — (1,939 ) Goodwill and other asset impairment charges — — — — (1,388 ) — (1,388 ) Loss on assets held for sale/sold — (4 ) — — (829 ) — (833 ) Segmented earnings/(losses) 1,307 1,190 287 806 (1,157 ) (120 ) 2,313 Interest expense (1,927 ) Allowance for funds used during construction 419 Interest income and other 117 Income before income taxes 922 Income tax expense (349 ) Net income 573 Net income attributable to non-controlling interests (252 ) Net income attributable to controlling interests and to common shares 321 Capital spending Capital expenditures 1,372 1,517 944 668 473 33 5,007 Capital projects in development 153 — — 142 — — 295 Contributions to equity investments — 5 198 327 235 — 765 1,525 1,522 1,142 1,137 708 33 6,067 1 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. year ended December 31, 2015 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,680 1,444 259 1,879 4,091 — 11,353 Intersegment revenues — 47 — — — (47 ) — 3,680 1,491 259 1,879 4,091 (47 ) 11,353 Income from equity investments 12 162 5 — 261 — 440 Plant operating costs and other (1,204 ) (606 ) (51 ) (492 ) (845 ) (105 ) (3,303 ) Commodity purchases resold — — — — (2,237 ) — (2,237 ) Property taxes (272 ) (77 ) — (79 ) (89 ) — (517 ) Depreciation and amortization (849 ) (248 ) (44 ) (283 ) (341 ) — (1,765 ) Asset impairment charges — — — (3,686 ) (59 ) — (3,745 ) Loss on assets held for sale/sold — (125 ) — — — — (125 ) Segmented earnings/(losses) 1,367 597 169 (2,661 ) 781 (152 ) 101 Interest expense (1,398 ) Allowance for funds used during construction 295 Interest income and other (103 ) Loss before income taxes (1,105 ) Income tax expense (35 ) Net loss (1,140 ) Net income attributable to non-controlling interests (6 ) Net loss attributable to controlling interests and to common shares (1,146 ) Capital spending Capital expenditures 1,366 534 566 1,012 376 64 3,918 Capital projects in development 230 3 — 278 — — 511 Contributions to equity investments — — — 311 182 — 493 1,596 537 566 1,601 558 64 4,922 1 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. at December 31 2017 2016 (millions of Canadian $) Total Assets Canadian Natural Gas Pipelines 16,904 15,816 U.S. Natural Gas Pipelines 35,898 34,422 Mexico Natural Gas Pipelines 5,716 5,013 Liquids Pipelines 15,438 16,896 Energy 8,503 13,169 Corporate 3,551 2,625 86,010 87,941 Geographic Information year ended December 31 2017 2016 2015 (millions of Canadian $) Revenues Canada – domestic 3,618 3,697 3,930 Canada – export 1,255 1,177 1,292 United States 8,006 7,295 5,872 Mexico 570 378 259 13,449 12,547 11,353 at December 31 2017 2016 (millions of Canadian $) Plant, Property and Equipment Canada 21,632 20,531 United States 30,693 29,414 Mexico 4,952 4,530 57,277 54,475 |
ACQUISITION OF COLUMBIA
ACQUISITION OF COLUMBIA | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
ACQUISITION OF COLUMBIA | ACQUISITION OF COLUMBIA On July 1, 2016 , TCPL acquired 100 per cent ownership of Columbia Pipeline Group, Inc. (Columbia) for a purchase price of US$10.3 billion in cash, based on US$25.50 per share for all of Columbia's outstanding common shares as well as all outstanding restricted and performance stock units. The acquisition was financed through the issuance of TCPL common shares to TransCanada, an intercompany loan due to TransCanada in connection with proceeds received from the sale of TransCanada subscription receipts and draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion . The sale of the subscription receipts was completed on April 1, 2016 through a public offering, and gross proceeds of approximately $4.4 billion were transferred to TCPL prior to the closing of the acquisition. Refer to Note 20, Common shares, Note 28, Related party transactions and Note 17, Long-term debt for further information on the common shares issued to TransCanada, the intercompany loan due to TransCanada and the acquisition bridge facilities. At the date of acquisition, Columbia operated a portfolio of approximately 24,500 km ( 15,200 miles ) of regulated natural gas pipelines, 285 Bcf of natural gas storage facilities and midstream and other assets in various regions in the U.S. TCPL acquired Columbia to expand the Company’s natural gas business in the U.S. market, positioning the Company for additional long-term growth opportunities. The goodwill arising from the acquisition principally reflects the opportunities to expand the Company’s U.S. Natural Gas Pipelines segment and to gain a stronger competitive position in the North American natural gas business. The goodwill resulting from the acquisition is not deductible for income tax purposes. The acquisition was accounted for as a business combination using the acquisition method where the acquired tangible and intangible assets and assumed liabilities were recorded at their estimated fair values at the date of acquisition. The purchase price equation reflects management’s estimate of the fair value of Columbia’s assets and liabilities as at July 1, 2016 . July 1, 2016 (millions of $) U.S. Canadian 1 Purchase Price Consideration 10,294 13,392 Fair Value Current assets 658 856 Plant, property and equipment 7,560 9,835 Equity investments 441 574 Regulatory assets 190 248 Intangible and other assets 135 175 Current liabilities (597 ) (777 ) Regulatory liabilities (294 ) (383 ) Other long-term liabilities (144 ) (187 ) Deferred income tax liabilities (1,613 ) (2,098 ) Long-term debt (2,981 ) (3,878 ) Non-controlling interests (808 ) (1,051 ) Fair Value of Net Assets Acquired 2,547 3,314 Goodwill (Note 11) 7,747 10,078 1 At July 1, 2016 exchange rate of $1.30 . The fair values of current assets including cash and cash equivalents, accounts receivable, and inventories and the fair values of current liabilities including notes payable and accrued interest approximated their carrying values due to the short-term nature of these items. Certain acquisition-related working capital items resulted in an adjustment to accounts payable. Columbia’s natural gas pipelines are subject to FERC regulations and, as a result, their rate bases are expected to be recovered with a reasonable rate of return over the life of the assets. These assets, as well as related regulatory assets and liabilities, had fair values equal to their carrying values on acquisition. The fair value of mineral rights included in Columbia's plant, property and equipment was determined using a discounted cash flow approach which resulted in a fair value increase of $241 million ( US$185 million ). On acquisition date, the fair value of base gas included in Columbia’s plant, property and equipment was determined by using a quoted market price multiplied by the estimated volume of base gas in place which resulted in a fair value increase of $840 million ( US$646 million ). In second quarter 2017, the Company completed its procedures over measuring the volume of base gas acquired and, as a result, decreased its fair value by $116 million ( US$90 million ). This impacted the purchase price equation by decreasing property, plant and equipment by $116 million ( US$90 million ), decreasing deferred income tax liabilities by $45 million ( US$35 million ) and increasing goodwill by $71 million ( US$55 million ). This adjustment did not impact the Company's net income. At December 31, 2017, goodwill related to the acquisition of Columbia is US$7,802 million (2016 – US$7,747 million ). Refer to Note 11, Goodwill, for further information. The fair value of Columbia’s long-term debt was estimated using an income approach based on observable market rates for similar debt instruments from external data service providers. This resulted in a fair value increase of $300 million ( US$231 million ). The following table summarizes the acquisition date fair value of Columbia's debt acquired by TCPL. (millions of $) Maturity Date Type Fair Value Interest Rate COLUMBIA PIPELINE GROUP, INC. June 2018 Senior Unsecured Notes (US$500) US$506 2.45 % June 2020 Senior Unsecured Notes (US$750) US$779 3.30 % June 2025 Senior Unsecured Notes (US$1,000) US$1,092 4.50 % June 2045 Senior Unsecured Notes (US$500) US$604 5.80 % US$2,981 The fair values of Columbia's DB plan and other post-retirement benefit plans were based on an actuarial valuation of the funded status of the plans, as of the acquisition date which resulted in an increase of $15 million ( US$12 million ) and $5 million ( US$4 million ) to Regulatory assets and Other long-term liabilities, respectively, and a decrease of $14 million ( US$11 million ) and $2 million ( US$2 million ) to Intangible and other assets and Regulatory liabilities, respectively. Temporary differences created as a result of the fair value changes described above resulted in deferred income tax assets and liabilities that were recorded at the Company's U.S. effective tax rate of 39 per cent . The fair value of Columbia’s non-controlling interest was based on the approximately 53.8 million Columbia Pipeline Partners LP (CPPL) common units outstanding to the public as of June 30, 2016 , and valued at the June 30, 2016 closing price of US$15.00 per common unit . On February 17, 2017, TCPL acquired all outstanding publicly held common units of CPPL. Refer to Note 19, Non-controlling interests, for further information. In 2016, acquisition expenses of approximately $36 million were included in Plant operating costs and other in the Consolidated statement of income. Upon completion of the acquisition, the Company began consolidating Columbia. Columbia’s significant accounting policies were consistent with TCPL's and continued to be applied. Columbia contributed $929 million to the Company's Revenues and $132 million to the Company's net income from July 1, 2016 to December 31, 2016. The following supplemental pro forma consolidated financial information of the Company for the years ended December 31, 2016 and 2015 includes the results of operations for Columbia as if the acquisition had been completed on January 1, 2015 . year ended December 31 (millions of Canadian $) 2016 2015 Revenues 13,404 13,007 Net Income/(Loss) 715 (820 ) Net Income/(Loss) Attributable to Controlling Interests and to Common Shares 431 (877 ) |
ASSETS HELD FOR SALE
ASSETS HELD FOR SALE | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
ASSETS HELD FOR SALE | ASSETS HELD FOR SALE U.S. Northeast Power Assets The Company's monetization of its U.S. Northeast power assets, for the purpose of permanently financing the Columbia acquisition, included the sales of TC Hydro, Ravenswood, Ironwood, Kibby Wind and Ocean State Power that closed in second quarter 2017. On November 1, 2016 , the Company entered into an agreement to sell TC Hydro to a third party. At December 31, 2016, the related assets and liabilities were classified as held for sale in the Energy segment. On April 19, 2017, the Company completed the sale of TC Hydro for proceeds of approximately US$1.07 billion , before post-closing adjustments. Refer to Note 25, Other acquisitions and dispositions, for further information. On November 1, 2016 , the Company entered into an agreement to sell Ravenswood, Ironwood, Kibby Wind and Ocean State Power to a third party. As a result, the Company recorded a loss of approximately $829 million ( $863 million after tax) in 2016 which was included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income. This included the impact of an estimated $70 million of foreign currency translation gains to be reclassified from AOCI to net income on close. At December 31, 2016, the related assets and liabilities were classified as held for sale in the Energy segment and were recorded at their fair values less costs to sell based on the proceeds expected from the sale. On June 2, 2017, TCPL completed the sale of these assets for proceeds of approximately US$2.029 billion , before post-closing adjustments. Refer to Note 25, Other acquisitions and dispositions, for further information. |
OTHER CURRENT ASSETS
OTHER CURRENT ASSETS | 12 Months Ended |
Dec. 31, 2017 | |
Other Assets [Abstract] | |
OTHER CURRENT ASSETS | OTHER CURRENT ASSETS at December 31 2017 2016 (millions of Canadian $) Fair value of derivative contracts (Note 23) 332 376 Prepaid expenses 109 131 Cash provided as collateral 99 313 Regulatory assets (Note 10) 23 33 Other 128 55 691 908 |
PLANT, PROPERTY AND EQUIPMENT
PLANT, PROPERTY AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
PLANT, PROPERTY AND EQUIPMENT | PLANT, PROPERTY AND EQUIPMENT 2017 2016 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 10,153 4,190 5,963 8,814 3,951 4,863 Compression 3,021 1,593 1,428 2,447 1,499 948 Metering and other 1,188 569 619 1,124 519 605 14,362 6,352 8,010 12,385 5,969 6,416 Under construction 940 — 940 1,151 — 1,151 15,302 6,352 8,950 13,536 5,969 7,567 Canadian Mainline Pipeline 9,763 6,455 3,308 9,502 6,221 3,281 Compression 3,605 2,499 1,106 3,537 2,361 1,176 Metering and other 655 207 448 605 198 407 14,023 9,161 4,862 13,644 8,780 4,864 Under construction 156 — 156 219 — 219 14,179 9,161 5,018 13,863 8,780 5,083 Other Canadian Natural Gas Pipelines Other 1 1,815 1,363 452 1,728 1,273 455 Under construction 4 — 4 112 — 112 1,819 1,363 456 1,840 1,273 567 31,300 16,876 14,424 29,239 16,022 13,217 U.S. Natural Gas Pipelines Columbia Gas Pipeline 3,550 125 3,425 3,317 42 3,275 Compression 1,547 64 1,483 1,636 29 1,607 Metering and other 2,306 37 2,269 2,550 8 2,542 7,403 226 7,177 7,503 79 7,424 Under construction 3,332 — 3,332 1,127 — 1,127 10,735 226 10,509 8,630 79 8,551 ANR Pipeline 1,427 365 1,062 1,468 349 1,119 Compression 1,582 286 1,296 1,494 260 1,234 Metering and other 961 268 693 988 254 734 3,970 919 3,051 3,950 863 3,087 Under construction 358 — 358 232 — 232 4,328 919 3,409 4,182 863 3,319 2017 2016 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,107 822 1,285 2,221 810 1,411 Great Lakes 1,988 1,113 875 2,106 1,155 951 Columbia Gulf 1,115 37 1,078 880 5 875 Midstream 1,085 54 1,031 1,072 23 1,049 Other 2 1,950 574 1,376 2,120 567 1,553 8,245 2,600 5,645 8,399 2,560 5,839 Under construction 699 — 699 346 — 346 8,944 2,600 6,344 8,745 2,560 6,185 24,007 3,745 20,262 21,557 3,502 18,055 Mexico Natural Gas Pipelines Pipeline 2,486 214 2,272 2,734 180 2,554 Compression 388 30 358 422 19 403 Metering and other 522 65 457 502 40 462 3,396 309 3,087 3,658 239 3,419 Under construction 1,865 — 1,865 1,108 — 1,108 5,261 309 4,952 4,766 239 4,527 Liquids Pipelines Keystone Pipeline System Pipeline 9,002 992 8,010 10,572 901 9,671 Pumping equipment 1,022 152 870 928 121 807 Tanks and other 3,314 385 2,929 2,521 286 2,235 13,338 1,529 11,809 14,021 1,308 12,713 Under construction 456 — 456 479 — 479 13,794 1,529 12,265 14,500 1,308 13,192 Intra-Alberta Pipelines 3 Pipeline 748 3 745 — — — Pumping equipment 104 — 104 — — — Tanks and other 259 1 258 — — — 1,111 4 1,107 — — — Under construction 47 — 47 955 — 955 1,158 4 1,154 955 — 955 14,952 1,533 13,419 15,455 1,308 14,147 Energy Natural Gas 4,5 2,645 743 1,902 2,696 696 2,000 Wind and Solar 6 673 204 469 1,180 245 935 Natural Gas Storage and Other 734 156 578 731 146 585 4,052 1,103 2,949 4,607 1,087 3,520 Under construction 1,028 — 1,028 729 — 729 5,080 1,103 3,977 5,336 1,087 4,249 Corporate 411 168 243 410 130 280 81,011 23,734 57,277 76,763 22,288 54,475 1 Includes Foothills, Ventures LP and Great Lakes Canada . 2 Includes Bison, Portland Natural Gas Transmission System, North Baja, Tuscarora and Crossroads. 3 Includes Northern Courier, placed in-service on November 1, 2017 and White Spruce. 4 Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities was $ 1,264 million and $ 354 million , respectively, at December 31, 2017 ( 2016 – $ 1,319 million and $ 335 million , respectively). Revenues of $ 215 million were recognized in 2017 ( 2016 – $ 212 million ; 2015 – $ 235 million ) through the sale of electricity under the related PPAs. 5 Includes Coolidge, Grandview, and Bécancour assets which operate under operating leases, along with Halton Hills and Alberta cogeneration natural gas-fired facilities. 6 Ontario solar assets are excluded from the Wind and Solar net book value at December 31, 2017 as they were sold on December 19, 2017. Refer to Note 25, Other acquisitions and dispositions, for further information. Energy East and Related Projects Impairment On October 5, 2017 , the Company informed the NEB that it will not proceed with the Energy East, Eastern Mainline and Upland projects. Based on this decision, the Company evaluated the carrying value of its Property, plant and equipment related to the Eastern Mainline project including AFUDC. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties. As a result, the Company recognized a non-cash impairment charge of $83 million ( $64 million after tax) in the Liquids Pipelines segment. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. Energy Turbine Impairment Following the evaluation of specific capital project opportunities in 2015, it was determined that the carrying value of certain Energy turbine equipment was not fully recoverable. These turbines had been previously purchased for a power development project that did not proceed. As a result, at December 31, 2015 , the Company recognized a non-cash impairment charge of $ 59 million ($ 43 million after tax) in the Energy segment. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. This impairment charge was based on the excess of the carrying value over the estimated fair value of the turbines, which was determined based on a comparison to similar assets available for sale in the market. At December 31, 2017, the Company again re-assessed the remaining carrying value of this Energy turbine equipment and determined that it was not recoverable. As a result, the Company recognized a non-cash impairment charge of $21 million ($ 16 million after tax) in the Energy segment related to the remaining carrying value. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. Keystone XL Impairment At December 31, 2015 , the Company evaluated its investment in Keystone XL and related projects for impairment in connection with the November 6, 2015 denial of the U.S. Presidential permit. As a result of the analysis, the Company recognized a non-cash impairment charge in its Liquids Pipelines segment of $ 3,686 million ($ 2,891 million after tax) based on the excess of the carrying value over the estimated fair value of $621 million of these assets. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. |
EQUITY INVESTMENTS
EQUITY INVESTMENTS | 12 Months Ended |
Dec. 31, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
EQUITY INVESTMENTS | EQUITY INVESTMENTS (millions of Canadian $) Ownership Income/(Loss) from Equity Investments Equity Investments year ended December 31 at December 31 2017 2016 2015 2017 2016 Canadian Natural Gas Pipelines TQM 50.0 % 11 12 12 68 71 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 87 92 85 641 597 Iroquois 2 50.0 % 59 54 51 280 309 Millennium 3 47.5 % 66 33 — 291 295 Pennant Midstream 3 47.0 % 11 6 — 228 246 Other Various 17 29 26 92 93 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % 66 (3 ) — 399 255 TransGas 46.5 % (12 ) — 5 — 28 Liquids Pipelines Grand Rapids 5 50.0 % 17 (1 ) — 996 876 Other 6 Various (20 ) — — 20 39 Energy Bruce Power 7 48.4 % 434 293 249 2,987 3,356 Portlands Energy 8 50.0 % 31 33 30 301 313 ASTC Power Partnership 50.0 % — (37 ) (23 ) — — Other Various 6 3 5 63 66 773 514 440 6,366 6,544 1 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company was US$115 million ( 2016 – US$116 million ) due to the fair value assessment of assets at the time of acquisition. 2 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million ( 2016 – US$48 million ) due mainly to the fair value assessment of the assets at the time of acquisition. 3 Acquired as part of Columbia on July 1, 2016. Income from Equity investments reflects equity earnings from the date of acquisition. 4 TCPL has an ownership interest of 60.0 per cent in Sur de Texas, which as a jointly controlled entity applies the equity method of accounting. Income from equity investments includes amounts recorded in the Corporate segment. 5 Grand Rapids was placed in service in August 2017. At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $105 million ( 2016 – $86 million ) due mainly to interest capitalized during construction and the fair value of guarantees. 6 Includes investments in Canaport Energy East Marine Terminal Limited Partnership and HoustonLink Pipeline Company LLC. At December 31, 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil . 7 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $902 million ( 2016 – $942 million ) due to the fair value assessment of assets at the time of acquisitions. 8 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million ( 2016 – $70 million ) due mainly to interest capitalized during construction. TransGas de Occidente S.A. Impairment In August 2017, TCPL recognized an impairment charge of $12 million on its 46.5 per cent equity investment in TransGas de Occidente S.A. (TransGas). TransGas constructed and operated a natural gas pipeline in Colombia for a 20 -year contract term. As per the terms of the agreement, upon completion of the 20 -year contract in August 2017, TransGas transferred its pipeline assets to Transportadora de Gas Internacional S.A.. The impairment charge represents the write-down of the remaining carrying value of the equity investment. The non-cash impairment charge was recognized in Income from equity investments in the Consolidated statement of income. Canaport Energy East Marine Terminal Limited Partnership Impairment On October 5, 2017, the Company informed the NEB that it will not be proceeding with the Energy East, Eastern Mainline and Upland projects. As a result, in October 2017 the Company recognized a non-cash impairment charge of $20 million in its Liquids Pipelines segment Income from equity investments which represented the carrying value of the equity investment in the Canaport Energy East Marine Terminal Limited Partnership. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties. ASTC Power Partnership Impairment In March 2016, TCPL issued notice to the Balancing Pool of the decision to terminate its Sundance B PPA held through ASTC Power Partnership. In accordance with a provision in the PPA, a buyer was permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. As a result of changes in law surrounding the Alberta Specified Gas Emitters Regulation, the Company expected increasing costs related to carbon emissions to continue throughout the remaining term of the PPA resulting in increasing unprofitability. As a result, in first quarter 2016, the Company recognized a non-cash impairment charge of $29 million ( $21 million after tax) in its Energy segment Income from equity investments which represented the carrying value of the equity investment in ASTC Partnership. The PPA termination was settled in December 2016. Distributions and Contributions Distributions received from equity investments for the year ended December 31, 2017 were $ 1,332 million ( 2016 – $ 1,571 million ; 2015 – $ 802 million ) of which $ 362 million ( 2016 – $ 727 million ; 2015 – $ 9 million ) was included in Investing activities in the Consolidated statement of cash flows with respect to distributions received from Bruce Power in 2017 and 2016 from its financing program. Undistributed earnings from equity investments were $ 198 million at December 31, 2015 . Contributions made to equity investments for the year ended December 31, 2017 were $ 1,681 million ( 2016 – $ 765 million ; 2015 – $ 493 million ) and are included in Investing activities in the Consolidated statement of cash flows. For 2017, contributions include $ 977 million related to TCPL's proportionate share of the Sur de Texas debt financing requirements. Summarized Financial Information of Equity Investments year ended December 31 2017 2016 2015 (millions of Canadian $) Income Revenues 4,913 4,336 4,337 Operating and other expenses (2,993 ) (3,068 ) (3,142 ) Net income 1,636 1,080 1,046 Net income attributable to TCPL 773 514 440 at December 31 2017 2016 (millions of Canadian $) Balance Sheet Current assets 2,176 1,669 Non-current assets 17,869 15,853 Current liabilities (1,577 ) (1,120 ) Non-current liabilities (8,217 ) (5,867 ) Loan receivable from affiliate TCPL holds a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. On April 21, 2017, TCPL entered into a MXN$13.6 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. On December 6, 2017, TCPL and the joint venture entered into an amended agreement to increase the credit facility to MXN$21.3 billion . At December 31, 2017 , the Company’s consolidated balance sheet included a $919 million loan receivable from the Sur de Texas joint venture which represents TCPL's proportionate share of the debt financing requirements related to the joint venture. Interest income and other included interest income of $34 million in 2017 from this joint venture with a corresponding proportionate share of interest expense recorded in Income from equity investments. |
RATE-REGULATED BUSINESSES
RATE-REGULATED BUSINESSES | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
RATE-REGULATED BUSINESSES | RATE-REGULATED BUSINESSES TCPL's businesses that apply RRA currently include certain Canadian, U.S. and Mexico natural gas pipelines, and certain regulated U.S. natural gas storage operations. Rate-regulated businesses account for and report assets and liabilities consistent with the resulting economic impact of the regulators' established rates, provided the rates are designed to recover the costs of providing the regulated service and the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination that would otherwise be reflected in the statement of income are deferred on the balance sheet and are expected to be included in future service rates and recovered from or refunded to customers in subsequent years. Canadian Regulated Operations TCPL's Canadian natural gas pipelines are regulated by the NEB under the National Energy Board Act . The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems. TCPL's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return on capital as approved by the NEB. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent actual costs and revenues are more or less than forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur. The Company's most significant regulated Canadian natural gas pipelines are described below. NGTL System The NGTL System’s 2017 and 2016 results reflect the terms of the 2016-2017 Revenue Requirement Settlement approved by the NEB in April 2016. This settlement includes an ROE of 10.1 per cent on 40 per cent deemed equity, a composite depreciation rate of approximately 3.16 per cent , a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration (OM&A) cost amount and flow-through treatment of all other costs. The NGTL System’s 2015 results reflect the terms of the 2015 Revenue Requirement Settlement. This one -year settlement included a 10.1 per cent ROE on deemed common equity of 40 per cent , a composite depreciation rate of approximately 3.1 per cent , a mechanism for sharing variances above and below a fixed annual OM&A cost amount and flow-through treatment of all other costs. Canadian Mainline The Canadian Mainline currently operates under the terms of the 2015-2030 Tolls Application approved in 2014 (the NEB 2014 Decision). The terms of the settlement include an ROE of 10.1 per cent on deemed common equity of 40 per cent , an incentive mechanism that has both upside and downside risk and a $20 million after-tax annual TCPL contribution to reduce the revenue requirement. Toll stabilization is achieved through the continued use of deferral accounts, namely the bridging amortization account and the long-term adjustment account (LTAA), to capture the surplus or shortfall between the Company's revenues and cost of service for each year over the six -year fixed toll term of the NEB 2014 Decision. As directed by the NEB, the Canadian Mainline filed an application for approval of 2018-2020 tolls on December 18, 2017. U.S. Regulated Operations TCPL's U.S. regulated natural gas pipelines, operate under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities, including the regulation of tariffs which incorporates maximum and minimum rates for services and allows U.S. regulated natural gas pipelines to discount or negotiate rates on a non-discriminatory basis. The Company's most significant regulated U.S. natural gas pipelines, based on effective ownership and total operated pipe length, are described below. Columbia Gas Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval. In 2013, the FERC approved a modernization settlement which provides for cost recovery and return on investment of up to US$1.5 billion over a five -year period to modernize the Columbia Gas system to improve system integrity and enhance service reliability and flexibility. In March 2016, an extension of this settlement was approved by the FERC, which will allow for the cost recovery and return on additional expanded scope investment of US$1.1 billion over a three -year period through 2020. ANR Pipeline Company ANR Pipeline Company previously operated under rates established pursuant to a settlement approved by the FERC that was effective for all periods presented beginning in 1997 through July 31, 2016. Effective August 1, 2016, ANR Pipeline Company began operating under new rates pursuant to a FERC-approved rate settlement in September 2016. Under terms of the September 2016 settlement, neither ANR Pipeline Company nor the settling parties can file for new rates to become effective earlier than August 1, 2019. However, ANR Pipeline Company is required to file for new rates to be effective no later than August 1, 2022. Great Lakes On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its previous 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, if approved by FERC, will result in a decrease in Great Lakes' maximum transportation rates effective October 1, 2017. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022. Columbia Gulf Columbia Gulf’s natural gas transportation services are provided under a tariff at rates subject to FERC approval. In September 2016, the FERC issued an order approving an uncontested settlement following a FERC-initiated rate proceeding pursuant to section 5 of the NGA, which required a reduction in Columbia Gulf’s daily maximum recourse rate and addressed treatment of post-retirement benefits other than pensions, pension expense and regulatory expenses. The FERC order also requires Columbia Gulf to file a general rate case under section 4 of the NGA by January 31, 2020, for rates to take effect by August 1, 2020. Mexico Regulated Operations TCPL's Mexico natural gas pipelines operations are regulated by the CRE and operate in accordance with CRE-approved tariffs. The rates in effect on TCPL's Mexico natural gas pipelines were established based on CRE-approved contracts that provide for the recovery of costs of providing services. Regulatory Assets and Liabilities at December 31 2017 2016 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 967 861 n/a Deferred income taxes – U.S. Tax Reform 2 (27 ) — n/a Operating and debt-service regulatory assets 3 — 1 1 Pensions and other post-retirement benefits 1,4 388 382 n/a Foreign exchange on long-term debt 1,5 — 37 1-12 Other 71 74 n/a 1,399 1,355 Less: Current portion included in Other current assets (Note 7) 23 33 1,376 1,322 Regulatory Liabilities Operating and debt-service regulatory liabilities 3 188 47 1 Pensions and other post-retirement benefits 4 164 180 n/a ANR related post-employment and retirement benefits other than pension 6 66 141 n/a Long term adjustment account 7 1,142 659 46 Pipeline abandonment trust balance 825 541 n/a Bridging amortization account 7 202 451 13 Cost of removal 8 216 226 n/a Deferred income taxes 75 — n/a Deferred income taxes – U.S. Tax Reform 2 1,659 — n/a Other 47 54 n/a 4,584 2,299 Less: Current portion included in Accounts payable and other (Note 14) 263 178 4,321 2,121 1 These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period. 2 These balances represent the impact of U.S. Tax Reform. The regulatory assets and regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax assets and liabilities that gave rise to the regulatory assets and liabilities. See Note 16, Income taxes, for further information. 3 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar years. 4 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates. 5 Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. 6 This balance represents the amount ANR estimates it would be required to refund to its customers for post-retirement and post-employment benefit amounts collected through its FERC-approved rates that have not been used to pay benefits to its employees. Pursuant to a FERC-approved September 2016 rate settlement, $26 million ( US$21 million ) of the regulatory liability balance at December 31, 2017 (2016 – $46 million , US$34 million ) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $40 million ( US$32 million ) balance accumulated prior to 2007 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period cannot be determined at this time. 7 These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. 8 This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated subsidiaries for future costs to be incurred. |
GOODWILL
GOODWILL | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL | GOODWILL The Company has recorded the following Goodwill on its acquisitions in the U.S.: (millions of Canadian $) U.S. Natural Gas Pipelines Energy Total Balance at January 1, 2016 3,667 1,145 4,812 Acquisition of Columbia (Note 5) 10,078 — 10,078 Impairment charge — (1,085 ) (1,085 ) Foreign exchange rate changes 213 (60 ) 153 Balance at December 31, 2016 13,958 — 13,958 Columbia adjustment (Note 5) 71 — 71 Foreign exchange rate changes (945 ) — (945 ) Balance at December 31, 2017 13,084 — 13,084 At December 31, 2017 , the estimated fair value of Great Lakes exceeded its carrying value by less than 10 per cent. The fair value of this reporting unit was measured using a discounted cash flow analysis. Assumptions used in the analysis regarding Great Lakes’ ability to realize long-term value in the North American energy market included the reduction in Great Lakes' rates effective October 1, 2017 as a result of the expected outcome of the 2017 Great Lakes Settlement. The reduction in rates was offset by expected cash flows from the long-term transportation contract with the Canadian Mainline, other opportunities to increase utilization on the system and the 2017 Great Lakes Settlement's elimination of the revenue sharing mechanism with its customers. Although evolving market conditions and other factors relevant to Great Lakes' long term financial performance have been positive, there is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in a future impairment of a portion of the goodwill relating to Great Lakes. The goodwill balance related to Great Lakes at December 31, 2017 was US$573 million ( 2016 – US$573 million ). As a result of information received during the process to monetize the Company's U.S. Northeast power business in third quarter 2016 , it was determined that the fair value of Ravenswood did not exceed its carrying value, including goodwill. The fair value of the reporting unit was determined using a combination of methods including a discounted cash flow approach and a range of expected consideration from a potential sale. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. As a result, in 2016 , the Company recorded a goodwill impairment charge on the full carrying value of Ravenswood goodwill of $1,085 million ( $656 million after tax) within the Energy segment. |
INTANGIBLE AND OTHER ASSETS
INTANGIBLE AND OTHER ASSETS | 12 Months Ended |
Dec. 31, 2017 | |
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |
INTANGIBLE AND OTHER ASSETS | INTANGIBLE AND OTHER ASSETS at December 31 2017 2016 (millions of Canadian $) Capital projects in development 596 2,094 Deferred income tax assets (Note 16) 255 313 Employee post-retirement benefits (Note 22) 193 189 Fair value of derivative contracts (Note 23) 73 133 Other 306 218 1,423 2,947 Prince Rupert Gas Transmission In July 2017 , the Company was notified that Pacific Northwest LNG would not be proceeding with its proposed LNG project and that Progress Energy (Progress) would be terminating its agreement with TCPL for the development of the PRGT project effective August 10, 2017. In accordance with the terms of the agreement, all project costs incurred to advance the project, including carrying charges, are fully recoverable upon termination. In October 2017 , the Company received full payment of the $634 million reimbursement from Progress. Energy East and Related Projects Impairment On October 5, 2017, the Company informed the NEB that it will not proceed with the Energy East, Eastern Mainline and Upland projects. Based on this decision, the Company evaluated its Capital projects in development balance related to the Energy East and Upland projects including AFUDC. As a result, the Company recognized a non-cash impairment charge of $1,153 million ( $870 million after tax) in the Liquids Pipelines segment. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. Power Purchase Arrangements In March 2016 , TCPL issued notice to the Balancing Pool of the decision to terminate its Sheerness and Sundance A PPAs. In accordance with a provision in the PPAs, a buyer was permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. As a result of changes in law surrounding the Alberta Specified Gas Emitters Regulation, the Company expected increasing costs related to carbon emissions to continue throughout the remaining terms of the PPAs resulting in increasing unprofitability. As such, in 2016, the Company recognized a non-cash impairment charge of $211 million ($ 155 million after tax) in its Energy segment, representing the carrying value of the PPAs which was recorded in Intangible and other assets. Upon final settlement of the PPA terminations in December 2016, TCPL transferred to the Balancing Pool a package of environmental credits that were being held to offset the PPA emissions costs and recorded a non-cash charge of $92 million ( $68 million after tax) related to the carrying value of these environmental credits. Amortization expense of $ 9 million was recognized in the Consolidated statement of income for the year ended December 31, 2016 ( 2015 – $ 52 million ), prior to the termination of the PPAs. |
NOTES PAYABLE
NOTES PAYABLE | 12 Months Ended |
Dec. 31, 2017 | |
Short-term Debt [Abstract] | |
NOTES PAYABLE | NOTES PAYABLE 2017 2016 (millions of Canadian $, unless otherwise noted) Outstanding at December 31 Weighted Average Interest Rate per Annum at December 31 Outstanding at December 31 Weighted Average Interest Rate per Annum at December 31 Canadian 884 1.6 % 509 0.9 % U.S. (2017 – US$688; 2016 – US$197) 862 2.2 % 265 0.5 % MXN (2017 – MXN$275) 17 8.0 % — — 1,763 774 At December 31, 2017 , Notes payable consists of short-term borrowing by TCPL, TransCanada American Investments Ltd. (TAIL), TransCanada PipeLine USA Ltd. (TCPL USA), Columbia and a Mexican subsidiary. At December 31, 2017 , total committed revolving and demand credit facilities were $ 11.0 billion ( 2016 – $11.1 billion ). When drawn, interest on these lines of credit is charged at negotiated floating rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2017 2016 Borrower Description Matures Total Facilities Unused Capacity Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 1 : TCPL Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes December 2022 3.0 3.0 3.0 TCPL Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes December 2018 US 2.0 US 2.0 US 2.0 TCPL USA Used for TCPL USA general corporate purposes, guaranteed by TCPL December 2018 US 1.0 US 0.6 US 1.0 Columbia Used for Columbia general corporate purposes, guaranteed by TCPL December 2018 US 1.0 US 1.0 US 1.0 TAIL Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL December 2018 US 0.5 US 0.5 US 0.5 Demand senior unsecured revolving credit facilities 1 : TCPL/TCPL USA Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL Demand 1.9 0.5 1.9 Mexican subsidiary Used for Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 MXN 4.7 — 1 Provisions of various credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2017, the Company was in compliance with all debt covenants. For the year ended December 31, 2017, the cost to maintain the above facilities was $ 7 million (2016 – $ 10 million ; 2015 – $ 11 million ). At December 31, 2017, the Company's operated affiliates had an additional $ 0.5 billion (2016 – $ 0.5 billion ) of undrawn capacity on committed credit facilities. |
ACCOUNTS PAYABLE AND OTHER
ACCOUNTS PAYABLE AND OTHER | 12 Months Ended |
Dec. 31, 2017 | |
Payables and Accruals [Abstract] | |
ACCOUNTS PAYABLE AND OTHER | ACCOUNTS PAYABLE AND OTHER at December 31 2017 2016 (millions of Canadian $) Trade payables 2,847 2,443 Fair value of derivative contracts (Note 23) 387 607 Unredeemed shares of Columbia 312 317 Regulatory liabilities (Note 10) 263 178 Other 262 331 4,071 3,876 |
OTHER LONG-TERM LIABILITIES
OTHER LONG-TERM LIABILITIES | 12 Months Ended |
Dec. 31, 2017 | |
Deferred Costs, Noncurrent [Abstract] | |
OTHER LONG-TERM LIABILITIES | OTHER LONG-TERM LIABILITIES at December 31 2017 2016 (millions of Canadian $) Employee post-retirement benefits (Note 22) 389 448 Fair value of derivative contracts (Note 23) 72 330 Asset retirement obligations 98 108 Guarantees (Note 26) 16 82 Other 152 215 727 1,183 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES U.S. Tax Reform On December 22, 2017, the President of the United States signed H.R.1, the Tax Cuts and Jobs Act (U.S. Tax Reform or the Act) into law. As a result, the enacted U.S. federal corporate income tax rate was reduced from 35 per cent to 21 per cent effective January 1, 2018 and resulted in a remeasurement of existing deferred income tax assets and deferred income tax liabilities related to the Company's U.S. businesses to reflect the new lower income tax rate as at December 31, 2017. For the Company’s U.S. businesses not subject to RRA, the reduction in enacted income tax rates resulted in a decrease in net deferred income tax liabilities and deferred income tax expense of $816 million . For the Company’s U.S. businesses subject to RRA, the reduction in income tax rates resulted in a reduction in net deferred income tax liabilities and the recognition of a net regulatory liability on the Consolidated balance sheet in the amount of $1,686 million . Net deferred income tax liabilities related to the cumulative remeasurements of employee post-retirement benefits included in AOCI have been adjusted with a corresponding increase in deferred income tax expense of $12 million . Given the significance of the legislation, the Securities and Exchange Commission (SEC) staff issued guidance which allows registrants to record provisional amounts which may be adjusted as information becomes available, prepared or analyzed during a measurement period not to exceed one year. The SEC guidance summarizes a three-step process to be applied at each reporting period to identify: (1) where the accounting is complete; (2) provisional amounts where the accounting is not yet complete, but a reasonable estimate has been determined; and (3) where a reasonable estimate cannot yet be determined and therefore income taxes are reflected in accordance with law prior to the enactment of the Act. At December 31, 2017, the Company considers all amounts recorded related to U.S. Tax Reform to be reasonable estimates. Amounts related to businesses subject to RRA are provisional as the Company’s interpretation, assessment and presentation of the impact of the tax law change may be further clarified with additional guidance from regulatory, tax and accounting authorities. Should additional guidance be provided by these authorities or other sources during the one-year measurement period, TCPL will review the provisional amounts and adjust as appropriate. Provision for Income Taxes year ended December 31 2017 2016 2015 (millions of Canadian $) Current Canada 113 117 45 Foreign 36 40 92 149 157 137 Deferred Canada (203 ) 97 33 Foreign 751 95 (135 ) Foreign – U.S. Tax Reform (804 ) — — (256 ) 192 (102 ) Income Tax (Recovery)/Expense (107 ) 349 35 Geographic Components of Income/(Loss) before Income Taxes year ended December 31 2017 2016 2015 (millions of Canadian $) Canada (408 ) 304 (623 ) Foreign 3,645 618 (482 ) Income/(Loss) before Income Taxes 3,237 922 (1,105 ) Reconciliation of Income Tax (Recovery)/Expense year ended December 31 2017 2016 2015 (millions of Canadian $) Income/(loss) before income taxes 3,237 922 (1,105 ) Federal and provincial statutory tax rate 27 % 27 % 26 % Expected income tax expense/(recovery) 874 249 (287 ) U.S. Tax Reform (804 ) — — Foreign income tax rate differentials (81 ) (196 ) 14 Income from equity investments and non-controlling interests (64 ) (68 ) (56 ) Income tax differential related to regulated operations (42 ) 81 159 Non-taxable portion of capital gains (42 ) — — Asset impairment charges 1 34 242 170 Non-deductible amounts 4 18 — Tax rate and legislative changes — — 34 Other 14 23 1 Income Tax (Recovery)/Expense (107 ) 349 35 1 Net of nil (2016 – $112 million ; 2015 – $311 million ) attributed to higher foreign tax rates. Deferred Income Tax Assets and Liabilities at December 31 2017 2016 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,365 2,049 Difference in accounting and tax bases of impaired assets and assets held for sale 651 1,168 Regulatory and other deferred amounts 512 277 Unrealized foreign exchange losses on long-term debt 216 446 Financial instruments 10 34 Other 180 287 2,934 4,261 Less: valuation allowance 832 1,336 2,102 2,925 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 6,240 9,015 Equity investments 632 905 Taxes on future revenue requirement 238 198 Other 140 156 7,250 10,274 Net Deferred Income Tax Liabilities 5,148 7,349 The above deferred tax amounts have been classified in the Consolidated balance sheet as follows: at December 31 2017 2016 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 12) 255 313 Deferred Income Tax Liabilities Deferred income tax liabilities 5,403 7,662 Net Deferred Income Tax Liabilities 5,148 7,349 At December 31, 2017 , the Company has recognized the benefit of unused non-capital loss carryforwards of $1,231 million ( 2016 – $1,736 million ) for federal and provincial purposes in Canada, which expire from 2030 to 2037. The Company has no t recognized the benefit of capital loss carry forwards of $668 million (2016 – $654 million ) for federal and provincial purposes in Canada. The Company also has Ontario minimum tax credits of $82 million (2016 – $68 million ), which expire from 2026 to 2037. At December 31, 2017 , the Company has recognized the benefit of unused net operating loss carryforwards of US$1,800 million ( 2016 – US$2,545 million ) for federal purposes in the U.S., which expire from 2028 to 2037. The Company has no t recognized the benefit of unused net operating loss carryforwards of US$710 million (2016 – US$58 million ) for federal purposes in the U.S. The Company also has alternative minimum tax credits of US$56 million (2016 – US$37 million ). At December 31, 2017 , the Company has recognized the benefit of unused net operating loss carryforwards of US$7 million (2016 – US$54 million ) in Mexico, which expire from 2024 to 2027. Unremitted Earnings of Foreign Investments Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2017 by approximately $569 million ( 2016 – $481 million ) if there had been a provision for these taxes. Income Tax Payments Income tax payments of $247 million , net of refunds, were made in 2017 ( 2016 – payments, net of refunds, of $105 million ; 2015 – payments, net of refunds, of $164 million ). Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2017 2016 2015 (millions of Canadian $) Unrecognized tax benefit at beginning of year 15 13 13 Gross increases – tax positions in prior years — 3 2 Gross decreases – tax positions in prior years (1 ) — (2 ) Gross increases – tax positions in current year 2 2 1 Settlement — (1 ) — Lapse of statutes of limitations (3 ) (2 ) (1 ) Unrecognized Tax Benefit at End of Year 13 15 13 Subject to the results of audit examinations by taxing authorities and other legislative amendments, TCPL does not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on its financial statements. TCPL and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2009. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2010. TCPL's practice is to recognize interest and penalties related to income tax uncertainties in income tax expense. Income tax expense for the year ended December 31, 2017 reflects nil of interest expense and nil for penalties ( 2016 – nil of interest expense and nil for penalties; 2015 – $ 1 million reversal of interest expense and nil for penalties). At December 31, 2017 , the Company had $ 4 million accrued for interest expense and nil accrued for penalties ( December 31, 2016 – $ 4 million accrued for interest expense and nil accrued for penalties). |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT 2017 2016 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Debentures Canadian 2018 to 2020 500 10.8 % 600 10.7 % U.S. (2017 and 2016 – US$400) 2021 501 9.9 % 537 9.9 % Medium Term Notes Canadian 2019 to 2047 6,504 4.9 % 5,804 4.6 % Senior Unsecured Notes U.S. (2017 – US$14,892; 2016 – US$14,642) 2018 to 2045 18,644 5.1 % 19,660 5.1 % Acquisition Bridge Facility (2017 – nil; 2016 – US$2,013) — — — 2,702 1.9 % 26,149 29,303 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2017 and 2016 – US$200) 2023 250 7.9 % 269 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2017 and 2016 – US$33) 2026 41 7.5 % 44 7.5 % 895 917 TRANSCANADA PIPELINE USA LTD. Acquisition Bridge Facility (2017 – nil; 2016 – US$1,700) — — — 2,283 1.9 % COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2017 and 2016 – US$2,750) 2 2018 to 2045 3,443 4.0 % 3,692 4.0 % TC PIPELINES, LP Unsecured Loan Facility U.S. (2017 – US$185; 2016 – US$160) 2021 232 2.7 % 215 1.9 % Unsecured Term Loan U.S. (2017 and 2016 – US$670) 3 2020 to 2022 839 2.7 % 899 1.9 % Senior Unsecured Notes U.S. (2017 – US$1,200; 2016 – US$700) 2021 to 2027 1,502 4.4 % 940 4.7 % 2,573 2,054 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2017 and 2016 – US$672) 2021 to 2026 842 7.2 % 903 7.2 % GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2017 – US$55; 2016 – US$65) 2019 69 1.1 % 87 1.6 % Senior Unsecured Notes U.S. (2017 and 2016 – US$250) 2020 to 2035 313 5.6 % 336 5.6 % 382 423 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2017 – US$259; 2016 – US$278) 2018 to 2030 324 7.7 % 373 7.7 % 2017 2016 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Secured Notes 4 U.S. (2017 – US$30; 2016 – US$53) 2018 38 6.0 % 71 6.0 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2017 – US$25; 2016 – US$10) 2020 31 1.1 % 13 1.9 % Senior Secured Notes U.S. (2017 – nil; 2016 – US$12) — — — 16 4.0 % 31 29 34,677 40,048 Current portion of long-term debt (2,866 ) (1,838 ) Unamortized debt discount and issue costs (174 ) (191 ) Fair value adjustments 5 238 293 31,875 38,312 1 Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates. 2 Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia’s obligations is required to comply with covenants under the debt indenture and in the event of default, the guarantors would be obligated to pay the principal and related interest. 3 The US$170 million and US$500 million term loan facilities were amended in September 2017 to extend the maturity dates from 2018 to 2020 and 2022, respectively. 4 These notes are secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements. 5 The fair value adjustments include $242 million (2016 – $293 million ) related to the acquisition of Columbia. Refer to Note 5, Acquisition of Columbia, for further information. The fair value adjustments also include a decrease of $4 million (2016 – nil ) related to hedged interest rate risk. Refer to Note 23, Risk management and financial instruments, for further information. Principal Repayments At December 31, 2017, principal repayments for the next five years on the Company's Long-term debt are approximately as follows: (millions of Canadian $) 2018 2019 2020 2021 2022 Principal repayments on long-term debt 2,866 3,189 2,834 2,085 1,929 Long-Term Debt Issued The Company issued long-term debt over the three years ended December 31, 2017 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED November 2017 Senior Unsecured Notes November 2019 US 550 Floating November 2017 Senior Unsecured Notes November 2019 US 700 2.125 % September 2017 Medium Term Notes March 2028 300 3.39 % September 2017 Medium Term Notes September 2047 700 4.33 % June 2016 Acquisition Bridge Facility 1 June 2018 US 5,213 Floating June 2016 Medium Term Notes July 2023 300 3.69 % 2 June 2016 Medium Term Notes June 2046 700 4.35 % January 2016 Senior Unsecured Notes January 2026 US 850 4.875 % January 2016 Senior Unsecured Notes January 2019 US 400 3.125 % November 2015 Senior Unsecured Notes November 2017 US 1,000 1.625 % October 2015 Medium Term Notes November 2041 400 4.55 % July 2015 Medium Term Notes July 2025 750 3.30 % March 2015 Senior Unsecured Notes March 2045 US 750 4.60 % January 2015 Senior Unsecured Notes January 2018 US 500 1.875 % January 2015 Senior Unsecured Notes January 2018 US 250 Floating TUSCARORA GAS TRANSMISSION COMPANY August 2017 Term Loan August 2020 US 25 Floating April 2016 Term Loan April 2019 US 10 Floating TC PIPELINES, LP May 2017 Senior Unsecured Notes May 2027 US 500 3.90 % September 2015 Unsecured Term Loan October 2018 US 170 Floating March 2015 Senior Unsecured Notes March 2025 US 350 4.375 % TRANSCANADA PIPELINE USA LTD. June 2016 Acquisition Bridge Facility 1 June 2018 US 1,700 Floating ANR PIPELINE COMPANY June 2016 Senior Unsecured Notes June 2026 US 240 4.14 % GAS TRANSMISSION NORTHWEST LLC June 2015 Unsecured Term Loan June 2019 US 75 Floating 1 These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the issuance of common shares in fourth quarter 2016 and proceeds from the sale of the U.S. Northeast power assets were used to fully retire the remaining acquisition bridge facilities in the second quarter 2017. 2 Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent . Long-Term Debt Retired The Company retired/repaid long-term debt over the three years ended December 31, 2017 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED December 2017 Debentures 100 9.80 % November 2017 Senior Unsecured Notes US 1,000 1.625 % June 2017 Acquisition Bridge Facility 1 US 1,513 Floating February 2017 Acquisition Bridge Facility 1 US 500 Floating January 2017 Medium Term Notes 300 5.10 % November 2016 Acquisition Bridge Facility 1 US 3,200 Floating October 2016 Medium Term Notes 400 4.65 % June 2016 Senior Unsecured Notes US 84 7.69 % June 2016 Senior Unsecured Notes US 500 Floating January 2016 Senior Unsecured Notes US 750 0.75 % August 2015 Debentures 150 11.90 % June 2015 Senior Unsecured Notes US 500 3.40 % March 2015 Senior Unsecured Notes US 500 0.875 % January 2015 Senior Unsecured Notes US 300 4.875 % TUSCARORA GAS TRANSMISSION COMPANY August 2017 Senior Secured Notes US 12 3.82 % TRANSCANADA PIPELINE USA LTD. June 2017 Acquisition Bridge Facility 1 US 630 Floating April 2017 Acquisition Bridge Facility 1 US 1,070 Floating NOVA GAS TRANSMISSION LTD. February 2016 Debentures 225 12.20 % GAS TRANSMISSION NORTHWEST LLC June 2015 Senior Unsecured Notes US 75 5.09 % 1 These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the issuance of common shares in fourth quarter 2016 and proceeds from the sale of the U.S. Northeast power assets were used to fully retire the remaining acquisition bridge facilities in the second quarter 2017. Interest Expense Interest expense in the three years ended December 31 was as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) Interest on long-term debt 1,794 1,765 1,487 Interest on junior subordinated notes 348 180 116 Interest on short-term debt 101 56 44 Capitalized interest (173 ) (176 ) (280 ) Amortization and other financial charges 1 67 102 31 2,137 1,927 1,398 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 $ 2,055 million in 2017 ( 2016 – $ 1,757 million ; 2015 – $ 1,295 million ) on long-term debt, junior subordinated notes and notes payable, net of interest capitalized. |
JUNIOR SUBORDINATED NOTES
JUNIOR SUBORDINATED NOTES | 12 Months Ended |
Dec. 31, 2017 | |
Junior Subordinated Notes [Abstract] | |
JUNIOR SUBORDINATED NOTES | JUNIOR SUBORDINATED NOTES 2017 2016 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED U.S.$1,000 notes issued 2007 1 2067 1,252 5.0 % 3 1,343 6.4 % U.S.$750 notes issued 2015 1,2 2075 939 5.9 % 1,007 5.5 % U.S.$1,200 notes issued 2016 1,2 2076 1,502 6.6 % 1,611 6.2 % U.S.$1,500 notes issued 2017 1, 2 2077 1,878 5.6 % — — $1,500 notes issued 2017 1, 2 2077 1,500 5.1 % — — 7,071 3,961 Unamortized debt discount and issue costs (64 ) (30 ) 7,007 3,931 1 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 2 The Junior subordinated notes were issued to TransCanada Trust, a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TCPL's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. 3 In May 2017, Junior subordinated notes of US $1 billion converted from fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three month LIBOR plus 2.21 per cent . In March 2017, TransCanada Trust (the Trust) issued US$ 1.5 billion of Trust Notes – Series 2017-A to third party investors with a fixed interest rate of 5.30 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$ 1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 5.55 per cent , including a 0.25 per cent administration charge. The rate will reset commencing March 2027 until March 2047 to the then three month LIBOR plus 3.458 per cent per annum; from March 2047 until March 2077, the interest rate will reset to the then three month LIBOR plus 4.208 per cent per annum. The junior subordinated notes are redeemable at TCPL's option at any time on or after March 15, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. In May 2017, the Trust issued $ 1.5 billion of Trust Notes – Series 2017-B to third party investors with a fixed interest rate of 4.65 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for $ 1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 4.90 per cent , including a 0.25 per cent administration charge. The rate will reset commencing May 2027 until May 2047 to the then three month Bankers' Acceptance rate plus 3.33 per cent per annum; from May 2047 until May 2077, the interest rate will reset to the then three month Bankers' Acceptance rate plus 4.08 per cent per annum. The junior subordinated notes are redeemable at TCPL's option at any time on or after May 18, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. In August 2016, the Trust issued US$1.2 billion of Trust Notes – Series 2016-A to third party investors at a fixed interest rate of 5.875 per cent for the first ten years , converting to a floating rate thereafter. All of the issuance proceeds of the Trust were loaned to TCPL for US$1.2 billion of junior subordinated notes of TCPL at an initial fixed rate of 6.125 per cent , including a 0.25 per cent administration charge. The rate will reset commencing August 2026 until August 2046 to the three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the three month LIBOR plus 5.64 per cent per annum. The junior subordinated notes are redeemable at TCPL's option at any time on or after August 15, 2026 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with any other outstanding first preferred shares of TCPL. |
NON-CONTROLLING INTERESTS
NON-CONTROLLING INTERESTS | 12 Months Ended |
Dec. 31, 2017 | |
Noncontrolling Interest [Abstract] | |
NON-CONTROLLING INTERESTS | NON-CONTROLLING INTERESTS The Company's Non-controlling interests included in the Consolidated balance sheet are as follows: at December 31 2017 2016 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,852 1,596 Non-controlling interest in Portland Natural Gas Transmission System — 130 1,852 1,726 The Company's Net income attributable to non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 220 215 (13 ) Non-controlling interest in Portland Natural Gas Transmission System 1 9 20 19 Non-controlling interest in Columbia Pipeline Partners LP 2 9 17 — 238 252 6 1 Non-controlling interest in 2017 for the period January 1 to May 31 when TCPL sold its remaining interest in PNGTS to TC PipeLines, LP. Refer to Note 25, Other acquisitions and dispositions for further information. 2 Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of CPPL. TC PipeLines, LP During 2017 , the non-controlling interest in TC PipeLines, LP increased from 73.2 per cent to 74.3 per cent due to periodic issuances of common units in TC PipeLines, LP to third parties under an at-the-market issuance program (ATM program). In 2016 , the non-controlling interest in TC PipeLines, LP ranged between 72.0 per cent and 73.2 per cent and, in 2015 , between 71.7 per cent and 72.0 per cent . In December 2015, TC PipeLines, LP recorded an impairment charge of US$199 million related to its equity investment in Great Lakes. The non-controlling interest's share of this charge was US$143 million and was included in the Net income attributable to non-controlling interests in 2015 . Portland Natural Gas Transmission System On June 1, 2017, TCPL sold its remaining 11.81 per cent directly held interest in Portland Natural Gas Transmission System (PNGTS) to TC PipeLines, LP and, as a result, at December 31, 2017 , non-controlling interest in PNGTS was nil . The non-controlling interest in PNGTS as at December 31, 2016 represented the 38.3 per cent interest held by third parties. On January 1, 2016, TCPL sold 49.9 per cent of PNGTS to TC PipeLines, LP. Refer to Note 25, Other acquisitions and dispositions for further information. In 2017 , TCPL received fees of $ 5 million from TC PipeLines, LP ( 2016 – $5 million and 2015 – $4 million ) and $ 4 million from PNGTS prior to June 1, 2017 ( 2016 – $ 10 million ; 2015 – $11 million ) for services provided . Columbia Pipeline Partners LP On July 1, 2016 , TCPL acquired Columbia, which included a 53.5 per cent non-controlling interest in CPPL. On February 17, 2017, TCPL acquired all outstanding publicly held common units of CPPL at a price of US $17.00 and a stub period distribution payment of US $0.10 per common unit for an aggregate transaction value of US $921 million . As this was a transaction between entities under common control, it was recognized in equity. At December 31, 2016 , the entire $1,073 million ( US$799 million ) of TCPL's non-controlling interest in CPPL was recorded as Common units subject to rescission or redemption on the Consolidated balance sheet. The Company classified this non-controlling interest outside of equity as the potential redemption rights of the units were not within the control of the Company. Common Units of TC PipeLines, LP Subject to Rescission In connection with a late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the TC PipeLines, LP ATM program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to TC PipeLines, LP within one year of purchase. As a result, at December 31, 2016 , $106 million ( US$82 million ) was recorded as Common units subject to rescission or redemption on the Consolidated balance sheet. The Company classified these 1.6 million common units outside equity because the potential rescission rights of the units were not within the control of the Company. At December 31, 2017 , all rescission rights previously classified outside of equity have lapsed and been reclassified to equity. These rights expired one year from the date of purchase of each unit and no unitholder claimed or attempted to exercise any of these rescission rights while they remained outstanding. |
COMMON SHARES
COMMON SHARES | 12 Months Ended |
Dec. 31, 2017 | |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |
COMMON SHARES | COMMON SHARES Number of Shares Amount (thousands) (millions of Canadian $) Outstanding at January 1, 2015 779,479 16,320 Issuance of common shares for cash — — Outstanding at December 31, 2015 779,479 16,320 Issuance of common shares for cash 1 79,656 4,661 Outstanding at December 31, 2016 859,135 20,981 Issuance of common shares for cash 12,499 780 Outstanding at December 31, 2017 871,634 21,761 1 Proceeds of $2.5 billion were used to finance the acquisition of Columbia and proceeds of $2.0 billion were used to repay a portion of the US$6.9 billion acquisition bridge facilities. Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares without par value. TCPL issued the following common shares to TransCanada during 2017: • 3.0 million on January 31, 2017 for proceeds of $187 million • 3.4 million on April 28, 2017 for proceeds of $214 million • 3.0 million on July 31, 2017 for proceeds of $190 million • 3.1 million on October 31, 2017 for proceeds of $189 million . Restrictions on Dividends Certain terms of the Company's debt instruments can limit the amount of dividends the Company can pay on common shares. At December 31, 2017 these terms limit the Company from paying dividends in excess of $14.6 billion (2016 – $9.7 billion ; 2015 – $4.1 billion ). Under the agreements, TCPL can adjust this limit throughout the year if required, at its sole discretion, without incurring significant costs. Stock Options TransCanada's Stock Option Plan permits options for the purchase of TransCanada common shares to be awarded to certain employees, including officers. The contractual life of options granted is seven years. Options may be exercised at a price determined at the time the option is awarded and vest on the anniversary date in each of the three years following the award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation or termination of the option holder's employment. TransCanada used a binomial model for determining the fair value of options granted applying the following weighted average assumptions: year ended December 31 2017 2016 2015 Weighted average fair value $7.22 $5.67 $6.45 Expected life (years) 5.7 5.8 5.8 Interest rate 1.2 % 0.7 % 1.1 % Volatility 1 18 % 21 % 18 % Dividend yield 3.6 % 4.9 % 3.7 % Forfeiture rate 2 — 5 % 5 % 1 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. 2 On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance. Refer to Note 3, Accounting changes, for further information. The amount expensed for TransCanada stock options, with a corresponding increase in Additional paid-in capital, was $12 million in 2017 ( 2016 – $15 million ; 2015 – $13 million ). At December 31, 2017 , unrecognized compensation costs related to non-vested stock options was $15 million . The cost is expected to be fully recognized over a three -year period. The following table summarizes additional stock option information: year ended December 31 2017 2016 2015 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 28 31 10 Fair value of options that have vested 140 126 91 Total options vested 2.3 million 2.1 million 2.0 million As at December 31, 2017 , the aggregate intrinsic value of the total options exercisable was $83 million and the total intrinsic value of options outstanding was $110 million . |
OTHER COMPREHENSIVE (LOSS)_INCO
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS | OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS Components of Other comprehensive (loss)/income, including the portion attributable to non-controlling interests and related tax effects, are as follows: year ended December 31, 2017 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation losses on net investment in foreign operations (746 ) (3 ) (749 ) Reclassification of foreign currency translation gains on net investment on disposal of foreign operations (77 ) — (77 ) Change in fair value of net investment hedges — — — Change in fair value of cash flow hedges 3 — 3 Reclassification to net income of gains and losses on cash flow hedges (3 ) 1 (2 ) Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (14 ) 3 (11 ) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 21 (5 ) 16 Other comprehensive loss on equity investments (141 ) 35 (106 ) Other Comprehensive Loss (957 ) 31 (926 ) year ended December 31, 2016 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 3 — 3 Change in fair value of net investment hedges (14 ) 4 (10 ) Change in fair value of cash flow hedges 44 (14 ) 30 Reclassification to net income of gains and losses on cash flow hedges 71 (29 ) 42 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (38 ) 12 (26 ) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 22 (6 ) 16 Other comprehensive loss on equity investments (117 ) 30 (87 ) Other Comprehensive Loss (29 ) (3 ) (32 ) year ended December 31, 2015 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 798 15 813 Change in fair value of net investment hedges (505 ) 133 (372 ) Change in fair value of cash flow hedges (92 ) 35 (57 ) Reclassification to net income of gains and losses on cash flow hedges 144 (56 ) 88 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 74 (23 ) 51 Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 41 (9 ) 32 Other comprehensive income on equity investments 62 (15 ) 47 Other Comprehensive Income 522 80 602 The changes in AOCI by component are as follows: Currency Translation Adjustments Cash Flow Hedges Pension and Other Post-Retirement Benefit Plan Adjustments Equity Investments Total 1 AOCI balance at January 1, 2015 (518 ) (128 ) (281 ) (308 ) (1,235 ) Other comprehensive income/(loss) before reclassifications 2 135 (57 ) 51 33 162 Amounts reclassified from AOCI — 88 32 14 134 Net current period other comprehensive income 135 31 83 47 296 AOCI balance at December 31, 2015 (383 ) (97 ) (198 ) (261 ) (939 ) Other comprehensive income/(loss) before reclassifications 2 7 27 (26 ) (101 ) (93 ) Amounts reclassified from AOCI — 42 16 14 72 Net current period other comprehensive income/(loss) 7 69 (10 ) (87 ) (21 ) AOCI balance at December 31, 2016 (376 ) (28 ) (208 ) (348 ) (960 ) Other comprehensive (loss)/income before reclassifications 2,3 (590 ) (1 ) (11 ) (117 ) (719 ) Amounts reclassified from AOCI 4 (77 ) (2 ) 16 11 (52 ) Net current period other comprehensive (loss)/income (667 ) (3 ) 5 (106 ) (771 ) AOCI balance at December 31, 2017 (1,043 ) (31 ) (203 ) (454 ) (1,731 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 In 2017 , other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $159 million ( 2016 – $14 million losses; 2015 – $306 million gains) and gains of $4 million ( 2016 – $3 million gains and 2015 – nil ), respectively. 3 Other comprehensive (loss)/income before reclassification on pension and other post-retirement benefit plan adjustments includes a $27 million reduction on settlements and curtailments. 4 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $19 million ( $14 million , net of tax) at December 31, 2017 . These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. Details about reclassifications out of AOCI into the Consolidated statement of income are as follows: Amounts Reclassified 1 Affected Line Item year ended December 31 2017 2016 2015 (millions of Canadian $) Cash flow hedges Commodities 20 (57 ) (128 ) Revenues (Energy) Interest (17 ) (14 ) (16 ) Interest expense 3 (71 ) (144 ) Total before tax (1 ) 29 56 Income tax (recovery)/expense 2 (42 ) (88 ) Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial loss and past service cost (15 ) (22 ) (41 ) Plant operating costs and other 2 Settlement charge (2 ) — — Plant operating costs and other 2 (17 ) (22 ) (41 ) Total before tax 5 6 9 Income tax (recovery)/expense (12 ) (16 ) (32 ) Net of tax Equity investments Equity income (15 ) (19 ) (19 ) Income from equity investments 4 5 5 Income tax (recovery)/expense (11 ) (14 ) (14 ) Net of tax Currency translation adjustments Realization of foreign currency translation gains on disposal of foreign operations 77 — — Gain/(loss) on sale of assets held for sale/sold — — — Income tax (recovery)/expense 77 — — Net of tax 1 All amounts in parentheses indicate expenses to the Consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost. Refer to Note 22, Employee post-retirement benefits for further information. |
EMPLOYEE POST-RETIREMENT BENEFI
EMPLOYEE POST-RETIREMENT BENEFITS | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
EMPLOYEE POST-RETIREMENT BENEFITS | EMPLOYEE POST-RETIREMENT BENEFITS The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining service life of employees, which is approximately nine years at December 31, 2017 ( 2016 and 2015 – nine years ). Effective April 1, 2017, the Company closed its U.S. DB plan to non-union new entrants. As of April 1, 2017, all non-union hires participate in the existing DC plan. Non-union U.S. employees who participated in the DC plan, had one final election opportunity to become a member of the U.S. DB plan as of January 1, 2018. On December 31, 2017 , the Columbia DB Plan merged with TCPL's U.S. DB Plan. Members accruing benefits in the Columbia DB Plan as of December 31, 2017 were provided an option to either continue receiving benefits in the Columbia DB Plan or instead participate in the existing DC plan. This election was effective December 31, 2017 . The Company also provides its employees with a savings plan in Canada, DC Plans consisting of 401(k) Plans in the U.S., and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining service life of employees, which was approximately 12 years at December 31, 2017 ( 2016 and 2015 – 12 years ). In 2017 , the Company expensed $42 million ( 2016 – $52 million ; 2015 – $41 million ) for the savings and DC Plans. Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) DB Plans 163 111 96 Other post-retirement benefit plans 7 8 6 Savings and DC Plans 42 52 41 212 171 143 Current Canadian pension legislation allows for partial funding of solvency requirements over a number of years through letters of credit in lieu of cash contributions, up to certain limits. As such, in addition to the cash contributions noted above, the Company provided a $27 million letter of credit to the Canadian DB Plan in 2017 ( 2016 – $20 million ; 2015 – $33 million ), resulting in a total of $260 million provided to the Canadian DB Plan under letters of credit at December 31, 2017 . The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2017 and the next required valuation will be as at January 1, 2018. As a result of settlements and curtailments that occurred upon the completion of the U.S. Northeast power generation asset sales, interim remeasurements were performed in 2017 on TCPL's U.S. DB Plan and other post-retirement benefit plans using a weighted average discount rate of 4.10 per cent . All other assumptions were consistent with those employed at December 31, 2016. The impact of these remeasurements reduced the U.S. DB Plan's unrealized actuarial losses by $3 million , which was included in Other comprehensive income, and resulted in a settlement charge of $2 million which was recorded in net benefit cost in 2017. These remeasurements had no impact on the other post-retirement benefit plan's unrealized actuarial losses. In 2017, lump sum payouts exceeded service and interest costs for the Columbia DB Plan. As a result, an interim remeasurement was performed on the Columbia DB Plan at September 30, 2017 using a discount rate of 3.70 per cent . All other assumptions were consistent with those employed at December 31, 2016. The interim remeasurement of the Columbia DB Plan increased the Company’s unrealized actuarial gains by $16 million , of which $14 million was recorded in Regulatory assets and $2 million was recorded in Other comprehensive income. The Company's funded status at December 31 is comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,456 2,780 372 225 Service cost 113 107 4 3 Interest cost 135 127 14 13 Employee contributions 5 4 3 2 Benefits paid (166 ) (204 ) (19 ) (16 ) Actuarial loss/(gain) 253 111 19 (8 ) Acquisition of Columbia — 527 — 151 Curtailment (14 ) — (2 ) — Settlement (66 ) 2 — — Foreign exchange rate changes (70 ) 2 (16 ) 2 Benefit obligation – end of year 3,646 3,456 375 372 Change in Plan Assets Plan assets at fair value – beginning of year 3,208 2,591 354 45 Actual return on plan assets 358 227 45 14 Employer contributions 2 163 111 7 8 Employee contributions 5 4 3 2 Benefits paid (166 ) (204 ) (19 ) (16 ) Acquisition of Columbia — 475 — 294 Settlement (57 ) — — — Foreign exchange rate changes (60 ) 4 (25 ) 7 Plan assets at fair value – end of year 3,451 3,208 365 354 Funded Status – Plan Deficit (195 ) (248 ) (10 ) (18 ) 1 The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation. 2 Excludes $260 million in letters of credit provided to the Canadian DB Plan for funding purposes ( 2016 – $233 million ). The amounts recognized in the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans are as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Intangible and other assets (Note 12) — — 193 189 Accounts payable and other (1 ) — (8 ) (7 ) Other long-term liabilities (Note 15) (194 ) (248 ) (195 ) (200 ) (195 ) (248 ) (10 ) (18 ) Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Projected benefit obligation 1 (3,646 ) (3,456 ) (203 ) (207 ) Plan assets at fair value 3,451 3,208 — — Funded Status – Plan Deficit (195 ) (248 ) (203 ) (207 ) 1 The projected benefit obligation for the pension benefit plan differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels. The funded status based on the accumulated benefit obligation for all DB Plans is as follows: at December 31 2017 2016 (millions of Canadian $) Accumulated benefit obligation (3,372 ) (3,202 ) Plan assets at fair value 3,451 3,208 Funded Status – Plan Surplus 79 6 Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded. at December 31 2017 2016 (millions of Canadian $) Accumulated benefit obligation (944 ) (990 ) Plan assets at fair value 925 868 Funded Status – Plan Deficit (19 ) (122 ) The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: Percentage of Target Allocations at December 31 2017 2016 2017 Debt securities 30 % 31 % 25% to 40% Equity securities 64 % 63 % 45% to 75% Alternatives 6 % 6 % 5% to 15% 100 % 100 % Debt and equity securities include the Company's debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2017 2016 2017 2016 Debt securities 7 9 0.2 % 0.2 % Equity securities 3 4 0.1 % 0.1 % Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities, as well as alternative assets such as infrastructure, private equity, real estate and derivatives to diversify risk. Derivatives are not used for speculative purposes and the use of leveraged derivatives is prohibited. All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted basis and by comparison to similar assets which are publicly traded. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets that the Company has the ability to access at the measurement date. In Level II, the fair value of assets is determined using valuation techniques, such as option pricing models and extrapolation using significant inputs, which are observable directly or indirectly. In Level III, the fair value of assets is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. For further information on the fair value hierarchy, refer to Note 23, Risk management and financial instruments. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 Asset Category Cash and Cash Equivalents 44 22 17 12 — — 61 34 2 1 Equity Securities: Canadian 410 388 151 143 — — 561 531 15 15 U.S. 543 504 354 476 — — 897 980 24 27 International 45 39 322 327 — — 367 366 10 10 Global — — 301 235 — — 301 235 8 7 Emerging 8 7 147 137 — — 155 144 4 4 Fixed Income Securities: Canadian Bonds: Federal — — 193 192 — — 193 192 5 5 Provincial — — 194 179 — — 194 179 5 5 Municipal — — 8 8 — — 8 8 — — Corporate — — 122 126 — — 122 126 3 4 U.S. Bonds: Federal — — 244 82 — — 244 82 6 2 State — — 41 41 — — 41 41 1 1 Municipal — — 4 39 — — 4 39 — 1 Corporate — — 234 188 — — 234 188 6 5 International: Government — — 4 6 — — 4 6 — — Corporate — — 5 21 — — 5 21 — 1 Mortgage backed — — 73 62 — — 73 62 2 2 Other Investments: Real estate — — — — 140 133 140 133 4 4 Infrastructure — — — — 70 58 70 58 2 2 Private equity funds — — — — 6 8 6 8 — — Funds held on deposit 136 129 — — — — 136 129 3 4 1,186 1,089 2,414 2,274 216 199 3,816 3,562 100 100 The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2015 14 Purchases and sales 183 Realized and unrealized gains 2 Balance at December 31, 2016 199 Purchases and sales 11 Realized and unrealized gains 6 Balance at December 31, 2017 216 The Company's expected funding contributions in 2018 are approximately $98 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $45 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $27 million letter of credit to the Canadian DB Plan for the funding of solvency requirements. The following are estimated future benefit payments, which reflect expected future service: (millions of Canadian $) Pension Benefits Other Post- Retirement Benefits 2018 181 19 2019 187 20 2020 190 20 2021 196 20 2022 200 20 2023 to 2027 1,054 98 The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of corporate AA bond yields at December 31, 2017 . This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate. The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows: Pension Other Post-Retirement at December 31 2017 2016 2017 2016 Discount rate 3.60 % 4.00 % 3.70 % 4.15 % Rate of compensation increase 3.00 % 1.20 % — — The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows: Pension Other Post-Retirement year ended December 31 2017 2016 2015 2017 2016 2015 Discount rate 3.95 % 4.20 % 4.15 % 4.15 % 4.30 % 4.20 % Expected long-term rate of return on plan assets 6.50 % 6.70 % 6.95 % 6.05 % 5.95 % 4.60 % Rate of compensation increase 1.20 % 0.80 % 3.15 % — — — The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan. A seven per cent weighted average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2024 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects: (millions of Canadian $) Increase Decrease Effect on total of service and interest cost components 1 (1 ) Effect on post-retirement benefit obligation 15 (13 ) The Company's net benefit cost recognized is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2015 2017 2016 2015 Service cost 108 107 108 4 3 3 Interest cost 122 127 115 14 13 10 Expected return on plan assets (178 ) (175 ) (155 ) (21 ) (11 ) (2 ) Amortization of actuarial loss 14 20 35 1 2 3 Amortization of past service cost — — 2 — — 1 Amortization of regulatory asset 37 27 23 1 1 1 Amortization of transitional obligation related to regulated business — — — — 2 2 Settlement charge – regulatory asset 2 — — — — — Settlement charge – AOCI 2 — — — — — Net Benefit Cost Recognized 107 106 128 (1 ) 10 18 Pre-tax amounts recognized in AOCI were as follows: 2017 2016 2015 at December 31 Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits (millions of Canadian $) Net loss 273 11 270 21 247 28 The estimated net loss for the DB Plans and for the other post-retirement benefit plans that will be amortized from AOCI into net periodic benefit cost in 2018 is $19 million and $1 million , respectively. Pre-tax amounts recognized in OCI were as follows: 2017 2016 2015 at December 31 Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits (millions of Canadian $) Amortization of net loss from AOCI to OCI (18 ) (1 ) (20 ) (2 ) (34 ) (4 ) Amortization of prior service costs from AOCI to OCI — — — — (2 ) (1 ) Curtailment (14 ) (2 ) — — — — Settlement (11 ) — — — — — Funded status adjustment 46 (7 ) 43 (5 ) (67 ) (7 ) 3 (10 ) 23 (7 ) (103 ) (12 ) |
RISK MANAGEMENT AND FINANCIAL I
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS | 12 Months Ended |
Dec. 31, 2017 | |
Risk Management and Financial Instruments [Abstract] | |
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS | RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TCPL has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings and cash flow. Risk management strategies, policies and limits are designed to ensure TCPL's risks and related exposures are in line with the Company's business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits ultimately established by the Company's Board of Directors, implemented by senior management and monitored by the Company's risk management and internal audit groups. The Board of Directors' Audit Committee oversees how management monitors compliance with market risk and counterparty credit risk management policies and procedures, and oversees management's review of the adequacy of the risk management framework. Market Risk The Company constructs and invests in energy infrastructure projects, purchases and sells commodities, issues short-term and long-term debt, including amounts in foreign currencies, and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings and the value of the financial instruments it holds. The Company assesses contracts used to manage market risk to determine whether all, or a portion, meets the definition of a derivative. Derivative contracts the Company uses to assist in managing the exposure to market risk may consist of the following: • Forwards and futures contracts – agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future • Swaps – agreements between two parties to exchange streams of payments over time according to specified terms • Options – agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. Power generation commodity price risk The Company is exposed to commodity price movements as part of its normal business operations. A number of strategies are used to manage these exposures, including the following: • committing a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to manage operational and price risks in its asset portfolio • purchasing a portion of the natural gas required to fuel certain of its power plants or entering into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin • meeting power sales commitments using power generation or fixed price purchase contracts, thereby reducing the Company's exposure to fluctuating commodity prices. In April and June 2017, the Company sold its U.S. Northeast power assets. In December 2017, TCPL entered into an agreement to sell its outstanding U.S. power retail contracts as part of the wind down of the U.S. power marketing operations. The sale of the U.S. power retail contracts is expected to close in the first quarter of 2018, subject to regulatory and other approvals. As a result of these sales, the exposure to commodity price risk has been reduced significantly. Natural gas storage commodity price risk TCPL manages its exposure to seasonal natural gas price spreads in its non-regulated natural gas storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TCPL simultaneously enters into forward purchase contracts of natural gas for injection into storage and offsetting forward sale contracts of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to natural gas price movements. Unrealized gains and losses on fair value adjustments recorded each period on these forward contracts are not necessarily representative of the amounts that will be realized on settlement. Liquids marketing commodity price risk The liquids marketing business began operations in 2016. TCPL enters into short-term or long-term liquids pipeline and storage terminal capacity contracts. TCPL fixes a portion of its exposure on these contracts by entering into derivative instruments to manage its variable price fluctuations that arise from physical liquids transactions. Foreign exchange and interest rate risk Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates. TCPL generates revenues and incurs expenses that are denominated in currencies other than Canadian dollars. As a result, the Company's earnings and cash flows are expected to fluctuate. A portion of TCPL’s business generates earnings in U.S. dollars, but since its financial results are reported in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect the Company’s net income. As the Company’s U.S. dollar-denominated operations continue to grow, exposure to changes in currency rates increases. The majority of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives. TCPL is exposed to interest rate risk resulting from financial instruments and contractual obligations containing variable interest rate components. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk. Net investment in foreign operations The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps and foreign exchange forward contracts and options. The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows: 2017 2016 at December 31 Fair 1 Notional or Fair 1 Notional or (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019) 2 (199 ) US 1,200 (425 ) US 2,350 U.S. dollar foreign exchange options (maturing 2018) 5 US 500 — — U.S. dollar foreign exchange forward contracts — — (7 ) US 150 (194 ) US 1,700 (432 ) US 2,500 1 Fair value equals carrying value. 2 In 2017 , Net income includes net realized gains of $4 million ( 2016 – gains of $6 million ) related to the interest component of cross-currency swap settlements which are reported within Interest expense. The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2017 2016 (millions of Canadian $, unless otherwise noted) Notional amount 25,400 (US 20,200) 26,600 (US 19,800) Fair value 28,900 (US 23,100) 29,400 (US 21,900) Counterparty Credit Risk Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the related contract or agreement with the Company. The Company manages its exposure to this potential loss by using recognized credit management techniques, including: • dealing with creditworthy counterparties – a significant amount of the Company’s credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties • setting limits on the amount TCPL can transact with any one counterparty – the Company monitors and manages the concentration of risk exposure with any one counterparty, and reduces the exposure when necessary and when it is allowed under the terms of the contracts • using contract netting arrangements and obtaining financial assurances such as guarantees, letters of credit or cash when deemed necessary. There is no guarantee that these techniques will protect the Company from material losses. TCPL's maximum counterparty credit exposure with respect to financial instruments at December 31, 2017 , without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets, derivative assets and loan receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2017 , there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the year. At December 31, 2016 , we had a credit risk concentration with one counterparty of $200 million ( US$149 million ). TCPL has significant credit and performance exposures to financial institutions as they hold cash deposits and provide committed credit lines and letters of credit that help manage the Company's exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. For TCPL's Canadian regulated natural gas pipeline assets, counterparty credit risk is managed through application of tariff provisions as approved by the NEB. Fair Value of Non-Derivative Financial Instruments The fair value of long-term debt and junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers. Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, due to affiliate, accrued interest and other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy. Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments. Balance Sheet Presentation of Non-Derivative Financial Instruments The following table details the fair value of non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy: 2017 2016 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Long-term debt, including current portion 1,2 (Note 17) (34,741 ) (40,180 ) (40,150 ) (45,047 ) Junior subordinated notes (Note 18) (7,007 ) (7,233 ) (3,931 ) (3,825 ) (41,748 ) (47,413 ) (44,081 ) (48,872 ) 1 Long-term debt is recorded at amortized cost, except for US$1.1 billion ( 2016 – US$850 million ) that is attributed to hedged risk and recorded at fair value. 2 Net income in 2017 included unrealized gains of $4 million ( 2016 – gains of $2 million ) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.1 billion of long-term debt at December 31, 2017 ( 2016 – US$850 million ). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. Available for Sale Assets Summary The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets: 2017 2016 LMCI Restricted Investments Other Restricted Investments 2 LMCI Restricted Investments Other Restricted Investments 2 (millions of Canadian $) Fair value 1 Fixed income securities (maturing within 1 year) — 23 — 19 Fixed income securities (maturing within 1-5 years) — 107 — 117 Fixed income securities (maturing within 5-10 years) 14 — 9 — Fixed income securities (maturing after 10 years) 790 — 513 — 804 130 522 136 1 Available for sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet. 2 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. 2017 2016 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized (losses)/gains in the year ended December 31 (3 ) 1 (28 ) (1 ) Net realized (losses)/gains in the year ended December 31 3 (1 ) — — — 1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. 2 Unrealized gains and losses on other restricted investments are included in OCI. 3 The realized gains or losses on the sale of LMCI restricted investment securities are determined using the average cost basis. Fair Value of Derivative Instruments The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using a market approach. The market approach bases the fair value measures on a comparable transaction using quoted market prices, or in the absence of quoted market prices, third-party broker quotes or other valuation techniques. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments. In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipeline exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered or refunded through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles. Balance Sheet Presentation of Derivative Instruments The balance sheet classification of the fair value of derivative instruments as at December 31, 2017 is as follows: at December 31, 2017 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 1 — — 249 250 Foreign exchange — — 8 70 78 Interest rate 3 — — 1 4 4 — 8 320 332 Intangible and other assets (Note 12) Commodities 2 — — — 69 69 Interest rate 4 — — — 4 4 — — 69 73 Total Derivative Assets 8 — 8 389 405 Accounts payable and other (Note 14) Commodities 2 (6 ) — — (208 ) (214 ) Foreign exchange — — (159 ) (10 ) (169 ) Interest rate — (4 ) — — (4 ) (6 ) (4 ) (159 ) (218 ) (387 ) Other long-term liabilities (Note 15) Commodities 2 (2 ) — — (26 ) (28 ) Foreign exchange — — (43 ) — (43 ) Interest rate — (1 ) — — (1 ) (2 ) (1 ) (43 ) (26 ) (72 ) Total Derivative Liabilities (8 ) (5 ) (202 ) (244 ) (459 ) Total Derivatives — (5 ) (194 ) 145 (54 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. The balance sheet classification of the fair value of derivative instruments as at December 31, 2016 is as follows: at December 31, 2016 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 6 — — 351 357 Foreign exchange — — 6 10 16 Interest rate 1 1 — 1 3 7 1 6 362 376 Intangible and other assets (Note 12) Commodities 2 4 — — 118 122 Foreign exchange — — 10 — 10 Interest rate 1 — — — 1 5 — 10 118 133 Total Derivative Assets 12 1 16 480 509 Accounts payable and other (Note 14) Commodities 2 — — — (330 ) (330 ) Foreign exchange — — (237 ) (38 ) (275 ) Interest rate (1 ) (1 ) — — (2 ) (1 ) (1 ) (237 ) (368 ) (607 ) Other long-term liabilities (Note 15) Commodities 2 — — — (118 ) (118 ) Foreign exchange — — (211 ) — (211 ) Interest rate — (1 ) — — (1 ) — (1 ) (211 ) (118 ) (330 ) Total Derivative Liabilities (1 ) (2 ) (448 ) (486 ) (937 ) Total Derivatives 11 (1 ) (432 ) (6 ) (428 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk. Notional and Maturity Summary The maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows: at December 31, 2017 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 66,132 133 6 — — Sales 1 42,836 135 7 — — Millions of U.S. dollars — — — US 2,931 US 2,300 Millions of Mexican pesos — — — MXN 100 — Maturity dates 2018-2022 2018-2021 2018 2018 2018-2022 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. at December 31, 2016 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 86,887 182 6 — — Sales 1 58,561 147 6 — — Millions of U.S. dollars — — — US 2,394 US 1,550 Maturity dates 2017-2021 2017-2020 2017 2017 2017-2019 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively . Unrealized and Realized Gains/(Losses) on Derivative Instruments The following summary does not include hedges of the net investment in foreign operations. year ended December 31 2017 2016 2015 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 2 62 123 (37 ) Foreign exchange 88 25 (21 ) Interest rate (1 ) — — Amount of realized (losses)/gains in the year Commodities (107 ) (204 ) (151 ) Foreign exchange 18 62 (112 ) Interest rate 1 — — Derivative instruments in hedging relationships Amount of realized gains/(losses) in the year Commodities 23 (167 ) (179 ) Foreign exchange 5 (101 ) — Interest rate 1 4 8 1 Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively. 2 In 2017 , there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur ( 2016 – net loss of $42 million ). Derivatives in cash flow hedging relationships The components of OCI (Note 21) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: year ended December 31 2017 2016 2015 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI (effective portion) 1 Commodities (1 ) 39 (92 ) Interest rate 4 5 — 3 44 (92 ) Reclassification of (losses)/gains on derivative instruments from AOCI to Net income (effective portion) 1 Commodities 2 (20 ) 57 128 Interest rate 3 17 14 16 (3 ) 71 144 1 No amounts have been excluded from the assessment of hedge effectiveness. In 2017 and 2016 , there were no gains or losses included in Net Income related to ineffective portions. Amounts in parentheses indicate losses recorded to OCI and AOCI. 2 Reported within Revenues on the Consolidated statement of income. 3 Reported within Interest expense on the Consolidated statement of income. Offsetting of derivative instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TCPL has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the Consolidated balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2017 : at December 31, 2017 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 319 (198 ) 121 Foreign exchange 78 (56 ) 22 Interest rate 8 (1 ) 7 405 (255 ) 150 Derivative – Liability Commodities (242 ) 198 (44 ) Foreign exchange (212 ) 56 (156 ) Interest rate (5 ) 1 (4 ) (459 ) 255 (204 ) 1 Amounts available for offset do not include cash collateral pledged or received. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2016 : at December 31, 2016 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 479 (362 ) 117 Foreign exchange 26 (26 ) — Interest rate 4 (1 ) 3 509 (389 ) 120 Derivative – Liability Commodities (448 ) 362 (86 ) Foreign exchange (486 ) 26 (460 ) Interest rate (3 ) 1 (2 ) (937 ) 389 (548 ) 1 Amounts available for offset do not include cash collateral pledged or received. With respect to the derivative instruments presented above as at December 31, 2017 , the Company had provided cash collateral of $165 million ( 2016 – $305 million ) and letters of credit of $30 million ( 2016 – $27 million ) to its counterparties. The Company held nil ( 2016 – nil ) in cash collateral and $3 million ( 2016 – $3 million ) in letters of credit from counterparties on asset exposures at December 31, 2017 . Credit risk related contingent features of derivative instruments Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at December 31, 2017 , the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $2 million ( 2016 – $19 million ), for which the Company has provided collateral in the normal course of business of nil ( 2016 – nil ). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2017 , the Company would have been required to provide additional collateral of $2 million ( 2016 – $19 million ) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise. Fair Value Hierarchy The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. Levels How fair value has been determined Level I Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis. Level II Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances. Level III Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category includes long-dated commodity transactions in certain markets where liquidity is low and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions. Valuation of options is based on the Black-Scholes pricing model. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which significant inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II. The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2017 , are categorized as follows: at December 31, 2017 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 21 283 15 319 Foreign exchange — 78 — 78 Interest rate — 8 — 8 Derivative Instrument Liabilities: Commodities (27 ) (193 ) (22 ) (242 ) Foreign exchange — (212 ) — (212 ) Interest rate — (5 ) — (5 ) (6 ) (41 ) (7 ) (54 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2017 . The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2016 , are categorized as follows: at December 31, 2016 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 134 326 19 479 Foreign exchange — 26 — 26 Interest rate — 4 — 4 Derivative Instrument Liabilities: Commodities (102 ) (343 ) (3 ) (448 ) Foreign exchange — (486 ) — (486 ) Interest rate — (3 ) — (3 ) 32 (476 ) 16 (428 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016 . The following table presents the net change in fair value of derivative assets and liabilities classified in Level III of the fair value hierarchy: (millions of Canadian $, pre-tax) 2017 2016 Balance at beginning of year 16 9 Transfers out of Level III (19 ) (1 ) Total (losses)/gains included in Net income (17 ) 13 Sales (5 ) (3 ) Settlements 18 (2 ) Balance at end of year 1 (7 ) 16 1 Revenues include unrealized losses attributed to derivatives in the Level III category that were still held at December 31, 2017 of $7 million ( 2016 — gains of $7 million ). A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million increase or decrease , respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2017 . |
CHANGES IN OPERATING WORKING CA
CHANGES IN OPERATING WORKING CAPITAL | 12 Months Ended |
Dec. 31, 2017 | |
CHANGES IN OPERATING WORKING CAPITAL | |
CHANGES IN OPERATING WORKING CAPITAL | CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2017 2016 2015 (millions of Canadian $) Increase in Accounts receivable (573 ) (487 ) (19 ) Increase in Inventories (38 ) (87 ) (3 ) Decrease/(increase) in Assets held for sale 14 (13 ) — Decrease/(increase) in Other current assets 189 328 (273 ) Increase/(decrease) in Accounts payable and other 149 432 (103 ) Increase in Accrued interest 12 62 91 (Decrease)/increase in Liabilities related to assets held for sale (25 ) 16 — (Increase)/decrease in Operating Working Capital (272 ) 251 (307 ) |
OTHER ACQUISITIONS AND DISPOSIT
OTHER ACQUISITIONS AND DISPOSITIONS | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
OTHER ACQUISITIONS AND DISPOSITIONS | OTHER ACQUISITIONS AND DISPOSITIONS U.S. Natural Gas Pipelines Iroquois Gas Transmission System and Portland Natural Gas Transmission System On June 1, 2017, TCPL closed the sale of 49.34 per cent of its 50 per cent interest in Iroquois, a long with an option to sell the remaining 0.66 per cent at a later date, to TC PipeLines, LP. At the same time, TCPL closed the sale of its remaining 11.81 per cent interest in PNGTS to TC PipeLines, LP. Proceeds from these transactions were US$765 million , before post-closing adjustments. Proceeds were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and PNGTS debt. In January 2016 , TCPL closed the sale of a 49.9 per cent interest in PNGTS to TC PipeLines, LP for an aggregate purchase price of US$223 million . Proceeds were comprised of US$188 million in cash and the assumption of US$35 million of a proportional share of PNGTS debt. In March 2016 , TCPL acquired a 4.87 per cent interest in Iroquois for an aggregate purchase price of US$54 million , increasing TCPL's interest in Iroquois to 49.35 per cent . On May 1, 2016 , the Company acquired an additional 0.65 per cent interest for an aggregate purchase price of US$7 million , further increasing TCPL's interest in Iroquois to 50 per cent . TC Offshore LLC In December 2015 , the Company entered into an agreement to sell TC Offshore LLC to a third party which resulted in a pre-tax loss on sale of $125 million in 2015. In March 2016 , the Company closed the sale which resulted in an additional loss of $4 million pre-tax. Losses from the sale were included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income. Gas Transmission Northwest LLC In April 2015 , TCPL completed the sale of its remaining 30 per cent interest in GTN to TC PipeLines, LP for an aggregate purchase price of US$457 million . Proceeds were comprised of US$264 million in cash, the assumption of US$98 million of a proportional share of GTN debt and US$95 million of new Class B units of TC PipeLines, LP. Energy Ontario Solar Assets On December 19, 2017, the Company completed the sale of its Ontario solar assets to a third party for proceeds of approximately $541 million , before post-closing adjustments. As a result, the Company recorded a gain on sale of approximately $127 million ( $136 million after tax) which is included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income. U.S. Northeast Power Assets On April 19, 2017 , the Company completed the sale of TC Hydro for proceeds of approximately US$1.07 billion , before post-closing adjustments. As a result, in 2017 the Company recorded a gain on sale of approximately $715 million ( $440 million after tax) including the impact of $5 million of foreign currency translation gains which were reclassified from AOCI to net income. On June 2, 2017 , TCPL completed the sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power for proceeds of approximately US$2.029 billion , before post-closing adjustments. In 2016, the Company recorded a loss of approximately $829 million ( $863 million after tax) which included the impact of $70 million of foreign currency translation gains that were reclassified from AOCI to net income on close. The Company recorded an additional loss on sale of $211 million ( $167 million after tax) in 2017 which included $2 million in foreign currency translation gains. This additional loss primarily related to adjustments to the purchase price and repair costs for an unplanned outage at Ravenswood prior to close of the sale. Gains and losses from these sales are included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income. The proceeds received from the sale of the U.S. Northeast Power assets were used to repay the outstanding balances on the Company's acquisition bridge facilities that partially funded the acquisition of Columbia. Ironwood In February 2016, TCPL acquired the Ironwood natural gas fired, combined cycle power plant for US$653 million in cash after post-closing adjustments. The evaluation of assigned fair value of acquired assets and liabilities did not result in the recognition of goodwill. The Company began consolidating Ironwood as of the date of acquisition which did not have a material impact on the Revenues and Net income of the Company. In addition, the pro forma incremental impact of Ironwood on the Company’s Revenues and Net income from the date of acquisition to the date of sale was not material. Bruce Power In December 2015, TCPL exercised its option to acquire an additional 14.89 per cent ownership interest in Bruce B from the Ontario Municipal Employees Retirement System for $236 million , increasing its ownership interest to 46.5 per cent . The difference between the purchase price and the underlying carrying value of Bruce B is primarily related to the estimated fair value of the amended agreement with Ontario's Independent Electricity System Operator to extend the oper ating life of the Bruce Power facility to 2064. In December 2015, Bruce A and Bruce B merged to form a single limited partnership, Bruce Power. This merger was accounted for as a transaction between entities under common control whereby the assets and liabilities of Bruce A and Bruce B were combined at their carrying values. Upon completion of the merger, TCPL applied equity method accounting to its resulting 48.5 per cent ownership interest in Bruce Power. Prior to the acquisition, TCPL applied equity method accounting to its 48.9 per cent ownership interest in Bruce A and its 31.6 per cent ownership interest in Bruce B. |
COMMITMENTS, CONTINGENCIES AND
COMMITMENTS, CONTINGENCIES AND GUARANTEES | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS, CONTINGENCIES AND GUARANTEES | COMMITMENTS, CONTINGENCIES AND GUARANTEES Commitments Operating leases Future annual payments under the Company's operating leases for various premises, services and equipment, net of sublease receipts, are approximately as follows: year ended December 31 Minimum Amounts Net (millions of Canadian $) 2018 75 4 71 2019 76 2 74 2020 73 2 71 2021 71 1 70 2022 63 — 63 2023 and thereafter 443 2 441 801 11 790 The operating lease agreements for premises, services and equipment expire at various dates through 2052, with an option to renew certain lease agreements for periods of one year to 25 years . Net rental expense on operating leases in 2017 was $93 million ( 2016 – $145 million ; 2015 – $131 million ). Other commitments TCPL and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business. Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts. At December 31, 2017 , TCPL was committed to approximately $0.3 billion of capital expenditures for its Canadian Natural Gas Pipelines, primarily related to construction costs associated with NGTL System natural gas pipeline projects. At December 31, 2017 , TCPL was committed to approximately $0.4 billion of capital expenditures for its U.S. Natural Gas Pipelines, primarily related to construction costs associated with Columbia Gas and Columbia Gulf growth projects. At December 31, 2017 , TCPL was committed to approximately $0.7 billion of capital expenditures for its Mexico Natural Gas Pipelines, primarily related to construction of the Sur de Texas and Villa de Reyes gas pipeline projects. At December 31, 2017 , the Company was committed to approximately $0.1 billion of capital expenditures for its Liquids Pipelines, primarily related to capital projects on operating pipelines. At December 31, 2017 , the Company was committed to approximately $0.4 billion of capital expenditures for its Energy business, primarily related to construction costs of the Napanee Generating Station. At December 31, 2017 , the Company was committed to approximately $0.1 billion of Corporate expenditures related to various information technology services agreements. Contingencies TCPL is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2017 , the Company had accrued approximately $34 million ( 2016 – $39 million ) related to operating facilities, which represents the present value of the estimated future amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue. TCPL and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. The amounts involved in such proceedings are not reasonably estimable as the final outcome of such legal proceedings cannot be predicted with certainty. It is the opinion of management that the ultimate resolution of such proceedings and actions, will not have a material impact on the Company's consolidated financial position or results of operations. In March 2017, the U.S. Department of State issued a U.S. Presidential Permit authorizing construction of the U.S./Canada border crossing facilities of the Keystone XL pipeline. TCPL discontinued its claim under Chapter 11 of the North American Free Trade Agreement and has also withdrawn the U.S. Constitutional challenge that was filed in June 2016 and arose from the November 2015 denial of our Presidential Permit application to construct the Keystone XL pipeline. Guarantees TCPL and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the obligations for construction services during the construction of the pipeline. TCPL and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, construction services and the payment of liabilities. For certain of these entities, any payments made by TCPL under these guarantees in excess of its ownership interest are to be reimbursed by its partners. The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees is as follows: 2017 2016 year ended December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas ranging to 2020 315 2 805 53 Bruce Power ranging to 2018 88 1 88 1 Other jointly owned entities ranging to 2059 104 13 87 28 507 16 980 82 1 TCPL's share of the potential estimated current or contingent exposure. |
CORPORATE RESTRUCTURING COSTS
CORPORATE RESTRUCTURING COSTS | 12 Months Ended |
Dec. 31, 2017 | |
Restructuring and Related Activities [Abstract] | |
CORPORATE RESTRUCTURING COSTS | CORPORATE RESTRUCTURING COSTS In mid-2015, the Company commenced a business restructuring and transformation initiative to reduce overall costs and maximize the effectiveness and efficiency of its existing operations. Restructuring costs consist primarily of severance and expected future losses under lease commitments. In 2015, the Company incurred $122 million before tax of corporate restructuring costs and recorded a provision of $87 million before tax related to planned severance costs in 2016 and 2017 and expected future losses under lease commitments. Of the total corporate restructuring charges of $209 million pre-tax, $157 million was recorded in Plant operating costs and other which was partially offset by $58 million that was recorded in Revenues in the Consolidated statement of income related to costs that were recoverable through regulatory and tolling structures. In addition, $44 million was recorded as a Regulatory asset as it is expected to be recovered through regulatory and tolling structures in future periods, and $8 million was capitalized to projects impacted by the corporate restructuring. In 2016, an additional provision of $44 million before tax was recorded related to changes to the expected future losses under lease commitments. For the year ended December 31, 2016, $22 million was recorded in Plant operating costs and other in the Consolidated statement of income. In addition, $22 million was recorded as a Regulatory asset on the Consolidated balance sheet at December 31, 2016 as this amount is expected to be recovered through regulatory and tolling structures in future periods. In 2017, an additional provision of $6 million before tax was recorded related to changes to the expected future losses under lease commitments. For the year ended December 31, 2017, $3 million was recorded in Plant operating costs and other in the Consolidated statement of income. In addition, $3 million was recorded as a Regulatory asset on the Consolidated balance sheet at December 31, 2017 as this amount is expected to be recovered through regulatory and tolling structures in future periods. Cumulatively at December 31, 2017, the Company has incurred costs, net of recoverable amounts of $ 86 million for employee severance and $ 38 million for lease commitments under this initiative. The remaining employee severance provision at December 31, 2017 is expected to be settled in early 2018. Changes in the restructuring liability were as follows: (millions of Canadian $) Employee Severance Lease Commitments Total Restructuring liability as at December 31, 2015 60 27 87 Restructuring charges — 44 44 Cash payments (24 ) (8 ) (32 ) Restructuring liability as at December 31, 2016 36 63 99 Restructuring charges — 6 6 Cash payments (27 ) (16 ) (43 ) Restructuring Liability as at December 31, 2017 9 53 62 |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. In 2017 , Interest income and other included nil as a result of inter-affiliate lending to TransCanada ( 2016 – $19 million ; 2015 – $29 million ). The following amounts are included in Due to affiliate: 2017 2016 (millions of Canadian $) Maturity Date Outstanding December 31 Effective Interest Rate Outstanding December 31 Effective Interest Rate Credit Facility 1 Demand 2,551 3.2 % 2,358 2.7 % 2,551 2,358 1 TCPL has an unsecured $3.0 billion credit facility with TransCanada. Interest on this facility is charged at the prime rate per annum. In 2017 , Interest expense included $68 million of interest charges as a result of inter-affiliate borrowing ( 2016 – $38 million ; 2015 – $28 million ). At December 31, 2017 , Accounts payable and other included $16 million due to TransCanada ( December 31, 2016 – $19 million ). The company made interest payments of $68 million to TransCanada in 2017 ( 2016 – $36 million ; 2015 – $29 million ). |
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are accounted for as equity investments. Consolidated VIEs The Company's consolidated VIEs consist of legal entities where the Company is the primary beneficiary. As the primary beneficiary, the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE. A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The Consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations are as follows: at December 31 (millions of Canadian $) 2017 2016 ASSETS Current Assets Cash and cash equivalents 41 77 Accounts receivable 63 71 Inventories 23 25 Other 11 10 138 183 Plant, Property and Equipment 3,535 3,685 Equity Investments 917 606 Goodwill 490 525 Intangible and Other Assets 3 1 5,083 5,000 LIABILITIES Current Liabilities Accounts payable and other 137 80 Dividends payable 1 — Accrued interest 23 21 Current portion of long-term debt 88 76 249 177 Regulatory Liabilities 34 34 Other Long-Term Liabilities 3 4 Deferred Income Tax Liabilities 13 7 Long-Term Debt 3,244 2,827 3,543 3,049 Non-Consolidated VIEs The Company’s non-consolidated VIEs consist of legal entities where the Company is not the primary beneficiary as it does not have the power to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid. The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows: at December 31 (millions of Canadian $) 2017 2016 Balance sheet Equity investments 4,372 4,964 Off-balance sheet Potential exposure to guarantees 171 163 Maximum exposure to loss 4,543 5,127 |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | SUBSEQUENT EVENT Common Share Issuance On January 31, 2018, the Company issued 3.4 million common shares to TransCanada for proceeds of $192 million . |
ACCOUNTING POLICIES (Policies)
ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation These consolidated financial statements include the accounts of TCPL and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. TCPL uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TCPL records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation. |
Use of Estimates and Judgments | Use of Estimates and Judgments In preparing these consolidated financial statements, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Significant estimates and judgments used in the preparation of the consolidated financial statements include, but are not limited to: • fair value of assets and liabilities acquired in a business combination (Note 5) • fair value and depreciation rates of plant, property and equipment (Note 8) • carrying value of regulatory assets and liabilities (Note 10) • fair value of goodwill (Note 11) • fair value of intangible assets (Note 12) • carrying value of asset retirement obligations (Note 15) • provisions for income taxes, including U.S. Tax Reform (Note 16) • assumptions used to measure retirement and other post-retirement obligations (Note 22) • fair value of financial instruments (Note 23) and • provision for commitments, contingencies, guarantees (Note 26) and restructuring costs (Note 27). Actual results could differ from these estimates. |
Regulation | Regulation Certain Canadian, U.S. and Mexico natural gas pipeline and storage assets are regulated with respect to construction, operations and the determination of tolls. In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB) or the Alberta Energy Regulator (AER). In the U.S., regulated natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TCPL's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TCPL's businesses that apply RRA currently include Canadian, U.S. and Mexico natural gas pipelines, and regulated U.S. natural gas storage. RRA is not applicable to liquids pipelines as the regulators' decisions regarding operations and tolls on those systems generally do not have an impact on timing of recognition of revenues and expenses. |
Revenue Recognition | Revenue Recognition Natural Gas Pipelines and Liquids Pipelines Capacity Arrangements and Transportation Revenues from the Company's natural gas and liquids pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made. Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline tolls are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines generally are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines, at times, are subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues on firm contracted capacity are recognized ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenues are recorded when the NEB decision is received. The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and recognized ratably over the contract period. Other volumes shipped on these pipelines are subject to CRE-approved tariffs. The Company does not take ownership of the natural gas that it transports for its customers. Regulated Natural Gas Storage Revenues from the Company's regulated natural gas storage services are recognized either ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, or when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the natural gas that it stores for its customers. Midstream and Other Revenues from the Company's midstream natural gas services, including gathering, treating, conditioning, processing, compression and liquids handling services, are generated from contractual arrangements and are recognized ratably over the contract period regardless of the amount of natural gas that is subject to these services. The Company also owns mineral rights associated with certain storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest. Royalties from mineral interests are recognized when commodities are produced. Energy Power Generation Revenues from the Company's Energy business are primarily derived from the sale of electricity, which is recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative instruments and hedging activities policy in this note. Non-Regulated Natural Gas Storage Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded net of the cost of the proprietary natural gas in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. |
Inventories | Inventories Inventories primarily consist of natural gas inventory in storage, crude oil in transit, materials and supplies including spare parts and fuel. Inventories are carried at the lower of cost and net realizable value. |
Assets Held For Sale | Assets Held For Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next twelve months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, net of selling costs, and any losses are recognized in net income. Depreciation expense is no longer recorded once an asset is classified as held for sale. |
Plant, Property and Equipment | Plant, Property and Equipment Natural Gas Pipelines Plant, property and equipment for natural gas pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to six per cent, and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in plant, property and equipment with a corresponding credit recognized in Allowance for funds used during construction in the Consolidated statement of income. The equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines. Regulated natural gas storage base gas, which is valued at cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver natural gas held in storage. Base gas is not depreciated. When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove a plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Midstream and Other Plant, property and equipment for midstream assets is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Gathering and processing facilities are depreciated at annual rates ranging from 1.7 per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. The Company participates as a working interest partner in the development of certain Marcellus and Utica acreage. The working interest allows the Company to invest in drilling activities in addition to receiving a royalty interest in well production. The Company uses the successful efforts method of accounting for natural gas and crude oil resulting from its portion of drilling activities. Capitalized well costs are depleted based on the units of production method. Liquids Pipelines Plant, property and equipment for liquids pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. Energy Plant, property and equipment for Energy assets are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. Non-regulated natural gas storage base gas, which is valued at original cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver gas held in storage. Base gas is not depreciated. Corporate Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful life at average annual rates ranging from three per cent to 20 per cent. Capitalized Project Costs The Company capitalizes project costs once advancement of the project to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest costs for non-regulated projects in development and AFUDC for regulated projects in development. Capital projects in development are included in Intangible and other assets on the Consolidated balance sheet. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to Plant, property and equipment under construction. When the asset is ready for its intended use and available for operations, capitalized project costs are depreciated in accordance with the Company's plant, property and equipment depreciation policies. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows or the estimated selling price is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset. |
Acquisitions and Goodwill | Acquisitions and Goodwill The Company accounts for business combinations using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair values at the date of acquisition. The excess of the fair value of the consideration transferred over the estimated fair value of the net assets acquired is classified as goodwill. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that it might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company can initially assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the first step of a two- step impairment test is performed by comparing the fair value of the reporting unit to its carrying value, which includes goodwill. If the fair value of the reporting unit is less than its carrying value, an impairment is indicated and the second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference. The Company can elect to move directly to the first step of the two-step impairment test for any of its reporting units when performing its annual impairment test. |
Loans and Receivables | Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at cost. |
Power Purchase Arrangements | Power Purchase Arrangements A power purchase arrangement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. TCPL has PPAs for the sale of power that are accounted for as operating leases where TCPL is the lessor. During 2016, the Company terminated its Alberta PPAs under which it purchased power and recorded an impairment charge. Prior to their termination, substantially all of these PPAs were also accounted for as operating leases, where TCPL was the lessee, and initial payments to acquire these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts. A portion of these PPAs were subleased to third parties under terms and conditions similar to the PPAs, and were also accounted for as operating leases with the margin earned from the subleases recorded in Revenues. |
Restricted Investments | Restricted Investments The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are classified as available for sale and are recorded at fair value on the Consolidated balance sheet. As a result of the NEB’s Land Matters Consultation Initiative (LMCI), TCPL is required to collect funds to cover estimated future pipeline abandonment costs for all NEB regulated Canadian pipelines. Funds collected are placed in trusts that hold and invest the funds and are accounted for as restricted investments. LMCI restricted investments may only be used to fund the abandonment of the NEB regulated pipeline facilities; therefore, a corresponding regulatory liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. |
Income Taxes | Income Taxes The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net income in the period during which they occur, except for changes in balances related to regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the regulator. D eferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet. Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. |
Asset Retirement Obligations | Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Operating and other expenses. The Company has recorded AROs related to its non-regulated natural gas storage operations, mineral rights and power generation facilities. The scope and timing of asset retirements related to most of the Company's natural gas pipelines and liquids pipelines is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities and certain facilities expected to be retired as part of an ongoing modernization program that will improve system integrity and enhance service reliability and flexibility on its Columbia Gas pipeline. |
Environmental Liabilities | Environmental Liabilities The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. These estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. These estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability. Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and expensed when they are utilized. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TCPL are not attributed a value for accounting purposes. When required, TCPL accrues emission liabilities on the Consolidated balance sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues. |
Stock Options and Other Compensation Programs | Stock Options and Other Compensation Programs TransCanada's Stock Option Plan permits options for the purchase of TransCanada common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period with an offset to Additional paid-in capital. TCPL records the compensation expense associated with these stock options. The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets. |
Employee Post-Retirement Benefits | Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service, and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five -year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service life of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income/(loss) (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated other comprehensive income/(loss) (AOCI) and into net income over the average remaining service life of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees. |
Foreign Currency Transactions and Translation | Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or reporting subsidiary operates. This is referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in net income except for exchange gains and losses of the foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB. Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI until the operations are sold, at which time the gains and losses are reclassified to net income. Asset and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt and certain derivative hedging instruments have been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar denominated debt are also reflected in OCI. |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions. The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment. This includes fair value and cash flow hedges and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in net income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. In hedging the foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in net income. The amounts recognized previously in AOCI are reclassified to net income in the event the Company reduces its net investment in a foreign operation. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as Regulatory assets or Regulatory liabilities and are refunded to or collected from the ratepayers, in subsequent years when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in net income. |
Long-Term Debt Transaction Costs and Issuance Costs | Long-Term Debt Transaction Costs and Issuance Costs The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the related debt liability and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms. |
Guarantees | Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of partially owned entity or by partially owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments, Plant, property and equipment, or a charge to net income, and a corresponding liability is recorded in Other long-term liabilities. The release from the obligation is recognized either over the term of the guarantee or upon expiration or settlement of the guarantee. |
Accounting Changes | ACCOUNTING CHANGES Changes in Accounting Policies for 2017 Inventory In July 2015, the Financial Accounting Standards Board (FASB) issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this guidance at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Company's Consolidated balance sheet. Derivatives and hedging In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks of their debt hosts. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements. Equity method investments In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance was effective January 1, 2017, was applied prospectively and has not resulted in any impact on the Company's consolidated financial statements. Employee share-based payments In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. The Company has elected to account for forfeitures when they occur. This new guidance was effective January 1, 2017 and resulted in a cumulative-effect adjustment of $12 million to retained earnings and the recognition of a deferred tax asset related to employee share-based payments that were made prior to the adoption of this guidance. Consolidation In October 2016, the FASB issued new guidance on consolidation relating to VIEs held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to the Company's consolidation conclusions. Future Accounting Changes Revenue from contracts with customers In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Company will adopt the new guidance on the effective date of January 1, 2018. There are two methods in which the new guidance can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Company will adopt the guidance using the modified retrospective approach with the cumulative-effect of the adjustment, if any, recognized at the date of adoption, subject to allowable and elected practical expedients. The Company identified all existing customer contracts that are within the scope of the new guidance by operating segment. The Company has completed its analysis of the contracts and has not identified any material differences in the amount and timing of revenue recognition as a result of implementing the new guidance. Therefore, the Company will not require a cumulative-effect adjustment to opening retained earnings on January 1, 2018. Although consolidated revenues will not be materially impacted by the new guidance, the Company will be required to add significant disclosures based on the prescribed requirements. These new disclosures will include information regarding the significant judgments used in evaluating when and how revenues, are recognized and information related to contract assets and deferred revenues. In addition, the new guidance requires that the Company’s revenue recognition policy disclosure include additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenues and cash flows generated from contracts with customers. The Company has developed draft disclosures required in first quarter 2018 with a particular focus on the scope of contracts subject to disclosure of future revenues from remaining performance obligations. The Company has addressed system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. Financial instruments In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in the fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018 and a method of adoption is specified for each component of the guidance. The Company has completed its analysis and does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the lessor to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for an arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is continuing to identify and analyze existing lease agreements to determine the effect of application of the new guidance on its consolidated financial statements. The Company is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance and continues to monitor and analyze additional guidance and clarification provided by the FASB. Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Income taxes In October 2016, the FASB issued new guidance on the income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied using a modified retrospective approach. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. Restricted cash In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents balance, and amounts generally described as restricted cash or restricted cash equivalents. Restricted cash and cash equivalents will be included with Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively. Goodwill impairment In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating Step 2 of the impairment test, which is the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted. Employee post-retirement benefits In March 2017, the FASB issued new guidance that will require entities to disaggregate the current service cost component from the other components of net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance is effective January 1, 2018. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. Amortization on purchased callable debt securities In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Hedge accounting In August 2017, the FASB issued new guidance on hedge accounting, making more financial and non-financial hedging strategies eligible for hedge accounting. The new guidance also amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019, with early adoption permitted. The Company has elected to apply this guidance effective January 1, 2018. The Company has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements. |
SEGMENTED INFORMATION (Tables)
SEGMENTED INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment | year ended December 31, 2017 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,693 3,584 570 2,009 3,593 — 13,449 Intersegment revenues — 51 — — — (51 ) — 3,693 3,635 570 2,009 3,593 (51 ) 13,449 Income from equity investments 11 240 (9 ) (3 ) 471 63 2 773 Plant operating costs and other (1,300 ) (1,340 ) (42 ) (623 ) (550 ) (51 ) (3,906 ) Commodity purchases resold — — — — (2,382 ) — (2,382 ) Property taxes (260 ) (181 ) — (89 ) (39 ) — (569 ) Depreciation and amortization (908 ) (594 ) (93 ) (309 ) (151 ) — (2,055 ) Goodwill and other asset impairment charges — — — (1,236 ) (21 ) — (1,257 ) Gain on assets held for sale/sold — — — — 631 — 631 Segmented earnings/(losses) 1,236 1,760 426 (251 ) 1,552 (39 ) 4,684 Interest expense (2,137 ) Allowance for funds used during construction 507 Interest income and other 183 Income before income taxes 3,237 Income tax recovery 107 Net income 3,344 Net income attributable to non-controlling interests (238 ) Net income attributable to controlling interests and to common shares 3,106 Capital spending Capital expenditures 2,106 3,712 833 341 350 41 7,383 Capital projects in development 75 — — 71 — — 146 Contributions to equity investments — 118 1,121 117 325 — 1,681 2,181 3,830 1,954 529 675 41 9,210 1 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. 2 This Inc ome from equity investments relates to foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture. Refer to Note 9, Equity investments, for further information. year ended December 31, 2016 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,682 2,526 378 1,755 4,206 — 12,547 Intersegment revenues — 56 — — — (56 ) — 3,682 2,582 378 1,755 4,206 (56 ) 12,547 Income from equity investments 12 214 (3 ) (1 ) 292 — 514 Plant operating costs and other (1,245 ) (1,057 ) (43 ) (568 ) (884 ) (64 ) (3,861 ) Commodity purchases resold — — — — (2,172 ) — (2,172 ) Property taxes (267 ) (120 ) — (88 ) (80 ) — (555 ) Depreciation and amortization (875 ) (425 ) (45 ) (292 ) (302 ) — (1,939 ) Goodwill and other asset impairment charges — — — — (1,388 ) — (1,388 ) Loss on assets held for sale/sold — (4 ) — — (829 ) — (833 ) Segmented earnings/(losses) 1,307 1,190 287 806 (1,157 ) (120 ) 2,313 Interest expense (1,927 ) Allowance for funds used during construction 419 Interest income and other 117 Income before income taxes 922 Income tax expense (349 ) Net income 573 Net income attributable to non-controlling interests (252 ) Net income attributable to controlling interests and to common shares 321 Capital spending Capital expenditures 1,372 1,517 944 668 473 33 5,007 Capital projects in development 153 — — 142 — — 295 Contributions to equity investments — 5 198 327 235 — 765 1,525 1,522 1,142 1,137 708 33 6,067 1 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. year ended December 31, 2015 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 3,680 1,444 259 1,879 4,091 — 11,353 Intersegment revenues — 47 — — — (47 ) — 3,680 1,491 259 1,879 4,091 (47 ) 11,353 Income from equity investments 12 162 5 — 261 — 440 Plant operating costs and other (1,204 ) (606 ) (51 ) (492 ) (845 ) (105 ) (3,303 ) Commodity purchases resold — — — — (2,237 ) — (2,237 ) Property taxes (272 ) (77 ) — (79 ) (89 ) — (517 ) Depreciation and amortization (849 ) (248 ) (44 ) (283 ) (341 ) — (1,765 ) Asset impairment charges — — — (3,686 ) (59 ) — (3,745 ) Loss on assets held for sale/sold — (125 ) — — — — (125 ) Segmented earnings/(losses) 1,367 597 169 (2,661 ) 781 (152 ) 101 Interest expense (1,398 ) Allowance for funds used during construction 295 Interest income and other (103 ) Loss before income taxes (1,105 ) Income tax expense (35 ) Net loss (1,140 ) Net income attributable to non-controlling interests (6 ) Net loss attributable to controlling interests and to common shares (1,146 ) Capital spending Capital expenditures 1,366 534 566 1,012 376 64 3,918 Capital projects in development 230 3 — 278 — — 511 Contributions to equity investments — — — 311 182 — 493 1,596 537 566 1,601 558 64 4,922 1 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties. at December 31 2017 2016 (millions of Canadian $) Total Assets Canadian Natural Gas Pipelines 16,904 15,816 U.S. Natural Gas Pipelines 35,898 34,422 Mexico Natural Gas Pipelines 5,716 5,013 Liquids Pipelines 15,438 16,896 Energy 8,503 13,169 Corporate 3,551 2,625 86,010 87,941 |
Revenue from External Customers by Geographic Areas | year ended December 31 2017 2016 2015 (millions of Canadian $) Revenues Canada – domestic 3,618 3,697 3,930 Canada – export 1,255 1,177 1,292 United States 8,006 7,295 5,872 Mexico 570 378 259 13,449 12,547 11,353 |
Schedule of Long-Lived Assets by Country | at December 31 2017 2016 (millions of Canadian $) Plant, Property and Equipment Canada 21,632 20,531 United States 30,693 29,414 Mexico 4,952 4,530 57,277 54,475 |
ACQUISITION OF COLUMBIA (Tables
ACQUISITION OF COLUMBIA (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The acquisition was accounted for as a business combination using the acquisition method where the acquired tangible and intangible assets and assumed liabilities were recorded at their estimated fair values at the date of acquisition. The purchase price equation reflects management’s estimate of the fair value of Columbia’s assets and liabilities as at July 1, 2016 . July 1, 2016 (millions of $) U.S. Canadian 1 Purchase Price Consideration 10,294 13,392 Fair Value Current assets 658 856 Plant, property and equipment 7,560 9,835 Equity investments 441 574 Regulatory assets 190 248 Intangible and other assets 135 175 Current liabilities (597 ) (777 ) Regulatory liabilities (294 ) (383 ) Other long-term liabilities (144 ) (187 ) Deferred income tax liabilities (1,613 ) (2,098 ) Long-term debt (2,981 ) (3,878 ) Non-controlling interests (808 ) (1,051 ) Fair Value of Net Assets Acquired 2,547 3,314 Goodwill (Note 11) 7,747 10,078 1 At July 1, 2016 exchange rate of $1.30 . |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments | The following table summarizes the acquisition date fair value of Columbia's debt acquired by TCPL. (millions of $) Maturity Date Type Fair Value Interest Rate COLUMBIA PIPELINE GROUP, INC. June 2018 Senior Unsecured Notes (US$500) US$506 2.45 % June 2020 Senior Unsecured Notes (US$750) US$779 3.30 % June 2025 Senior Unsecured Notes (US$1,000) US$1,092 4.50 % June 2045 Senior Unsecured Notes (US$500) US$604 5.80 % US$2,981 |
Business Acquisition, Pro Forma Information | The following supplemental pro forma consolidated financial information of the Company for the years ended December 31, 2016 and 2015 includes the results of operations for Columbia as if the acquisition had been completed on January 1, 2015 . year ended December 31 (millions of Canadian $) 2016 2015 Revenues 13,404 13,007 Net Income/(Loss) 715 (820 ) Net Income/(Loss) Attributable to Controlling Interests and to Common Shares 431 (877 ) |
OTHER CURRENT ASSETS (Tables)
OTHER CURRENT ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Assets [Abstract] | |
Schedule of Other Current Assets | at December 31 2017 2016 (millions of Canadian $) Fair value of derivative contracts (Note 23) 332 376 Prepaid expenses 109 131 Cash provided as collateral 99 313 Regulatory assets (Note 10) 23 33 Other 128 55 691 908 |
PLANT, PROPERTY AND EQUIPMENT (
PLANT, PROPERTY AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Plant, Property and Equipment | 2017 2016 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 10,153 4,190 5,963 8,814 3,951 4,863 Compression 3,021 1,593 1,428 2,447 1,499 948 Metering and other 1,188 569 619 1,124 519 605 14,362 6,352 8,010 12,385 5,969 6,416 Under construction 940 — 940 1,151 — 1,151 15,302 6,352 8,950 13,536 5,969 7,567 Canadian Mainline Pipeline 9,763 6,455 3,308 9,502 6,221 3,281 Compression 3,605 2,499 1,106 3,537 2,361 1,176 Metering and other 655 207 448 605 198 407 14,023 9,161 4,862 13,644 8,780 4,864 Under construction 156 — 156 219 — 219 14,179 9,161 5,018 13,863 8,780 5,083 Other Canadian Natural Gas Pipelines Other 1 1,815 1,363 452 1,728 1,273 455 Under construction 4 — 4 112 — 112 1,819 1,363 456 1,840 1,273 567 31,300 16,876 14,424 29,239 16,022 13,217 U.S. Natural Gas Pipelines Columbia Gas Pipeline 3,550 125 3,425 3,317 42 3,275 Compression 1,547 64 1,483 1,636 29 1,607 Metering and other 2,306 37 2,269 2,550 8 2,542 7,403 226 7,177 7,503 79 7,424 Under construction 3,332 — 3,332 1,127 — 1,127 10,735 226 10,509 8,630 79 8,551 ANR Pipeline 1,427 365 1,062 1,468 349 1,119 Compression 1,582 286 1,296 1,494 260 1,234 Metering and other 961 268 693 988 254 734 3,970 919 3,051 3,950 863 3,087 Under construction 358 — 358 232 — 232 4,328 919 3,409 4,182 863 3,319 2017 2016 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,107 822 1,285 2,221 810 1,411 Great Lakes 1,988 1,113 875 2,106 1,155 951 Columbia Gulf 1,115 37 1,078 880 5 875 Midstream 1,085 54 1,031 1,072 23 1,049 Other 2 1,950 574 1,376 2,120 567 1,553 8,245 2,600 5,645 8,399 2,560 5,839 Under construction 699 — 699 346 — 346 8,944 2,600 6,344 8,745 2,560 6,185 24,007 3,745 20,262 21,557 3,502 18,055 Mexico Natural Gas Pipelines Pipeline 2,486 214 2,272 2,734 180 2,554 Compression 388 30 358 422 19 403 Metering and other 522 65 457 502 40 462 3,396 309 3,087 3,658 239 3,419 Under construction 1,865 — 1,865 1,108 — 1,108 5,261 309 4,952 4,766 239 4,527 Liquids Pipelines Keystone Pipeline System Pipeline 9,002 992 8,010 10,572 901 9,671 Pumping equipment 1,022 152 870 928 121 807 Tanks and other 3,314 385 2,929 2,521 286 2,235 13,338 1,529 11,809 14,021 1,308 12,713 Under construction 456 — 456 479 — 479 13,794 1,529 12,265 14,500 1,308 13,192 Intra-Alberta Pipelines 3 Pipeline 748 3 745 — — — Pumping equipment 104 — 104 — — — Tanks and other 259 1 258 — — — 1,111 4 1,107 — — — Under construction 47 — 47 955 — 955 1,158 4 1,154 955 — 955 14,952 1,533 13,419 15,455 1,308 14,147 Energy Natural Gas 4,5 2,645 743 1,902 2,696 696 2,000 Wind and Solar 6 673 204 469 1,180 245 935 Natural Gas Storage and Other 734 156 578 731 146 585 4,052 1,103 2,949 4,607 1,087 3,520 Under construction 1,028 — 1,028 729 — 729 5,080 1,103 3,977 5,336 1,087 4,249 Corporate 411 168 243 410 130 280 81,011 23,734 57,277 76,763 22,288 54,475 1 Includes Foothills, Ventures LP and Great Lakes Canada . 2 Includes Bison, Portland Natural Gas Transmission System, North Baja, Tuscarora and Crossroads. 3 Includes Northern Courier, placed in-service on November 1, 2017 and White Spruce. 4 Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities was $ 1,264 million and $ 354 million , respectively, at December 31, 2017 ( 2016 – $ 1,319 million and $ 335 million , respectively). Revenues of $ 215 million were recognized in 2017 ( 2016 – $ 212 million ; 2015 – $ 235 million ) through the sale of electricity under the related PPAs. 5 Includes Coolidge, Grandview, and Bécancour assets which operate under operating leases, along with Halton Hills and Alberta cogeneration natural gas-fired facilities. 6 Ontario solar assets are excluded from the Wind and Solar net book value at December 31, 2017 as they were sold on December 19, 2017. Refer to Note 25, Other acquisitions and dispositions, for further information. |
EQUITY INVESTMENTS (Tables)
EQUITY INVESTMENTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of Equity Investments | (millions of Canadian $) Ownership Income/(Loss) from Equity Investments Equity Investments year ended December 31 at December 31 2017 2016 2015 2017 2016 Canadian Natural Gas Pipelines TQM 50.0 % 11 12 12 68 71 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 87 92 85 641 597 Iroquois 2 50.0 % 59 54 51 280 309 Millennium 3 47.5 % 66 33 — 291 295 Pennant Midstream 3 47.0 % 11 6 — 228 246 Other Various 17 29 26 92 93 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % 66 (3 ) — 399 255 TransGas 46.5 % (12 ) — 5 — 28 Liquids Pipelines Grand Rapids 5 50.0 % 17 (1 ) — 996 876 Other 6 Various (20 ) — — 20 39 Energy Bruce Power 7 48.4 % 434 293 249 2,987 3,356 Portlands Energy 8 50.0 % 31 33 30 301 313 ASTC Power Partnership 50.0 % — (37 ) (23 ) — — Other Various 6 3 5 63 66 773 514 440 6,366 6,544 1 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company was US$115 million ( 2016 – US$116 million ) due to the fair value assessment of assets at the time of acquisition. 2 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million ( 2016 – US$48 million ) due mainly to the fair value assessment of the assets at the time of acquisition. 3 Acquired as part of Columbia on July 1, 2016. Income from Equity investments reflects equity earnings from the date of acquisition. 4 TCPL has an ownership interest of 60.0 per cent in Sur de Texas, which as a jointly controlled entity applies the equity method of accounting. Income from equity investments includes amounts recorded in the Corporate segment. 5 Grand Rapids was placed in service in August 2017. At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $105 million ( 2016 – $86 million ) due mainly to interest capitalized during construction and the fair value of guarantees. 6 Includes investments in Canaport Energy East Marine Terminal Limited Partnership and HoustonLink Pipeline Company LLC. At December 31, 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil . 7 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $902 million ( 2016 – $942 million ) due to the fair value assessment of assets at the time of acquisitions. 8 At December 31, 2017 , the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million ( 2016 – $70 million ) due mainly to interest capitalized during construction. |
Summary of Financial Information of Equity Investments | year ended December 31 2017 2016 2015 (millions of Canadian $) Income Revenues 4,913 4,336 4,337 Operating and other expenses (2,993 ) (3,068 ) (3,142 ) Net income 1,636 1,080 1,046 Net income attributable to TCPL 773 514 440 at December 31 2017 2016 (millions of Canadian $) Balance Sheet Current assets 2,176 1,669 Non-current assets 17,869 15,853 Current liabilities (1,577 ) (1,120 ) Non-current liabilities (8,217 ) (5,867 ) |
RATE-REGULATED BUSINESSES (Tabl
RATE-REGULATED BUSINESSES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets and Liabilities | at December 31 2017 2016 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 967 861 n/a Deferred income taxes – U.S. Tax Reform 2 (27 ) — n/a Operating and debt-service regulatory assets 3 — 1 1 Pensions and other post-retirement benefits 1,4 388 382 n/a Foreign exchange on long-term debt 1,5 — 37 1-12 Other 71 74 n/a 1,399 1,355 Less: Current portion included in Other current assets (Note 7) 23 33 1,376 1,322 Regulatory Liabilities Operating and debt-service regulatory liabilities 3 188 47 1 Pensions and other post-retirement benefits 4 164 180 n/a ANR related post-employment and retirement benefits other than pension 6 66 141 n/a Long term adjustment account 7 1,142 659 46 Pipeline abandonment trust balance 825 541 n/a Bridging amortization account 7 202 451 13 Cost of removal 8 216 226 n/a Deferred income taxes 75 — n/a Deferred income taxes – U.S. Tax Reform 2 1,659 — n/a Other 47 54 n/a 4,584 2,299 Less: Current portion included in Accounts payable and other (Note 14) 263 178 4,321 2,121 1 These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period. 2 These balances represent the impact of U.S. Tax Reform. The regulatory assets and regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax assets and liabilities that gave rise to the regulatory assets and liabilities. See Note 16, Income taxes, for further information. 3 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar years. 4 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates. 5 Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. 6 This balance represents the amount ANR estimates it would be required to refund to its customers for post-retirement and post-employment benefit amounts collected through its FERC-approved rates that have not been used to pay benefits to its employees. Pursuant to a FERC-approved September 2016 rate settlement, $26 million ( US$21 million ) of the regulatory liability balance at December 31, 2017 (2016 – $46 million , US$34 million ) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $40 million ( US$32 million ) balance accumulated prior to 2007 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period cannot be determined at this time. 7 These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. 8 This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated subsidiaries for future costs to be incurred. |
GOODWILL (Tables)
GOODWILL (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of goodwill recorded on the entity's acquisitions in the U.S. | The Company has recorded the following Goodwill on its acquisitions in the U.S.: (millions of Canadian $) U.S. Natural Gas Pipelines Energy Total Balance at January 1, 2016 3,667 1,145 4,812 Acquisition of Columbia (Note 5) 10,078 — 10,078 Impairment charge — (1,085 ) (1,085 ) Foreign exchange rate changes 213 (60 ) 153 Balance at December 31, 2016 13,958 — 13,958 Columbia adjustment (Note 5) 71 — 71 Foreign exchange rate changes (945 ) — (945 ) Balance at December 31, 2017 13,084 — 13,084 |
INTANGIBLE AND OTHER ASSETS (Ta
INTANGIBLE AND OTHER ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |
Schedule of Other Assets | at December 31 2017 2016 (millions of Canadian $) Capital projects in development 596 2,094 Deferred income tax assets (Note 16) 255 313 Employee post-retirement benefits (Note 22) 193 189 Fair value of derivative contracts (Note 23) 73 133 Other 306 218 1,423 2,947 |
NOTES PAYABLE (Tables)
NOTES PAYABLE (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Short-term Debt [Abstract] | |
Schedule of Notes Payable | 2017 2016 (millions of Canadian $, unless otherwise noted) Outstanding at December 31 Weighted Average Interest Rate per Annum at December 31 Outstanding at December 31 Weighted Average Interest Rate per Annum at December 31 Canadian 884 1.6 % 509 0.9 % U.S. (2017 – US$688; 2016 – US$197) 862 2.2 % 265 0.5 % MXN (2017 – MXN$275) 17 8.0 % — — 1,763 774 |
Schedule of Credit Facilities | These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2017 2016 Borrower Description Matures Total Facilities Unused Capacity Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 1 : TCPL Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes December 2022 3.0 3.0 3.0 TCPL Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes December 2018 US 2.0 US 2.0 US 2.0 TCPL USA Used for TCPL USA general corporate purposes, guaranteed by TCPL December 2018 US 1.0 US 0.6 US 1.0 Columbia Used for Columbia general corporate purposes, guaranteed by TCPL December 2018 US 1.0 US 1.0 US 1.0 TAIL Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL December 2018 US 0.5 US 0.5 US 0.5 Demand senior unsecured revolving credit facilities 1 : TCPL/TCPL USA Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL Demand 1.9 0.5 1.9 Mexican subsidiary Used for Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 MXN 4.7 — 1 Provisions of various credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2017, the Company was in compliance with all debt covenants. |
ACCOUNTS PAYABLE AND OTHER (Tab
ACCOUNTS PAYABLE AND OTHER (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Payables and Accruals [Abstract] | |
Schedule of Accounts Payable and Other | at December 31 2017 2016 (millions of Canadian $) Trade payables 2,847 2,443 Fair value of derivative contracts (Note 23) 387 607 Unredeemed shares of Columbia 312 317 Regulatory liabilities (Note 10) 263 178 Other 262 331 4,071 3,876 |
OTHER LONG-TERM LIABILITIES (Ta
OTHER LONG-TERM LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Deferred Costs, Noncurrent [Abstract] | |
Schedule of Other Long-Term Liabilities | at December 31 2017 2016 (millions of Canadian $) Employee post-retirement benefits (Note 22) 389 448 Fair value of derivative contracts (Note 23) 72 330 Asset retirement obligations 98 108 Guarantees (Note 26) 16 82 Other 152 215 727 1,183 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of Provision for Income Taxes | year ended December 31 2017 2016 2015 (millions of Canadian $) Current Canada 113 117 45 Foreign 36 40 92 149 157 137 Deferred Canada (203 ) 97 33 Foreign 751 95 (135 ) Foreign – U.S. Tax Reform (804 ) — — (256 ) 192 (102 ) Income Tax (Recovery)/Expense (107 ) 349 35 |
Schedule of Geographic Components of Income | year ended December 31 2017 2016 2015 (millions of Canadian $) Canada (408 ) 304 (623 ) Foreign 3,645 618 (482 ) Income/(Loss) before Income Taxes 3,237 922 (1,105 ) |
Reconciliation of Income Tax Expense | year ended December 31 2017 2016 2015 (millions of Canadian $) Income/(loss) before income taxes 3,237 922 (1,105 ) Federal and provincial statutory tax rate 27 % 27 % 26 % Expected income tax expense/(recovery) 874 249 (287 ) U.S. Tax Reform (804 ) — — Foreign income tax rate differentials (81 ) (196 ) 14 Income from equity investments and non-controlling interests (64 ) (68 ) (56 ) Income tax differential related to regulated operations (42 ) 81 159 Non-taxable portion of capital gains (42 ) — — Asset impairment charges 1 34 242 170 Non-deductible amounts 4 18 — Tax rate and legislative changes — — 34 Other 14 23 1 Income Tax (Recovery)/Expense (107 ) 349 35 1 Net of nil (2016 – $112 million ; 2015 – $311 million ) attributed to higher foreign tax rates. |
Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet | at December 31 2017 2016 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,365 2,049 Difference in accounting and tax bases of impaired assets and assets held for sale 651 1,168 Regulatory and other deferred amounts 512 277 Unrealized foreign exchange losses on long-term debt 216 446 Financial instruments 10 34 Other 180 287 2,934 4,261 Less: valuation allowance 832 1,336 2,102 2,925 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 6,240 9,015 Equity investments 632 905 Taxes on future revenue requirement 238 198 Other 140 156 7,250 10,274 Net Deferred Income Tax Liabilities 5,148 7,349 The above deferred tax amounts have been classified in the Consolidated balance sheet as follows: at December 31 2017 2016 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 12) 255 313 Deferred Income Tax Liabilities Deferred income tax liabilities 5,403 7,662 Net Deferred Income Tax Liabilities 5,148 7,349 |
Reconciliation of the Annual Changes in the Total Unrecognized Tax Benefit | Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2017 2016 2015 (millions of Canadian $) Unrecognized tax benefit at beginning of year 15 13 13 Gross increases – tax positions in prior years — 3 2 Gross decreases – tax positions in prior years (1 ) — (2 ) Gross increases – tax positions in current year 2 2 1 Settlement — (1 ) — Lapse of statutes of limitations (3 ) (2 ) (1 ) Unrecognized Tax Benefit at End of Year 13 15 13 |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Long-Term Debt | 2017 2016 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Debentures Canadian 2018 to 2020 500 10.8 % 600 10.7 % U.S. (2017 and 2016 – US$400) 2021 501 9.9 % 537 9.9 % Medium Term Notes Canadian 2019 to 2047 6,504 4.9 % 5,804 4.6 % Senior Unsecured Notes U.S. (2017 – US$14,892; 2016 – US$14,642) 2018 to 2045 18,644 5.1 % 19,660 5.1 % Acquisition Bridge Facility (2017 – nil; 2016 – US$2,013) — — — 2,702 1.9 % 26,149 29,303 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2017 and 2016 – US$200) 2023 250 7.9 % 269 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2017 and 2016 – US$33) 2026 41 7.5 % 44 7.5 % 895 917 TRANSCANADA PIPELINE USA LTD. Acquisition Bridge Facility (2017 – nil; 2016 – US$1,700) — — — 2,283 1.9 % COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2017 and 2016 – US$2,750) 2 2018 to 2045 3,443 4.0 % 3,692 4.0 % TC PIPELINES, LP Unsecured Loan Facility U.S. (2017 – US$185; 2016 – US$160) 2021 232 2.7 % 215 1.9 % Unsecured Term Loan U.S. (2017 and 2016 – US$670) 3 2020 to 2022 839 2.7 % 899 1.9 % Senior Unsecured Notes U.S. (2017 – US$1,200; 2016 – US$700) 2021 to 2027 1,502 4.4 % 940 4.7 % 2,573 2,054 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2017 and 2016 – US$672) 2021 to 2026 842 7.2 % 903 7.2 % GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2017 – US$55; 2016 – US$65) 2019 69 1.1 % 87 1.6 % Senior Unsecured Notes U.S. (2017 and 2016 – US$250) 2020 to 2035 313 5.6 % 336 5.6 % 382 423 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2017 – US$259; 2016 – US$278) 2018 to 2030 324 7.7 % 373 7.7 % 2017 2016 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Secured Notes 4 U.S. (2017 – US$30; 2016 – US$53) 2018 38 6.0 % 71 6.0 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2017 – US$25; 2016 – US$10) 2020 31 1.1 % 13 1.9 % Senior Secured Notes U.S. (2017 – nil; 2016 – US$12) — — — 16 4.0 % 31 29 34,677 40,048 Current portion of long-term debt (2,866 ) (1,838 ) Unamortized debt discount and issue costs (174 ) (191 ) Fair value adjustments 5 238 293 31,875 38,312 1 Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates. 2 Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia’s obligations is required to comply with covenants under the debt indenture and in the event of default, the guarantors would be obligated to pay the principal and related interest. 3 The US$170 million and US$500 million term loan facilities were amended in September 2017 to extend the maturity dates from 2018 to 2020 and 2022, respectively. 4 These notes are secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements. 5 The fair value adjustments include $242 million (2016 – $293 million ) related to the acquisition of Columbia. Refer to Note 5, Acquisition of Columbia, for further information. The fair value adjustments also include a decrease of $4 million (2016 – nil ) related to hedged interest rate risk. Refer to Note 23, Risk management and financial instruments, for further information. The Company issued long-term debt over the three years ended December 31, 2017 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED November 2017 Senior Unsecured Notes November 2019 US 550 Floating November 2017 Senior Unsecured Notes November 2019 US 700 2.125 % September 2017 Medium Term Notes March 2028 300 3.39 % September 2017 Medium Term Notes September 2047 700 4.33 % June 2016 Acquisition Bridge Facility 1 June 2018 US 5,213 Floating June 2016 Medium Term Notes July 2023 300 3.69 % 2 June 2016 Medium Term Notes June 2046 700 4.35 % January 2016 Senior Unsecured Notes January 2026 US 850 4.875 % January 2016 Senior Unsecured Notes January 2019 US 400 3.125 % November 2015 Senior Unsecured Notes November 2017 US 1,000 1.625 % October 2015 Medium Term Notes November 2041 400 4.55 % July 2015 Medium Term Notes July 2025 750 3.30 % March 2015 Senior Unsecured Notes March 2045 US 750 4.60 % January 2015 Senior Unsecured Notes January 2018 US 500 1.875 % January 2015 Senior Unsecured Notes January 2018 US 250 Floating TUSCARORA GAS TRANSMISSION COMPANY August 2017 Term Loan August 2020 US 25 Floating April 2016 Term Loan April 2019 US 10 Floating TC PIPELINES, LP May 2017 Senior Unsecured Notes May 2027 US 500 3.90 % September 2015 Unsecured Term Loan October 2018 US 170 Floating March 2015 Senior Unsecured Notes March 2025 US 350 4.375 % TRANSCANADA PIPELINE USA LTD. June 2016 Acquisition Bridge Facility 1 June 2018 US 1,700 Floating ANR PIPELINE COMPANY June 2016 Senior Unsecured Notes June 2026 US 240 4.14 % GAS TRANSMISSION NORTHWEST LLC June 2015 Unsecured Term Loan June 2019 US 75 Floating 1 These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the issuance of common shares in fourth quarter 2016 and proceeds from the sale of the U.S. Northeast power assets were used to fully retire the remaining acquisition bridge facilities in the second quarter 2017. 2 Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent . |
Schedule of Repayments of Long-Term Debt | At December 31, 2017, principal repayments for the next five years on the Company's Long-term debt are approximately as follows: (millions of Canadian $) 2018 2019 2020 2021 2022 Principal repayments on long-term debt 2,866 3,189 2,834 2,085 1,929 |
Schedule of Retired Long-Term Debt | The Company retired/repaid long-term debt over the three years ended December 31, 2017 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED December 2017 Debentures 100 9.80 % November 2017 Senior Unsecured Notes US 1,000 1.625 % June 2017 Acquisition Bridge Facility 1 US 1,513 Floating February 2017 Acquisition Bridge Facility 1 US 500 Floating January 2017 Medium Term Notes 300 5.10 % November 2016 Acquisition Bridge Facility 1 US 3,200 Floating October 2016 Medium Term Notes 400 4.65 % June 2016 Senior Unsecured Notes US 84 7.69 % June 2016 Senior Unsecured Notes US 500 Floating January 2016 Senior Unsecured Notes US 750 0.75 % August 2015 Debentures 150 11.90 % June 2015 Senior Unsecured Notes US 500 3.40 % March 2015 Senior Unsecured Notes US 500 0.875 % January 2015 Senior Unsecured Notes US 300 4.875 % TUSCARORA GAS TRANSMISSION COMPANY August 2017 Senior Secured Notes US 12 3.82 % TRANSCANADA PIPELINE USA LTD. June 2017 Acquisition Bridge Facility 1 US 630 Floating April 2017 Acquisition Bridge Facility 1 US 1,070 Floating NOVA GAS TRANSMISSION LTD. February 2016 Debentures 225 12.20 % GAS TRANSMISSION NORTHWEST LLC June 2015 Senior Unsecured Notes US 75 5.09 % 1 These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the issuance of common shares in fourth quarter 2016 and proceeds from the sale of the U.S. Northeast power assets were used to fully retire the remaining acquisition bridge facilities in the second quarter 2017. |
Schedule of Interest Expense | Interest expense in the three years ended December 31 was as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) Interest on long-term debt 1,794 1,765 1,487 Interest on junior subordinated notes 348 180 116 Interest on short-term debt 101 56 44 Capitalized interest (173 ) (176 ) (280 ) Amortization and other financial charges 1 67 102 31 2,137 1,927 1,398 1 Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to changes in interest rates. |
JUNIOR SUBORDINATED NOTES (Tabl
JUNIOR SUBORDINATED NOTES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Junior Subordinated Notes [Abstract] | |
Schedule of Junior Subordinated Notes | 2017 2016 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED U.S.$1,000 notes issued 2007 1 2067 1,252 5.0 % 3 1,343 6.4 % U.S.$750 notes issued 2015 1,2 2075 939 5.9 % 1,007 5.5 % U.S.$1,200 notes issued 2016 1,2 2076 1,502 6.6 % 1,611 6.2 % U.S.$1,500 notes issued 2017 1, 2 2077 1,878 5.6 % — — $1,500 notes issued 2017 1, 2 2077 1,500 5.1 % — — 7,071 3,961 Unamortized debt discount and issue costs (64 ) (30 ) 7,007 3,931 1 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 2 The Junior subordinated notes were issued to TransCanada Trust, a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TCPL's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. 3 In May 2017, Junior subordinated notes of US $1 billion converted from fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three month LIBOR plus 2.21 per cent . |
NON-CONTROLLING INTERESTS (Tabl
NON-CONTROLLING INTERESTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Noncontrolling Interest [Abstract] | |
Schedule of Non-Controlling Interests | The Company's Non-controlling interests included in the Consolidated balance sheet are as follows: at December 31 2017 2016 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,852 1,596 Non-controlling interest in Portland Natural Gas Transmission System — 130 1,852 1,726 The Company's Net income attributable to non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 220 215 (13 ) Non-controlling interest in Portland Natural Gas Transmission System 1 9 20 19 Non-controlling interest in Columbia Pipeline Partners LP 2 9 17 — 238 252 6 1 Non-controlling interest in 2017 for the period January 1 to May 31 when TCPL sold its remaining interest in PNGTS to TC PipeLines, LP. Refer to Note 25, Other acquisitions and dispositions for further information. 2 Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of CPPL. |
COMMON SHARES (Tables)
COMMON SHARES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |
Schedule of Common Shares | Number of Shares Amount (thousands) (millions of Canadian $) Outstanding at January 1, 2015 779,479 16,320 Issuance of common shares for cash — — Outstanding at December 31, 2015 779,479 16,320 Issuance of common shares for cash 1 79,656 4,661 Outstanding at December 31, 2016 859,135 20,981 Issuance of common shares for cash 12,499 780 Outstanding at December 31, 2017 871,634 21,761 1 Proceeds of $2.5 billion were used to finance the acquisition of Columbia and proceeds of $2.0 billion were used to repay a portion of the US$6.9 billion acquisition bridge facilities. |
Schedule of Options Valuation Assumptions | TransCanada used a binomial model for determining the fair value of options granted applying the following weighted average assumptions: year ended December 31 2017 2016 2015 Weighted average fair value $7.22 $5.67 $6.45 Expected life (years) 5.7 5.8 5.8 Interest rate 1.2 % 0.7 % 1.1 % Volatility 1 18 % 21 % 18 % Dividend yield 3.6 % 4.9 % 3.7 % Forfeiture rate 2 — 5 % 5 % 1 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. 2 On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance. Refer to Note 3, Accounting changes, for further information. |
Schedule of Additional Option Information | period. The following table summarizes additional stock option inf |
OTHER COMPREHENSIVE (LOSS)_IN55
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Components of Other Comprehensive Income/(Loss) | Components of Other comprehensive (loss)/income, including the portion attributable to non-controlling interests and related tax effects, are as follows: year ended December 31, 2017 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation losses on net investment in foreign operations (746 ) (3 ) (749 ) Reclassification of foreign currency translation gains on net investment on disposal of foreign operations (77 ) — (77 ) Change in fair value of net investment hedges — — — Change in fair value of cash flow hedges 3 — 3 Reclassification to net income of gains and losses on cash flow hedges (3 ) 1 (2 ) Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (14 ) 3 (11 ) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 21 (5 ) 16 Other comprehensive loss on equity investments (141 ) 35 (106 ) Other Comprehensive Loss (957 ) 31 (926 ) year ended December 31, 2016 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 3 — 3 Change in fair value of net investment hedges (14 ) 4 (10 ) Change in fair value of cash flow hedges 44 (14 ) 30 Reclassification to net income of gains and losses on cash flow hedges 71 (29 ) 42 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (38 ) 12 (26 ) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 22 (6 ) 16 Other comprehensive loss on equity investments (117 ) 30 (87 ) Other Comprehensive Loss (29 ) (3 ) (32 ) year ended December 31, 2015 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 798 15 813 Change in fair value of net investment hedges (505 ) 133 (372 ) Change in fair value of cash flow hedges (92 ) 35 (57 ) Reclassification to net income of gains and losses on cash flow hedges 144 (56 ) 88 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 74 (23 ) 51 Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 41 (9 ) 32 Other comprehensive income on equity investments 62 (15 ) 47 Other Comprehensive Income 522 80 602 |
Schedule of Changes in Accumulated Other Comprehensive Income | The changes in AOCI by component are as follows: Currency Translation Adjustments Cash Flow Hedges Pension and Other Post-Retirement Benefit Plan Adjustments Equity Investments Total 1 AOCI balance at January 1, 2015 (518 ) (128 ) (281 ) (308 ) (1,235 ) Other comprehensive income/(loss) before reclassifications 2 135 (57 ) 51 33 162 Amounts reclassified from AOCI — 88 32 14 134 Net current period other comprehensive income 135 31 83 47 296 AOCI balance at December 31, 2015 (383 ) (97 ) (198 ) (261 ) (939 ) Other comprehensive income/(loss) before reclassifications 2 7 27 (26 ) (101 ) (93 ) Amounts reclassified from AOCI — 42 16 14 72 Net current period other comprehensive income/(loss) 7 69 (10 ) (87 ) (21 ) AOCI balance at December 31, 2016 (376 ) (28 ) (208 ) (348 ) (960 ) Other comprehensive (loss)/income before reclassifications 2,3 (590 ) (1 ) (11 ) (117 ) (719 ) Amounts reclassified from AOCI 4 (77 ) (2 ) 16 11 (52 ) Net current period other comprehensive (loss)/income (667 ) (3 ) 5 (106 ) (771 ) AOCI balance at December 31, 2017 (1,043 ) (31 ) (203 ) (454 ) (1,731 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 In 2017 , other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $159 million ( 2016 – $14 million losses; 2015 – $306 million gains) and gains of $4 million ( 2016 – $3 million gains and 2015 – nil ), respectively. 3 Other comprehensive (loss)/income before reclassification on pension and other post-retirement benefit plan adjustments includes a $27 million reduction on settlements and curtailments. 4 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $19 million ( $14 million , net of tax) at December 31, 2017 . These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. |
Schedule of Reclassifications out of Accumulated Other Comprehensive Income | Details about reclassifications out of AOCI into the Consolidated statement of income are as follows: Amounts Reclassified 1 Affected Line Item year ended December 31 2017 2016 2015 (millions of Canadian $) Cash flow hedges Commodities 20 (57 ) (128 ) Revenues (Energy) Interest (17 ) (14 ) (16 ) Interest expense 3 (71 ) (144 ) Total before tax (1 ) 29 56 Income tax (recovery)/expense 2 (42 ) (88 ) Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial loss and past service cost (15 ) (22 ) (41 ) Plant operating costs and other 2 Settlement charge (2 ) — — Plant operating costs and other 2 (17 ) (22 ) (41 ) Total before tax 5 6 9 Income tax (recovery)/expense (12 ) (16 ) (32 ) Net of tax Equity investments Equity income (15 ) (19 ) (19 ) Income from equity investments 4 5 5 Income tax (recovery)/expense (11 ) (14 ) (14 ) Net of tax Currency translation adjustments Realization of foreign currency translation gains on disposal of foreign operations 77 — — Gain/(loss) on sale of assets held for sale/sold — — — Income tax (recovery)/expense 77 — — Net of tax 1 All amounts in parentheses indicate expenses to the Consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost. Refer to Note 22, Employee post-retirement benefits for further information. |
EMPLOYEE POST-RETIREMENT BENE56
EMPLOYEE POST-RETIREMENT BENEFITS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
Schedule of Payments for Defined Benefit Plans | Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2017 2016 2015 (millions of Canadian $) DB Plans 163 111 96 Other post-retirement benefit plans 7 8 6 Savings and DC Plans 42 52 41 212 171 143 |
Schedule of Change in Benefit Obligations, Change in Plan Assets, and Funded Status | The Company's funded status at December 31 is comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,456 2,780 372 225 Service cost 113 107 4 3 Interest cost 135 127 14 13 Employee contributions 5 4 3 2 Benefits paid (166 ) (204 ) (19 ) (16 ) Actuarial loss/(gain) 253 111 19 (8 ) Acquisition of Columbia — 527 — 151 Curtailment (14 ) — (2 ) — Settlement (66 ) 2 — — Foreign exchange rate changes (70 ) 2 (16 ) 2 Benefit obligation – end of year 3,646 3,456 375 372 Change in Plan Assets Plan assets at fair value – beginning of year 3,208 2,591 354 45 Actual return on plan assets 358 227 45 14 Employer contributions 2 163 111 7 8 Employee contributions 5 4 3 2 Benefits paid (166 ) (204 ) (19 ) (16 ) Acquisition of Columbia — 475 — 294 Settlement (57 ) — — — Foreign exchange rate changes (60 ) 4 (25 ) 7 Plan assets at fair value – end of year 3,451 3,208 365 354 Funded Status – Plan Deficit (195 ) (248 ) (10 ) (18 ) 1 The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation. 2 Excludes $260 million in letters of credit provided to the Canadian DB Plan for funding purposes ( 2016 – $233 million ). |
Schedule of Amounts Recognized in the Balance Sheet for its DB Plans and Other Post-Retirement Benefits Plans | The amounts recognized in the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans are as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Intangible and other assets (Note 12) — — 193 189 Accounts payable and other (1 ) — (8 ) (7 ) Other long-term liabilities (Note 15) (194 ) (248 ) (195 ) (200 ) (195 ) (248 ) (10 ) (18 ) |
Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets | Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2017 2016 Projected benefit obligation 1 (3,646 ) (3,456 ) (203 ) (207 ) Plan assets at fair value 3,451 3,208 — — Funded Status – Plan Deficit (195 ) (248 ) (203 ) (207 ) 1 The projected benefit obligation for the pension benefit plan differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels. |
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for All DB Plans | The funded status based on the accumulated benefit obligation for all DB Plans is as follows: at December 31 2017 2016 (millions of Canadian $) Accumulated benefit obligation (3,372 ) (3,202 ) Plan assets at fair value 3,451 3,208 Funded Status – Plan Surplus 79 6 |
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for Plans Not Fully Funded | Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded. at December 31 2017 2016 (millions of Canadian $) Accumulated benefit obligation (944 ) (990 ) Plan assets at fair value 925 868 Funded Status – Plan Deficit (19 ) (122 ) |
Schedule of Weighted Average Asset Allocations and Target Allocations by Asset Category | The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: Percentage of Target Allocations at December 31 2017 2016 2017 Debt securities 30 % 31 % 25% to 40% Equity securities 64 % 63 % 45% to 75% Alternatives 6 % 6 % 5% to 15% 100 % 100 % |
Schedule of Allocation of Plan Assets, Employer and Related Party Securities | Debt and equity securities include the Company's debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2017 2016 2017 2016 Debt securities 7 9 0.2 % 0.2 % Equity securities 3 4 0.1 % 0.1 % |
Schedule of Plan Assets for DB Plans and Other Post-Retirement Benefits Measured at Fair Value | The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. For further information on the fair value hierarchy, refer to Note 23, Risk management and financial instruments. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 Asset Category Cash and Cash Equivalents 44 22 17 12 — — 61 34 2 1 Equity Securities: Canadian 410 388 151 143 — — 561 531 15 15 U.S. 543 504 354 476 — — 897 980 24 27 International 45 39 322 327 — — 367 366 10 10 Global — — 301 235 — — 301 235 8 7 Emerging 8 7 147 137 — — 155 144 4 4 Fixed Income Securities: Canadian Bonds: Federal — — 193 192 — — 193 192 5 5 Provincial — — 194 179 — — 194 179 5 5 Municipal — — 8 8 — — 8 8 — — Corporate — — 122 126 — — 122 126 3 4 U.S. Bonds: Federal — — 244 82 — — 244 82 6 2 State — — 41 41 — — 41 41 1 1 Municipal — — 4 39 — — 4 39 — 1 Corporate — — 234 188 — — 234 188 6 5 International: Government — — 4 6 — — 4 6 — — Corporate — — 5 21 — — 5 21 — 1 Mortgage backed — — 73 62 — — 73 62 2 2 Other Investments: Real estate — — — — 140 133 140 133 4 4 Infrastructure — — — — 70 58 70 58 2 2 Private equity funds — — — — 6 8 6 8 — — Funds held on deposit 136 129 — — — — 136 129 3 4 1,186 1,089 2,414 2,274 216 199 3,816 3,562 100 100 |
Schedule of the Net Change in the Level III Fair Value Category | The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2015 14 Purchases and sales 183 Realized and unrealized gains 2 Balance at December 31, 2016 199 Purchases and sales 11 Realized and unrealized gains 6 Balance at December 31, 2017 216 |
Schedule of Estimated Future Benefit Payments | The following are estimated future benefit payments, which reflect expected future service: (millions of Canadian $) Pension Benefits Other Post- Retirement Benefits 2018 181 19 2019 187 20 2020 190 20 2021 196 20 2022 200 20 2023 to 2027 1,054 98 |
Schedule of Weighted Average Assumptions Used in Calculating Benefit Obligation | The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows: Pension Other Post-Retirement at December 31 2017 2016 2017 2016 Discount rate 3.60 % 4.00 % 3.70 % 4.15 % Rate of compensation increase 3.00 % 1.20 % — — |
Schedule of Significant Weighted Average Actuarial Assumptions Adopted in Measuring Net Benefit Plan Costs | The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows: Pension Other Post-Retirement year ended December 31 2017 2016 2015 2017 2016 2015 Discount rate 3.95 % 4.20 % 4.15 % 4.15 % 4.30 % 4.20 % Expected long-term rate of return on plan assets 6.50 % 6.70 % 6.95 % 6.05 % 5.95 % 4.60 % Rate of compensation increase 1.20 % 0.80 % 3.15 % — — — |
Schedule of Effects of a 1% Change in Assumed Health Care Cost Trend Rates | A one per cent change in assumed health care cost trend rates would have the following effects: (millions of Canadian $) Increase Decrease Effect on total of service and interest cost components 1 (1 ) Effect on post-retirement benefit obligation 15 (13 ) |
Schedule of Net Benefit Costs | The Company's net benefit cost recognized is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2017 2016 2015 2017 2016 2015 Service cost 108 107 108 4 3 3 Interest cost 122 127 115 14 13 10 Expected return on plan assets (178 ) (175 ) (155 ) (21 ) (11 ) (2 ) Amortization of actuarial loss 14 20 35 1 2 3 Amortization of past service cost — — 2 — — 1 Amortization of regulatory asset 37 27 23 1 1 1 Amortization of transitional obligation related to regulated business — — — — 2 2 Settlement charge – regulatory asset 2 — — — — — Settlement charge – AOCI 2 — — — — — Net Benefit Cost Recognized 107 106 128 (1 ) 10 18 |
Schedule of the Pre-Tax Amounts Recognized in AOCI | Pre-tax amounts recognized in AOCI were as follows: 2017 2016 2015 at December 31 Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits (millions of Canadian $) Net loss 273 11 270 21 247 28 |
Schedule of the Pre-Tax Amounts Recognized in OCI | Pre-tax amounts recognized in OCI were as follows: 2017 2016 2015 at December 31 Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits (millions of Canadian $) Amortization of net loss from AOCI to OCI (18 ) (1 ) (20 ) (2 ) (34 ) (4 ) Amortization of prior service costs from AOCI to OCI — — — — (2 ) (1 ) Curtailment (14 ) (2 ) — — — — Settlement (11 ) — — — — — Funded status adjustment 46 (7 ) 43 (5 ) (67 ) (7 ) 3 (10 ) 23 (7 ) (103 ) (12 ) |
RISK MANAGEMENT AND FINANCIAL57
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative financial instruments | |
Summary of Derivative Instruments | The maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows: at December 31, 2017 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 66,132 133 6 — — Sales 1 42,836 135 7 — — Millions of U.S. dollars — — — US 2,931 US 2,300 Millions of Mexican pesos — — — MXN 100 — Maturity dates 2018-2022 2018-2021 2018 2018 2018-2022 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. at December 31, 2016 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 86,887 182 6 — — Sales 1 58,561 147 6 — — Millions of U.S. dollars — — — US 2,394 US 1,550 Maturity dates 2017-2021 2017-2020 2017 2017 2017-2019 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively . |
Schedule of Financial Instruments | The following table details the fair value of non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy: 2017 2016 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Long-term debt, including current portion 1,2 (Note 17) (34,741 ) (40,180 ) (40,150 ) (45,047 ) Junior subordinated notes (Note 18) (7,007 ) (7,233 ) (3,931 ) (3,825 ) (41,748 ) (47,413 ) (44,081 ) (48,872 ) 1 Long-term debt is recorded at amortized cost, except for US$1.1 billion ( 2016 – US$850 million ) that is attributed to hedged risk and recorded at fair value. 2 Net income in 2017 included unrealized gains of $4 million ( 2016 – gains of $2 million ) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.1 billion of long-term debt at December 31, 2017 ( 2016 – US$850 million ). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. Available for Sale Assets Summary The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets: 2017 2016 LMCI Restricted Investments Other Restricted Investments 2 LMCI Restricted Investments Other Restricted Investments 2 (millions of Canadian $) Fair value 1 Fixed income securities (maturing within 1 year) — 23 — 19 Fixed income securities (maturing within 1-5 years) — 107 — 117 Fixed income securities (maturing within 5-10 years) 14 — 9 — Fixed income securities (maturing after 10 years) 790 — 513 — 804 130 522 136 1 Available for sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet. 2 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. The balance sheet classification of the fair value of derivative instruments as at December 31, 2017 is as follows: at December 31, 2017 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 1 — — 249 250 Foreign exchange — — 8 70 78 Interest rate 3 — — 1 4 4 — 8 320 332 Intangible and other assets (Note 12) Commodities 2 — — — 69 69 Interest rate 4 — — — 4 4 — — 69 73 Total Derivative Assets 8 — 8 389 405 Accounts payable and other (Note 14) Commodities 2 (6 ) — — (208 ) (214 ) Foreign exchange — — (159 ) (10 ) (169 ) Interest rate — (4 ) — — (4 ) (6 ) (4 ) (159 ) (218 ) (387 ) Other long-term liabilities (Note 15) Commodities 2 (2 ) — — (26 ) (28 ) Foreign exchange — — (43 ) — (43 ) Interest rate — (1 ) — — (1 ) (2 ) (1 ) (43 ) (26 ) (72 ) Total Derivative Liabilities (8 ) (5 ) (202 ) (244 ) (459 ) Total Derivatives — (5 ) (194 ) 145 (54 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. The balance sheet classification of the fair value of derivative instruments as at December 31, 2016 is as follows: at December 31, 2016 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 6 — — 351 357 Foreign exchange — — 6 10 16 Interest rate 1 1 — 1 3 7 1 6 362 376 Intangible and other assets (Note 12) Commodities 2 4 — — 118 122 Foreign exchange — — 10 — 10 Interest rate 1 — — — 1 5 — 10 118 133 Total Derivative Assets 12 1 16 480 509 Accounts payable and other (Note 14) Commodities 2 — — — (330 ) (330 ) Foreign exchange — — (237 ) (38 ) (275 ) Interest rate (1 ) (1 ) — — (2 ) (1 ) (1 ) (237 ) (368 ) (607 ) Other long-term liabilities (Note 15) Commodities 2 — — — (118 ) (118 ) Foreign exchange — — (211 ) — (211 ) Interest rate — (1 ) — — (1 ) — (1 ) (211 ) (118 ) (330 ) Total Derivative Liabilities (1 ) (2 ) (448 ) (486 ) (937 ) Total Derivatives 11 (1 ) (432 ) (6 ) (428 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. |
Unrealized Gain (Loss) on Investments | 2017 2016 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized (losses)/gains in the year ended December 31 (3 ) 1 (28 ) (1 ) Net realized (losses)/gains in the year ended December 31 3 (1 ) — — — 1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. 2 Unrealized gains and losses on other restricted investments are included in OCI. 3 The realized gains or losses on the sale of LMCI restricted investment securities are determined using the average cost basis. |
Realized Gain (Loss) on Investments | 2017 2016 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized (losses)/gains in the year ended December 31 (3 ) 1 (28 ) (1 ) Net realized (losses)/gains in the year ended December 31 3 (1 ) — — — 1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. 2 Unrealized gains and losses on other restricted investments are included in OCI. 3 The realized gains or losses on the sale of LMCI restricted investment securities are determined using the average cost basis. |
Summary of Unrealized and Realized Gains/(Losses) of Derivative Instruments | The following summary does not include hedges of the net investment in foreign operations. year ended December 31 2017 2016 2015 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 2 62 123 (37 ) Foreign exchange 88 25 (21 ) Interest rate (1 ) — — Amount of realized (losses)/gains in the year Commodities (107 ) (204 ) (151 ) Foreign exchange 18 62 (112 ) Interest rate 1 — — Derivative instruments in hedging relationships Amount of realized gains/(losses) in the year Commodities 23 (167 ) (179 ) Foreign exchange 5 (101 ) — Interest rate 1 4 8 1 Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively. 2 In 2017 , there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur ( 2016 – net loss of $42 million ). |
Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships | The components of OCI (Note 21) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: year ended December 31 2017 2016 2015 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI (effective portion) 1 Commodities (1 ) 39 (92 ) Interest rate 4 5 — 3 44 (92 ) Reclassification of (losses)/gains on derivative instruments from AOCI to Net income (effective portion) 1 Commodities 2 (20 ) 57 128 Interest rate 3 17 14 16 (3 ) 71 144 1 No amounts have been excluded from the assessment of hedge effectiveness. In 2017 and 2016 , there were no gains or losses included in Net Income related to ineffective portions. Amounts in parentheses indicate losses recorded to OCI and AOCI. 2 Reported within Revenues on the Consolidated statement of income. 3 Reported within Interest expense on the Consolidated statement of income. |
Schedule of Offsetting Assets | The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2017 : at December 31, 2017 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 319 (198 ) 121 Foreign exchange 78 (56 ) 22 Interest rate 8 (1 ) 7 405 (255 ) 150 Derivative – Liability Commodities (242 ) 198 (44 ) Foreign exchange (212 ) 56 (156 ) Interest rate (5 ) 1 (4 ) (459 ) 255 (204 ) 1 Amounts available for offset do not include cash collateral pledged or received. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2016 : at December 31, 2016 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 479 (362 ) 117 Foreign exchange 26 (26 ) — Interest rate 4 (1 ) 3 509 (389 ) 120 Derivative – Liability Commodities (448 ) 362 (86 ) Foreign exchange (486 ) 26 (460 ) Interest rate (3 ) 1 (2 ) (937 ) 389 (548 ) 1 Amounts available for offset do not include cash collateral pledged or received. |
Schedule of Offsetting Liabilities | The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2017 : at December 31, 2017 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 319 (198 ) 121 Foreign exchange 78 (56 ) 22 Interest rate 8 (1 ) 7 405 (255 ) 150 Derivative – Liability Commodities (242 ) 198 (44 ) Foreign exchange (212 ) 56 (156 ) Interest rate (5 ) 1 (4 ) (459 ) 255 (204 ) 1 Amounts available for offset do not include cash collateral pledged or received. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2016 : at December 31, 2016 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 479 (362 ) 117 Foreign exchange 26 (26 ) — Interest rate 4 (1 ) 3 509 (389 ) 120 Derivative – Liability Commodities (448 ) 362 (86 ) Foreign exchange (486 ) 26 (460 ) Interest rate (3 ) 1 (2 ) (937 ) 389 (548 ) 1 Amounts available for offset do not include cash collateral pledged or received. |
Schedule of Fair Value of Assets and Liabilities Measured on a Recurring Basis | The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. Levels How fair value has been determined Level I Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis. Level II Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances. Level III Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category includes long-dated commodity transactions in certain markets where liquidity is low and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions. Valuation of options is based on the Black-Scholes pricing model. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which significant inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II. The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2017 , are categorized as follows: at December 31, 2017 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 21 283 15 319 Foreign exchange — 78 — 78 Interest rate — 8 — 8 Derivative Instrument Liabilities: Commodities (27 ) (193 ) (22 ) (242 ) Foreign exchange — (212 ) — (212 ) Interest rate — (5 ) — (5 ) (6 ) (41 ) (7 ) (54 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2017 . The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2016 , are categorized as follows: at December 31, 2016 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 134 326 19 479 Foreign exchange — 26 — 26 Interest rate — 4 — 4 Derivative Instrument Liabilities: Commodities (102 ) (343 ) (3 ) (448 ) Foreign exchange — (486 ) — (486 ) Interest rate — (3 ) — (3 ) 32 (476 ) 16 (428 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016 . |
Schedule of Net Change in the Level III Fair Value Category | The following table presents the net change in fair value of derivative assets and liabilities classified in Level III of the fair value hierarchy: (millions of Canadian $, pre-tax) 2017 2016 Balance at beginning of year 16 9 Transfers out of Level III (19 ) (1 ) Total (losses)/gains included in Net income (17 ) 13 Sales (5 ) (3 ) Settlements 18 (2 ) Balance at end of year 1 (7 ) 16 1 Revenues include unrealized losses attributed to derivatives in the Level III category that were still held at December 31, 2017 of $7 million ( 2016 — gains of $7 million ). |
Designated as a net investment hedge | |
Derivative financial instruments | |
Summary of Derivative Instruments | The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows: 2017 2016 at December 31 Fair 1 Notional or Fair 1 Notional or (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019) 2 (199 ) US 1,200 (425 ) US 2,350 U.S. dollar foreign exchange options (maturing 2018) 5 US 500 — — U.S. dollar foreign exchange forward contracts — — (7 ) US 150 (194 ) US 1,700 (432 ) US 2,500 1 Fair value equals carrying value. 2 In 2017 , Net income includes net realized gains of $4 million ( 2016 – gains of $6 million ) related to the interest component of cross-currency swap settlements which are reported within Interest expense. The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2017 2016 (millions of Canadian $, unless otherwise noted) Notional amount 25,400 (US 20,200) 26,600 (US 19,800) Fair value 28,900 (US 23,100) 29,400 (US 21,900) |
CHANGES IN OPERATING WORKING 58
CHANGES IN OPERATING WORKING CAPITAL (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
CHANGES IN OPERATING WORKING CAPITAL | |
Schedule of changes in operating working capital | year ended December 31 2017 2016 2015 (millions of Canadian $) Increase in Accounts receivable (573 ) (487 ) (19 ) Increase in Inventories (38 ) (87 ) (3 ) Decrease/(increase) in Assets held for sale 14 (13 ) — Decrease/(increase) in Other current assets 189 328 (273 ) Increase/(decrease) in Accounts payable and other 149 432 (103 ) Increase in Accrued interest 12 62 91 (Decrease)/increase in Liabilities related to assets held for sale (25 ) 16 — (Increase)/decrease in Operating Working Capital (272 ) 251 (307 ) |
COMMITMENTS, CONTINGENCIES AN59
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Future Annual Payments | Future annual payments under the Company's operating leases for various premises, services and equipment, net of sublease receipts, are approximately as follows: year ended December 31 Minimum Amounts Net (millions of Canadian $) 2018 75 4 71 2019 76 2 74 2020 73 2 71 2021 71 1 70 2022 63 — 63 2023 and thereafter 443 2 441 801 11 790 |
Schedule of Guarantees | The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees is as follows: 2017 2016 year ended December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas ranging to 2020 315 2 805 53 Bruce Power ranging to 2018 88 1 88 1 Other jointly owned entities ranging to 2059 104 13 87 28 507 16 980 82 1 TCPL's share of the potential estimated current or contingent exposure. |
CORPORATE RESTRUCTURING COSTS (
CORPORATE RESTRUCTURING COSTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Restructuring and Related Activities [Abstract] | |
Restructuring and Related Costs | Changes in the restructuring liability were as follows: (millions of Canadian $) Employee Severance Lease Commitments Total Restructuring liability as at December 31, 2015 60 27 87 Restructuring charges — 44 44 Cash payments (24 ) (8 ) (32 ) Restructuring liability as at December 31, 2016 36 63 99 Restructuring charges — 6 6 Cash payments (27 ) (16 ) (43 ) Restructuring Liability as at December 31, 2017 9 53 62 |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | The following amounts are included in Due to affiliate: 2017 2016 (millions of Canadian $) Maturity Date Outstanding December 31 Effective Interest Rate Outstanding December 31 Effective Interest Rate Credit Facility 1 Demand 2,551 3.2 % 2,358 2.7 % 2,551 2,358 1 TCPL has an unsecured $3.0 billion credit facility with TransCanada. Interest on this facility is charged at the prime rate per annum. |
VARIABLE INTEREST ENTITIES (Tab
VARIABLE INTEREST ENTITIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Variable Interest Entity, Primary Beneficiary | |
Variable Interest Entity [Line Items] | |
Schedule of Variable Interest Entities | The Consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations are as follows: at December 31 (millions of Canadian $) 2017 2016 ASSETS Current Assets Cash and cash equivalents 41 77 Accounts receivable 63 71 Inventories 23 25 Other 11 10 138 183 Plant, Property and Equipment 3,535 3,685 Equity Investments 917 606 Goodwill 490 525 Intangible and Other Assets 3 1 5,083 5,000 LIABILITIES Current Liabilities Accounts payable and other 137 80 Dividends payable 1 — Accrued interest 23 21 Current portion of long-term debt 88 76 249 177 Regulatory Liabilities 34 34 Other Long-Term Liabilities 3 4 Deferred Income Tax Liabilities 13 7 Long-Term Debt 3,244 2,827 3,543 3,049 |
Variable Interest Entity, Not Primary Beneficiary | |
Variable Interest Entity [Line Items] | |
Schedule of Variable Interest Entities | The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows: at December 31 (millions of Canadian $) 2017 2016 Balance sheet Equity investments 4,372 4,964 Off-balance sheet Potential exposure to guarantees 171 163 Maximum exposure to loss 4,543 5,127 |
DESCRIPTION OF TCPL'S BUSINESS
DESCRIPTION OF TCPL'S BUSINESS (Details) | 12 Months Ended |
Dec. 31, 2017plantsegmentmikmBcf | |
Segment Reporting Information [Line Items] | |
Number of business segments in which the entity operates | segment | 5 |
Canadian Natural Gas Pipelines | |
Segment Reporting Information [Line Items] | |
Investments of regulated natural gas pipelines (in kilometers) | km | 40,429 |
Investments of regulated natural gas pipelines (in miles) | mi | 25,121 |
U.S. Natural Gas Pipelines | |
Segment Reporting Information [Line Items] | |
Investments of regulated natural gas pipelines (in kilometers) | km | 49,779 |
Investments of regulated natural gas pipelines (in miles) | mi | 30,931 |
Investments of regulated natural gas storage facilities (in billion cubic feet) | Bcf | 535 |
Mexico Natural Gas Pipelines | |
Segment Reporting Information [Line Items] | |
Investments of regulated natural gas pipelines (in kilometers) | km | 1,680 |
Investments of regulated natural gas pipelines (in miles) | mi | 1,044 |
Liquids Pipelines | |
Segment Reporting Information [Line Items] | |
Wholly owned and operated crude oil pipeline systems (in kilometers) | km | 4,874 |
Wholly owned and operated crude oil pipeline systems (in miles) | mi | 3,030 |
Energy | |
Segment Reporting Information [Line Items] | |
Number of electrical power generation plants | plant | 11 |
Non-regulated natural gas storage facilities (in billion cubic feet) | Bcf | 118 |
ACCOUNTING POLICIES (Details)
ACCOUNTING POLICIES (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Employee Post-Retirement Benefits | |
Moving average period of basis used to determine expected return on plan assets (in years) | 5 years |
Corporate | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 3.00% |
Corporate | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 20.00% |
Natural Gas Pipelines | Pipeline | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 1.00% |
Natural Gas Pipelines | Pipeline | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 6.00% |
Midstream | Pipeline | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 170.00% |
Midstream | Pipeline | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 250.00% |
Liquids Pipelines | Pipeline | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 2.00% |
Liquids Pipelines | Pipeline | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 2.50% |
Energy | Power generation and natural gas storage plant, equipment and structures | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 2.00% |
Energy | Power generation and natural gas storage plant, equipment and structures | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 20.00% |
ACCOUNTING CHANGES (Details)
ACCOUNTING CHANGES (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Accounting Standards Update 2016-09, Excess Tax Benefit Component | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Deferred income tax assets, net | CAD 12 | |
Retained Earnings | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Cumulative-effect adjustment | CAD 12 | |
Retained Earnings | Accounting Standards Update 2016-09, Excess Tax Benefit Component | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Cumulative-effect adjustment | CAD 12 |
SEGMENTED INFORMATION (Details)
SEGMENTED INFORMATION (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segmented information | |||
Liquids Pipelines | CAD 2,009 | CAD 1,755 | CAD 1,879 |
Energy | 3,593 | 4,206 | 4,091 |
Revenues | 13,449 | 12,547 | 11,353 |
Income from equity investments | 773 | 514 | 440 |
Plant operating costs and other | (3,906) | (3,861) | (3,303) |
Commodity purchases resold | (2,382) | (2,172) | (2,237) |
Property taxes | (569) | (555) | (517) |
Depreciation and amortization | (2,055) | (1,939) | (1,765) |
Goodwill and other asset impairment charges | (1,257) | (1,388) | (3,745) |
Gain (loss) on assets held for sale/sold | 631 | (833) | (125) |
Segmented earnings/(losses) | 4,684 | 2,313 | 101 |
Interest expense | (2,137) | (1,927) | (1,398) |
Allowance for funds used during construction | 507 | 419 | 295 |
Interest income and other | 183 | 117 | (103) |
Income/(Loss) before Income Taxes | 3,237 | 922 | (1,105) |
Income tax recovery/(expense) | 107 | (349) | (35) |
Net Income/(Loss) | 3,344 | 573 | (1,140) |
Net income attributable to non-controlling interests | (238) | (252) | (6) |
Net Income/(Loss) Attributable to Controlling Interests and to Common Shares | 3,106 | 321 | (1,146) |
Capital spending | |||
Capital expenditures | 7,383 | 5,007 | 3,918 |
Capital projects in development | 146 | 295 | 511 |
Contributions to equity investments | 1,681 | 765 | 493 |
Capital spending | 9,210 | 6,067 | 4,922 |
Assets | 86,010 | 87,941 | |
GEOGRAPHIC INFORMATION | |||
Revenues | 13,449 | 12,547 | 11,353 |
Plant, Property and Equipment | 57,277 | 54,475 | |
Canada – domestic | |||
Segmented information | |||
Revenues | 3,618 | 3,697 | 3,930 |
GEOGRAPHIC INFORMATION | |||
Revenues | 3,618 | 3,697 | 3,930 |
Canada – export | |||
Segmented information | |||
Revenues | 1,255 | 1,177 | 1,292 |
GEOGRAPHIC INFORMATION | |||
Revenues | 1,255 | 1,177 | 1,292 |
United States | |||
Segmented information | |||
Revenues | 8,006 | 7,295 | 5,872 |
GEOGRAPHIC INFORMATION | |||
Revenues | 8,006 | 7,295 | 5,872 |
Plant, Property and Equipment | 30,693 | 29,414 | |
Mexico | |||
Segmented information | |||
Revenues | 570 | 378 | 259 |
GEOGRAPHIC INFORMATION | |||
Revenues | 570 | 378 | 259 |
Plant, Property and Equipment | 4,952 | 4,530 | |
Canadian | |||
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 21,632 | 20,531 | |
Intersegment Eliminations | |||
Segmented information | |||
Revenues | 0 | 0 | 0 |
GEOGRAPHIC INFORMATION | |||
Revenues | 0 | 0 | 0 |
Corporate | |||
Segmented information | |||
Revenues | (51) | (56) | (47) |
Income from equity investments | 63 | 0 | 0 |
Plant operating costs and other | (51) | (64) | (105) |
Commodity purchases resold | 0 | 0 | 0 |
Property taxes | 0 | 0 | 0 |
Depreciation and amortization | 0 | 0 | 0 |
Goodwill and other asset impairment charges | 0 | 0 | 0 |
Gain (loss) on assets held for sale/sold | 0 | 0 | 0 |
Segmented earnings/(losses) | (39) | (120) | (152) |
Capital spending | |||
Capital expenditures | 41 | 33 | 64 |
Capital projects in development | 0 | 0 | 0 |
Contributions to equity investments | 0 | 0 | 0 |
Capital spending | 41 | 33 | 64 |
Assets | 3,551 | 2,625 | |
GEOGRAPHIC INFORMATION | |||
Revenues | (51) | (56) | (47) |
Plant, Property and Equipment | 243 | 280 | |
Canadian Natural Gas Pipelines | |||
Segmented information | |||
Natural Gas Pipelines | 3,693 | 3,682 | 3,680 |
Canadian Natural Gas Pipelines | Operating segments | |||
Segmented information | |||
Natural Gas Pipelines | 3,693 | 3,682 | 3,680 |
Income from equity investments | 11 | 12 | 12 |
Plant operating costs and other | (1,300) | (1,245) | (1,204) |
Commodity purchases resold | 0 | 0 | 0 |
Property taxes | (260) | (267) | (272) |
Depreciation and amortization | (908) | (875) | (849) |
Goodwill and other asset impairment charges | 0 | 0 | 0 |
Gain (loss) on assets held for sale/sold | 0 | 0 | 0 |
Segmented earnings/(losses) | 1,236 | 1,307 | 1,367 |
Capital spending | |||
Capital expenditures | 2,106 | 1,372 | 1,366 |
Capital projects in development | 75 | 153 | 230 |
Contributions to equity investments | 0 | 0 | 0 |
Capital spending | 2,181 | 1,525 | 1,596 |
Assets | 16,904 | 15,816 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 14,424 | 13,217 | |
Canadian Natural Gas Pipelines | Intersegment Eliminations | |||
Segmented information | |||
Natural Gas Pipelines | 0 | 0 | 0 |
U.S. Natural Gas Pipelines | |||
Segmented information | |||
Natural Gas Pipelines | 3,584 | 2,526 | 1,444 |
U.S. Natural Gas Pipelines | Operating segments | |||
Segmented information | |||
Natural Gas Pipelines | 3,635 | 2,582 | 1,491 |
Income from equity investments | 240 | 214 | 162 |
Plant operating costs and other | (1,340) | (1,057) | (606) |
Commodity purchases resold | 0 | 0 | 0 |
Property taxes | (181) | (120) | (77) |
Depreciation and amortization | (594) | (425) | (248) |
Goodwill and other asset impairment charges | 0 | 0 | 0 |
Gain (loss) on assets held for sale/sold | 0 | (4) | (125) |
Segmented earnings/(losses) | 1,760 | 1,190 | 597 |
Capital spending | |||
Capital expenditures | 3,712 | 1,517 | 534 |
Capital projects in development | 0 | 0 | 3 |
Contributions to equity investments | 118 | 5 | 0 |
Capital spending | 3,830 | 1,522 | 537 |
Assets | 35,898 | 34,422 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 20,262 | 18,055 | |
U.S. Natural Gas Pipelines | Intersegment Eliminations | |||
Segmented information | |||
Natural Gas Pipelines | 51 | 56 | 47 |
Mexico Natural Gas Pipelines | |||
Segmented information | |||
Natural Gas Pipelines | 570 | 378 | 259 |
Mexico Natural Gas Pipelines | Operating segments | |||
Segmented information | |||
Natural Gas Pipelines | 570 | 378 | 259 |
Income from equity investments | (9) | (3) | 5 |
Plant operating costs and other | (42) | (43) | (51) |
Commodity purchases resold | 0 | 0 | 0 |
Property taxes | 0 | 0 | 0 |
Depreciation and amortization | (93) | (45) | (44) |
Goodwill and other asset impairment charges | 0 | 0 | 0 |
Gain (loss) on assets held for sale/sold | 0 | 0 | 0 |
Segmented earnings/(losses) | 426 | 287 | 169 |
Capital spending | |||
Capital expenditures | 833 | 944 | 566 |
Capital projects in development | 0 | 0 | 0 |
Contributions to equity investments | 1,121 | 198 | 0 |
Capital spending | 1,954 | 1,142 | 566 |
Assets | 5,716 | 5,013 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 4,952 | 4,527 | |
Mexico Natural Gas Pipelines | Intersegment Eliminations | |||
Segmented information | |||
Natural Gas Pipelines | 0 | 0 | 0 |
Liquids Pipelines | |||
Segmented information | |||
Liquids Pipelines | 2,009 | 1,755 | 1,879 |
Liquids Pipelines | Operating segments | |||
Segmented information | |||
Liquids Pipelines | 2,009 | 1,755 | 1,879 |
Income from equity investments | (3) | (1) | 0 |
Plant operating costs and other | (623) | (568) | (492) |
Commodity purchases resold | 0 | 0 | 0 |
Property taxes | (89) | (88) | (79) |
Depreciation and amortization | (309) | (292) | (283) |
Goodwill and other asset impairment charges | (1,236) | 0 | (3,686) |
Gain (loss) on assets held for sale/sold | 0 | 0 | 0 |
Segmented earnings/(losses) | (251) | 806 | (2,661) |
Capital spending | |||
Capital expenditures | 341 | 668 | 1,012 |
Capital projects in development | 71 | 142 | 278 |
Contributions to equity investments | 117 | 327 | 311 |
Capital spending | 529 | 1,137 | 1,601 |
Assets | 15,438 | 16,896 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 13,419 | 14,147 | |
Liquids Pipelines | Intersegment Eliminations | |||
Segmented information | |||
Liquids Pipelines | 0 | 0 | 0 |
Energy | |||
Segmented information | |||
Energy | 3,593 | 4,206 | 4,091 |
Energy | Operating segments | |||
Segmented information | |||
Energy | 3,593 | 4,206 | 4,091 |
Income from equity investments | 471 | 292 | 261 |
Plant operating costs and other | (550) | (884) | (845) |
Commodity purchases resold | (2,382) | (2,172) | (2,237) |
Property taxes | (39) | (80) | (89) |
Depreciation and amortization | (151) | (302) | (341) |
Goodwill and other asset impairment charges | (21) | (1,388) | (59) |
Gain (loss) on assets held for sale/sold | 631 | (829) | 0 |
Segmented earnings/(losses) | 1,552 | (1,157) | 781 |
Capital spending | |||
Capital expenditures | 350 | 473 | 376 |
Capital projects in development | 0 | 0 | 0 |
Contributions to equity investments | 325 | 235 | 182 |
Capital spending | 675 | 708 | 558 |
Assets | 8,503 | 13,169 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | CAD 3,977 | 4,249 | |
Energy | Intersegment Eliminations | |||
Segmented information | |||
Energy | CAD 0 | CAD 0 |
ACQUISITION OF COLUMBIA (Detail
ACQUISITION OF COLUMBIA (Details) $ / shares in Units, shares in Millions, CAD in Millions, $ in Millions | Jul. 01, 2016CADmikmBcf | Jul. 01, 2016USD ($) | Jun. 30, 2017CAD | Jun. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jul. 01, 2016USD ($)mikm$ / sharesBcf | Jun. 30, 2016$ / sharesshares | Dec. 31, 2015CAD |
Business Acquisition [Line Items] | |||||||||||||
Columbia adjustment (Note 5) | CAD 71 | ||||||||||||
Goodwill | CAD 13,958 | 13,084 | CAD 13,958 | CAD 4,812 | |||||||||
Columbian Pipeline | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Percentage of interests acquired | 100.00% | 100.00% | |||||||||||
Purchase price | $ | $ 10,300 | ||||||||||||
Share price (in usd per share) | $ / shares | $ 25.5 | ||||||||||||
Common stock, value, subscriptions | CAD 4,400 | ||||||||||||
Investments of regulated natural gas pipelines (in kilometers) | km | 24,500 | 24,500 | |||||||||||
Investments of regulated natural gas pipelines (in miles) | mi | 15,200 | 15,200 | |||||||||||
Investments of regulated natural gas storage facilities (in billion cubic feet) | Bcf | 285 | 285 | |||||||||||
Decrease in deferred income tax liabilities | CAD 45 | $ 35 | |||||||||||
Columbia adjustment (Note 5) | 71 | 55 | |||||||||||
Goodwill | CAD 10,078 | $ 7,802 | $ 7,747 | $ 7,747 | |||||||||
Estimated increase (decrease) in fair value of acquired liabilities, long-term debt | 300 | $ 231 | CAD 242 | 293 | |||||||||
Common unit, outstanding (in shares) | shares | 53.8 | ||||||||||||
Share price (in USD per share) | $ / shares | $ 15 | ||||||||||||
Acquisition costs | 36 | CAD 36 | |||||||||||
Pro revenue of acquiree since acquisition date | 929 | ||||||||||||
Pro forma information, earnings of acquiree since acquisition date | CAD 132 | ||||||||||||
Columbian Pipeline | U.S. federal | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Effective income tax rate percent | 39.00% | ||||||||||||
Columbian Pipeline | Pension Benefit Plans | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Increase in fair value of regulatory assets | 15 | 12 | |||||||||||
Increase in fair value of other long-term liabilities | 5 | 4 | |||||||||||
Decrease in fair value of intangibles and other assets | 14 | 11 | |||||||||||
Decrease in fair value of regulatory liabilities | 2 | 2 | |||||||||||
Columbian Pipeline | Mining Properties and Mineral Rights | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Increase (decrease) in fair value of property, plant, and equipment | 241 | 185 | CAD (116) | $ (90) | |||||||||
Columbian Pipeline | Natural Gas | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Increase (decrease) in fair value of property, plant, and equipment | CAD 840 | 646 | |||||||||||
Columbian Pipeline | Bridge Facility | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Proceeds from lines of credit | $ | $ 6,900 |
ACQUISITION OF COLUMBIA - Sched
ACQUISITION OF COLUMBIA - Schedule of Assets Acquired and Liabilities Assumed (Details) CAD in Millions, $ in Millions | Jul. 01, 2016CAD | Jul. 01, 2016USD ($) | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Jul. 01, 2016USD ($) | Dec. 31, 2015CAD |
Fair Value | ||||||||
Goodwill (Note 11) | CAD 13,084 | CAD 13,958 | CAD 4,812 | |||||
Exchange rate | 1.30 | 1.30 | ||||||
Columbian Pipeline | ||||||||
Business Acquisition [Line Items] | ||||||||
Purchase Price Consideration | CAD 13,392 | $ 10,294 | ||||||
Fair Value | ||||||||
Current assets | 856 | $ 658 | ||||||
Plant, property and equipment | 9,835 | 7,560 | ||||||
Equity investments | 574 | 441 | ||||||
Regulatory assets | 248 | 190 | ||||||
Intangible and other assets | 175 | 135 | ||||||
Current liabilities | (777) | (597) | ||||||
Regulatory liabilities | (383) | (294) | ||||||
Other long-term liabilities | (187) | (144) | ||||||
Deferred income tax liabilities | (2,098) | (1,613) | ||||||
Long-term debt | (3,878) | (2,981) | ||||||
Non-controlling interests | (1,051) | (808) | ||||||
Fair Value of Net Assets Acquired | 3,314 | 2,547 | ||||||
Goodwill (Note 11) | CAD 10,078 | $ 7,802 | $ 7,747 | $ 7,747 |
ACQUISITION OF COLUMBIA - Sch69
ACQUISITION OF COLUMBIA - Schedule of Fair Value of Debt Acquired (Details) CAD in Millions | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Jul. 01, 2016CAD | Jul. 01, 2016USD ($) | Dec. 31, 2015CAD |
Debt Instrument [Line Items] | |||||||
Goodwill (Note 11) | CAD | CAD 13,084 | CAD 13,958 | CAD 4,812 | ||||
Senior Unsecured Notes, 2.45% Interest Rate | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument, face amount | $ 500,000,000 | ||||||
Senior Unsecured Notes, 3.30% Interest Rate | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument, face amount | 750,000,000 | ||||||
Senior Unsecured Notes, 4.50% Interest Rate | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument, face amount | 1,000,000,000 | ||||||
Senior Unsecured Notes, 5.80% Interest Rate | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument, face amount | 500,000,000 | ||||||
Columbian Pipeline | |||||||
Debt Instrument [Line Items] | |||||||
Goodwill (Note 11) | $ 7,802,000,000 | $ 7,747,000,000 | CAD 10,078 | 7,747,000,000 | |||
Fair Value | CAD 3,878 | 2,981,000,000 | |||||
Columbian Pipeline | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Fair Value | 2,981,000,000 | ||||||
Columbian Pipeline | Senior Unsecured Notes, 2.45% Interest Rate | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Fair Value | $ 506,000,000 | ||||||
Interest Rate | 2.45% | 2.45% | |||||
Columbian Pipeline | Senior Unsecured Notes, 3.30% Interest Rate | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Fair Value | $ 779,000,000 | ||||||
Interest Rate | 3.30% | 3.30% | |||||
Columbian Pipeline | Senior Unsecured Notes, 4.50% Interest Rate | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Fair Value | $ 1,092,000,000 | ||||||
Interest Rate | 4.50% | 4.50% | |||||
Columbian Pipeline | Senior Unsecured Notes, 5.80% Interest Rate | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Fair Value | $ 604,000,000 | ||||||
Interest Rate | 5.80% | 5.80% |
ACQUISITION OF COLUMBIA - Pro F
ACQUISITION OF COLUMBIA - Pro Forma Information (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Business Combinations [Abstract] | ||
Revenues | CAD 13,404 | CAD 13,007 |
Net Income/(Loss) | 715 | (820) |
Net Income/(Loss) Attributable to Controlling Interests and to Common Shares | CAD 431 | CAD (877) |
ASSETS HELD FOR SALE - (Details
ASSETS HELD FOR SALE - (Details) CAD in Millions, $ in Millions | Apr. 19, 2017USD ($) | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD |
Long Lived Assets Held-for-sale [Line Items] | ||||
Proceeds from sale of assets, net of transaction costs | CAD 5,317 | CAD 6 | CAD 0 | |
Disposal group, not discontinued operations | TC Hydro | ||||
Long Lived Assets Held-for-sale [Line Items] | ||||
Proceeds from sale of assets, net of transaction costs | $ | $ 1,070 | |||
Disposal group, not discontinued operations | Ravenswood, Ironwood, Kibby Wind and Ocean State Power | ||||
Long Lived Assets Held-for-sale [Line Items] | ||||
Foreign currency translation gain on assets held for sale | CAD 70 |
OTHER CURRENT ASSETS (Details)
OTHER CURRENT ASSETS (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Other Assets [Abstract] | ||
Fair value of derivative contracts (Note 23) | CAD 332 | CAD 376 |
Prepaid expenses | 109 | 131 |
Cash provided as collateral | 99 | 313 |
Regulatory assets (Note 10) | 23 | 33 |
Other | 128 | 55 |
Other current assets, total | CAD 691 | CAD 908 |
PLANT, PROPERTY AND EQUIPMENT73
PLANT, PROPERTY AND EQUIPMENT (Details) - CAD CAD in Millions | Dec. 31, 2017 | Oct. 05, 2017 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Plant, property and equipment | ||||||
Cost | CAD 81,011 | CAD 81,011 | CAD 76,763 | |||
Accumulated Depreciation | 23,734 | 23,734 | 22,288 | |||
Net Book Value | 57,277 | 57,277 | 54,475 | |||
Energy East, Eastern Mainline and Upland Projects | ||||||
Plant, property and equipment | ||||||
Tangible asset impairment charges | CAD 83 | |||||
Impairment charge, net of tax | CAD 64 | |||||
Keystone XL | ||||||
Plant, property and equipment | ||||||
Impairment charge | CAD 3,686 | |||||
Impairment charge, after tax | 2,891 | |||||
Canadian Natural Gas Pipelines | NGTL System | Under construction | ||||||
Plant, property and equipment | ||||||
Accumulated Depreciation | 0 | 0 | 0 | |||
Energy | Facilities under PPAs | ||||||
Plant, property and equipment | ||||||
Cost | 1,264 | 1,264 | 1,319 | |||
Accumulated Depreciation | 354 | 354 | 335 | |||
Revenues recognized through the sale of electricity | 215 | 212 | CAD 235 | |||
Operating segments | Canadian Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 31,300 | 31,300 | 29,239 | |||
Accumulated Depreciation | 16,876 | 16,876 | 16,022 | |||
Net Book Value | 14,424 | 14,424 | 13,217 | |||
Operating segments | Canadian Natural Gas Pipelines | NGTL System | ||||||
Plant, property and equipment | ||||||
Cost | 15,302 | 15,302 | 13,536 | |||
Accumulated Depreciation | 6,352 | 6,352 | 5,969 | |||
Net Book Value | 8,950 | 8,950 | 7,567 | |||
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 10,153 | 10,153 | 8,814 | |||
Accumulated Depreciation | 4,190 | 4,190 | 3,951 | |||
Net Book Value | 5,963 | 5,963 | 4,863 | |||
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Compression | ||||||
Plant, property and equipment | ||||||
Cost | 3,021 | 3,021 | 2,447 | |||
Accumulated Depreciation | 1,593 | 1,593 | 1,499 | |||
Net Book Value | 1,428 | 1,428 | 948 | |||
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Metering and other | ||||||
Plant, property and equipment | ||||||
Cost | 1,188 | 1,188 | 1,124 | |||
Accumulated Depreciation | 569 | 569 | 519 | |||
Net Book Value | 619 | 619 | 605 | |||
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 14,362 | 14,362 | 12,385 | |||
Accumulated Depreciation | 6,352 | 6,352 | 5,969 | |||
Net Book Value | 8,010 | 8,010 | 6,416 | |||
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 940 | 940 | 1,151 | |||
Net Book Value | 940 | 940 | 1,151 | |||
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | ||||||
Plant, property and equipment | ||||||
Cost | 14,179 | 14,179 | 13,863 | |||
Accumulated Depreciation | 9,161 | 9,161 | 8,780 | |||
Net Book Value | 5,018 | 5,018 | 5,083 | |||
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 9,763 | 9,763 | 9,502 | |||
Accumulated Depreciation | 6,455 | 6,455 | 6,221 | |||
Net Book Value | 3,308 | 3,308 | 3,281 | |||
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Compression | ||||||
Plant, property and equipment | ||||||
Cost | 3,605 | 3,605 | 3,537 | |||
Accumulated Depreciation | 2,499 | 2,499 | 2,361 | |||
Net Book Value | 1,106 | 1,106 | 1,176 | |||
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Metering and other | ||||||
Plant, property and equipment | ||||||
Cost | 655 | 655 | 605 | |||
Accumulated Depreciation | 207 | 207 | 198 | |||
Net Book Value | 448 | 448 | 407 | |||
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 14,023 | 14,023 | 13,644 | |||
Accumulated Depreciation | 9,161 | 9,161 | 8,780 | |||
Net Book Value | 4,862 | 4,862 | 4,864 | |||
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 156 | 156 | 219 | |||
Accumulated Depreciation | 0 | 0 | 0 | |||
Net Book Value | 156 | 156 | 219 | |||
Operating segments | Canadian Natural Gas Pipelines | Other | ||||||
Plant, property and equipment | ||||||
Cost | 1,815 | 1,815 | 1,728 | |||
Accumulated Depreciation | 1,363 | 1,363 | 1,273 | |||
Net Book Value | 452 | 452 | 455 | |||
Operating segments | Canadian Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 1,819 | 1,819 | 1,840 | |||
Accumulated Depreciation | 1,363 | 1,363 | 1,273 | |||
Net Book Value | 456 | 456 | 567 | |||
Operating segments | Canadian Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 4 | 4 | 112 | |||
Accumulated Depreciation | 0 | 0 | 0 | |||
Net Book Value | 4 | 4 | 112 | |||
Operating segments | U.S. Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 24,007 | 24,007 | 21,557 | |||
Accumulated Depreciation | 3,745 | 3,745 | 3,502 | |||
Net Book Value | 20,262 | 20,262 | 18,055 | |||
Operating segments | U.S. Natural Gas Pipelines | Under construction | ||||||
Plant, property and equipment | ||||||
Accumulated Depreciation | 0 | 0 | 0 | |||
Operating segments | U.S. Natural Gas Pipelines | Other | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 1,950 | 1,950 | 2,120 | |||
Accumulated Depreciation | 574 | 574 | 567 | |||
Net Book Value | 1,376 | 1,376 | 1,553 | |||
Operating segments | U.S. Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 8,944 | 8,944 | 8,745 | |||
Accumulated Depreciation | 2,600 | 2,600 | 2,560 | |||
Net Book Value | 6,344 | 6,344 | 6,185 | |||
Operating segments | U.S. Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 8,245 | 8,245 | 8,399 | |||
Accumulated Depreciation | 2,600 | 2,600 | 2,560 | |||
Net Book Value | 5,645 | 5,645 | 5,839 | |||
Operating segments | U.S. Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 699 | 699 | 346 | |||
Accumulated Depreciation | 0 | 0 | 0 | |||
Net Book Value | 699 | 699 | 346 | |||
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | ||||||
Plant, property and equipment | ||||||
Cost | 10,735 | 10,735 | 8,630 | |||
Accumulated Depreciation | 226 | 226 | 79 | |||
Net Book Value | 10,509 | 10,509 | 8,551 | |||
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 3,550 | 3,550 | 3,317 | |||
Accumulated Depreciation | 125 | 125 | 42 | |||
Net Book Value | 3,425 | 3,425 | 3,275 | |||
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Compression | ||||||
Plant, property and equipment | ||||||
Cost | 1,547 | 1,547 | 1,636 | |||
Accumulated Depreciation | 64 | 64 | 29 | |||
Net Book Value | 1,483 | 1,483 | 1,607 | |||
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Metering and other | ||||||
Plant, property and equipment | ||||||
Cost | 2,306 | 2,306 | 2,550 | |||
Accumulated Depreciation | 37 | 37 | 8 | |||
Net Book Value | 2,269 | 2,269 | 2,542 | |||
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 7,403 | 7,403 | 7,503 | |||
Accumulated Depreciation | 226 | 226 | 79 | |||
Net Book Value | 7,177 | 7,177 | 7,424 | |||
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 3,332 | 3,332 | 1,127 | |||
Accumulated Depreciation | 0 | 0 | 0 | |||
Net Book Value | 3,332 | 3,332 | 1,127 | |||
Operating segments | U.S. Natural Gas Pipelines | ANR | ||||||
Plant, property and equipment | ||||||
Cost | 4,328 | 4,328 | 4,182 | |||
Accumulated Depreciation | 919 | 919 | 863 | |||
Net Book Value | 3,409 | 3,409 | 3,319 | |||
Operating segments | U.S. Natural Gas Pipelines | ANR | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 1,427 | 1,427 | 1,468 | |||
Accumulated Depreciation | 365 | 365 | 349 | |||
Net Book Value | 1,062 | 1,062 | 1,119 | |||
Operating segments | U.S. Natural Gas Pipelines | ANR | Compression | ||||||
Plant, property and equipment | ||||||
Cost | 1,582 | 1,582 | 1,494 | |||
Accumulated Depreciation | 286 | 286 | 260 | |||
Net Book Value | 1,296 | 1,296 | 1,234 | |||
Operating segments | U.S. Natural Gas Pipelines | ANR | Metering and other | ||||||
Plant, property and equipment | ||||||
Cost | 961 | 961 | 988 | |||
Accumulated Depreciation | 268 | 268 | 254 | |||
Net Book Value | 693 | 693 | 734 | |||
Operating segments | U.S. Natural Gas Pipelines | ANR | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 3,970 | 3,970 | 3,950 | |||
Accumulated Depreciation | 919 | 919 | 863 | |||
Net Book Value | 3,051 | 3,051 | 3,087 | |||
Operating segments | U.S. Natural Gas Pipelines | ANR | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 358 | 358 | 232 | |||
Net Book Value | 358 | 358 | 232 | |||
Operating segments | U.S. Natural Gas Pipelines | GTN | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 2,107 | 2,107 | 2,221 | |||
Accumulated Depreciation | 822 | 822 | 810 | |||
Net Book Value | 1,285 | 1,285 | 1,411 | |||
Operating segments | U.S. Natural Gas Pipelines | Great Lakes | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 1,988 | 1,988 | 2,106 | |||
Accumulated Depreciation | 1,113 | 1,113 | 1,155 | |||
Net Book Value | 875 | 875 | 951 | |||
Operating segments | U.S. Natural Gas Pipelines | Columbia Gulf | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 1,115 | 1,115 | 880 | |||
Accumulated Depreciation | 37 | 37 | 5 | |||
Net Book Value | 1,078 | 1,078 | 875 | |||
Operating segments | U.S. Natural Gas Pipelines | Midstream | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 1,085 | 1,085 | 1,072 | |||
Accumulated Depreciation | 54 | 54 | 23 | |||
Net Book Value | 1,031 | 1,031 | 1,049 | |||
Operating segments | Mexico Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 5,261 | 5,261 | 4,766 | |||
Accumulated Depreciation | 309 | 309 | 239 | |||
Net Book Value | 4,952 | 4,952 | 4,527 | |||
Operating segments | Mexico Natural Gas Pipelines | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 2,486 | 2,486 | 2,734 | |||
Accumulated Depreciation | 214 | 214 | 180 | |||
Net Book Value | 2,272 | 2,272 | 2,554 | |||
Operating segments | Mexico Natural Gas Pipelines | Compression | ||||||
Plant, property and equipment | ||||||
Cost | 388 | 388 | 422 | |||
Accumulated Depreciation | 30 | 30 | 19 | |||
Net Book Value | 358 | 358 | 403 | |||
Operating segments | Mexico Natural Gas Pipelines | Metering and other | ||||||
Plant, property and equipment | ||||||
Cost | 522 | 522 | 502 | |||
Accumulated Depreciation | 65 | 65 | 40 | |||
Net Book Value | 457 | 457 | 462 | |||
Operating segments | Mexico Natural Gas Pipelines | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 3,396 | 3,396 | 3,658 | |||
Accumulated Depreciation | 309 | 309 | 239 | |||
Net Book Value | 3,087 | 3,087 | 3,419 | |||
Operating segments | Mexico Natural Gas Pipelines | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 1,865 | 1,865 | 1,108 | |||
Accumulated Depreciation | 0 | 0 | 0 | |||
Net Book Value | 1,865 | 1,865 | 1,108 | |||
Operating segments | Liquids Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 14,952 | 14,952 | 15,455 | |||
Accumulated Depreciation | 1,533 | 1,533 | 1,308 | |||
Net Book Value | 13,419 | 13,419 | 14,147 | |||
Operating segments | Liquids Pipelines | Keystone Pipeline System | ||||||
Plant, property and equipment | ||||||
Cost | 13,794 | 13,794 | 14,500 | |||
Accumulated Depreciation | 1,529 | 1,529 | 1,308 | |||
Net Book Value | 12,265 | 12,265 | 13,192 | |||
Operating segments | Liquids Pipelines | Keystone Pipeline System | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 9,002 | 9,002 | 10,572 | |||
Accumulated Depreciation | 992 | 992 | 901 | |||
Net Book Value | 8,010 | 8,010 | 9,671 | |||
Operating segments | Liquids Pipelines | Keystone Pipeline System | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 13,338 | 13,338 | 14,021 | |||
Accumulated Depreciation | 1,529 | 1,529 | 1,308 | |||
Net Book Value | 11,809 | 11,809 | 12,713 | |||
Operating segments | Liquids Pipelines | Keystone Pipeline System | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 456 | 456 | 479 | |||
Accumulated Depreciation | 0 | 0 | 0 | |||
Net Book Value | 456 | 456 | 479 | |||
Operating segments | Liquids Pipelines | Keystone Pipeline System | Pumping equipment | ||||||
Plant, property and equipment | ||||||
Cost | 1,022 | 1,022 | 928 | |||
Accumulated Depreciation | 152 | 152 | 121 | |||
Net Book Value | 870 | 870 | 807 | |||
Operating segments | Liquids Pipelines | Keystone Pipeline System | Tanks and other | ||||||
Plant, property and equipment | ||||||
Cost | 3,314 | 3,314 | 2,521 | |||
Accumulated Depreciation | 385 | 385 | 286 | |||
Net Book Value | 2,929 | 2,929 | 2,235 | |||
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 1,158 | 1,158 | 955 | |||
Accumulated Depreciation | 4 | 4 | 0 | |||
Net Book Value | 1,154 | 1,154 | 955 | |||
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 748 | 748 | 0 | |||
Accumulated Depreciation | 3 | 3 | 0 | |||
Net Book Value | 745 | 745 | 0 | |||
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 1,111 | 1,111 | 0 | |||
Accumulated Depreciation | 4 | 4 | 0 | |||
Net Book Value | 1,107 | 1,107 | 0 | |||
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 47 | 47 | 955 | |||
Accumulated Depreciation | 0 | 0 | ||||
Net Book Value | 47 | 47 | 955 | |||
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Pumping equipment | ||||||
Plant, property and equipment | ||||||
Cost | 104 | 104 | 0 | |||
Accumulated Depreciation | 0 | 0 | 0 | |||
Net Book Value | 104 | 104 | 0 | |||
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | Tanks and other | ||||||
Plant, property and equipment | ||||||
Cost | 259 | 259 | 0 | |||
Accumulated Depreciation | 1 | 1 | 0 | |||
Net Book Value | 258 | 258 | 0 | |||
Operating segments | Energy | ||||||
Plant, property and equipment | ||||||
Cost | 5,080 | 5,080 | 5,336 | |||
Accumulated Depreciation | 1,103 | 1,103 | 1,087 | |||
Net Book Value | 3,977 | 3,977 | 4,249 | |||
Operating segments | Energy | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 4,052 | 4,052 | 4,607 | |||
Accumulated Depreciation | 1,103 | 1,103 | 1,087 | |||
Net Book Value | 2,949 | 2,949 | 3,520 | |||
Operating segments | Energy | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 1,028 | 1,028 | 729 | |||
Accumulated Depreciation | 0 | 0 | 0 | |||
Net Book Value | 1,028 | 1,028 | 729 | |||
Operating segments | Energy | Natural Gas | ||||||
Plant, property and equipment | ||||||
Cost | 2,645 | 2,645 | 2,696 | |||
Accumulated Depreciation | 743 | 743 | 696 | |||
Net Book Value | 1,902 | 1,902 | 2,000 | |||
Operating segments | Energy | Wind and Solar | ||||||
Plant, property and equipment | ||||||
Cost | 673 | 673 | 1,180 | |||
Accumulated Depreciation | 204 | 204 | 245 | |||
Net Book Value | 469 | 469 | 935 | |||
Operating segments | Energy | Natural Gas Storage and Other | ||||||
Plant, property and equipment | ||||||
Cost | 734 | 734 | 731 | |||
Accumulated Depreciation | 156 | 156 | 146 | |||
Net Book Value | 578 | 578 | 585 | |||
Corporate | ||||||
Plant, property and equipment | ||||||
Cost | 411 | 411 | 410 | |||
Accumulated Depreciation | 168 | 168 | 130 | |||
Net Book Value | 243 | CAD 243 | CAD 280 | |||
Power generation and natural gas storage plant, equipment and structures | ||||||
Plant, property and equipment | ||||||
Impairment charge | 21 | 59 | ||||
Impairment charge, after tax | CAD 16 | 43 | ||||
Significant Unobservable Inputs (Level III) | Keystone XL | ||||||
Plant, property and equipment | ||||||
Estimated fair value | CAD 621 | CAD 621 |
EQUITY INVESTMENTS - Schedule a
EQUITY INVESTMENTS - Schedule and Narrative (Details) $ in Millions | May 01, 2016USD ($) | Oct. 31, 2017CAD | Aug. 31, 2017CAD | Mar. 31, 2016USD ($) | Mar. 31, 2016CAD | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2017USD ($) | Jun. 02, 2017 | Jun. 01, 2017 | Dec. 31, 2016USD ($) |
Equity Investments | ||||||||||||
Income/(Loss) from Equity Investments | CAD 773,000,000 | CAD 514,000,000 | CAD 440,000,000 | |||||||||
Equity Investments | 6,366,000,000 | 6,544,000,000 | ||||||||||
Distributions received from equity investments | 1,332,000,000 | 1,571,000,000 | 802,000,000 | |||||||||
Returns of capital | 362,000,000 | 727,000,000 | 9,000,000 | |||||||||
Undistributed earnings | 198,000,000 | |||||||||||
Contributions to equity investments | CAD 1,681,000,000 | 765,000,000 | CAD 493,000,000 | |||||||||
Iroquois | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 50.00% | 49.35% | 49.35% | |||||||||
Additional ownership acquired (percent) | 0.65% | 4.87% | 4.87% | |||||||||
Contributions to equity investments | $ | $ 7 | $ 54 | ||||||||||
Sur de Texas | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 60.00% | 60.00% | ||||||||||
Contributions to equity investments | CAD 977,000,000 | |||||||||||
TransGas | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 46.50% | |||||||||||
Asset impairment charges | CAD 12,000,000 | |||||||||||
Contract term | 20 years | |||||||||||
Grand Rapids | ||||||||||||
Equity Investments | ||||||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ | $ 105 | $ 86 | ||||||||||
Bruce Power | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 48.50% | |||||||||||
Canadian Natural Gas Pipelines | TQM | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||||
Income/(Loss) from Equity Investments | CAD 11,000,000 | 12,000,000 | CAD 12,000,000 | |||||||||
Equity Investments | CAD 68,000,000 | 71,000,000 | ||||||||||
U.S. Natural Gas Pipelines | Northern Border | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||||
Income/(Loss) from Equity Investments | CAD 87,000,000 | 92,000,000 | 85,000,000 | |||||||||
Equity Investments | CAD 641,000,000 | 597,000,000 | ||||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ | $ 115 | 116 | ||||||||||
U.S. Natural Gas Pipelines | Iroquois | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 50.00% | 50.00% | 0.66% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | CAD 59,000,000 | 54,000,000 | 51,000,000 | |||||||||
Equity Investments | CAD 280,000,000 | 309,000,000 | ||||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ | $ 41 | 48 | ||||||||||
U.S. Natural Gas Pipelines | Millennium | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 47.50% | 47.50% | ||||||||||
Income/(Loss) from Equity Investments | CAD 66,000,000 | 33,000,000 | 0 | |||||||||
Equity Investments | CAD 291,000,000 | 295,000,000 | ||||||||||
U.S. Natural Gas Pipelines | Pennant Midstream | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 47.00% | 47.00% | ||||||||||
Income/(Loss) from Equity Investments | CAD 11,000,000 | 6,000,000 | 0 | |||||||||
Equity Investments | 228,000,000 | 246,000,000 | ||||||||||
U.S. Natural Gas Pipelines | Other | ||||||||||||
Equity Investments | ||||||||||||
Income/(Loss) from Equity Investments | 17,000,000 | 29,000,000 | 26,000,000 | |||||||||
Equity Investments | CAD 92,000,000 | 93,000,000 | ||||||||||
Mexico Natural Gas Pipelines | Sur de Texas | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 60.00% | 60.00% | ||||||||||
Income/(Loss) from Equity Investments | CAD 66,000,000 | (3,000,000) | 0 | |||||||||
Equity Investments | 399,000,000 | 255,000,000 | ||||||||||
Mexico Natural Gas Pipelines | TransGas | ||||||||||||
Equity Investments | ||||||||||||
Income/(Loss) from Equity Investments | (12,000,000) | 0 | 5,000,000 | |||||||||
Equity Investments | 0 | 28,000,000 | ||||||||||
Liquids Pipelines | Other | ||||||||||||
Equity Investments | ||||||||||||
Income/(Loss) from Equity Investments | (20,000,000) | 0 | 0 | |||||||||
Equity Investments | CAD 20,000,000 | 39,000,000 | ||||||||||
Liquids Pipelines | Grand Rapids | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||||
Income/(Loss) from Equity Investments | CAD 17,000,000 | (1,000,000) | 0 | |||||||||
Equity Investments | 996,000,000 | 876,000,000 | ||||||||||
Liquids Pipelines | Canaport Energy East Marine Terminal Limited Partnership | ||||||||||||
Equity Investments | ||||||||||||
Equity Investments | 0 | |||||||||||
Energy | Other | ||||||||||||
Equity Investments | ||||||||||||
Income/(Loss) from Equity Investments | 6,000,000 | 3,000,000 | 5,000,000 | |||||||||
Equity Investments | CAD 63,000,000 | 66,000,000 | ||||||||||
Energy | Bruce Power | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 48.40% | 48.40% | ||||||||||
Income/(Loss) from Equity Investments | CAD 434,000,000 | 293,000,000 | 249,000,000 | |||||||||
Equity Investments | 2,987,000,000 | 3,356,000,000 | ||||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | CAD 902,000,000 | 942,000,000 | ||||||||||
Energy | Portlands Energy | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||||
Income/(Loss) from Equity Investments | CAD 31,000,000 | 33,000,000 | 30,000,000 | |||||||||
Equity Investments | CAD 301,000,000 | 313,000,000 | ||||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ | $ 73 | $ 70 | ||||||||||
Energy | ASTC Power Partnership | ||||||||||||
Equity Investments | ||||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||||
Income/(Loss) from Equity Investments | CAD 0 | (37,000,000) | CAD (23,000,000) | |||||||||
Equity Investments | CAD 0 | CAD 0 | ||||||||||
Energy | Sundance B PPA | ||||||||||||
Equity Investments | ||||||||||||
Asset impairment charges | CAD 29,000,000 | |||||||||||
Asset impairment charge, after tax | CAD 21,000,000 | |||||||||||
Energy East, Eastern Mainline and Upland Projects | Liquids Pipelines | ||||||||||||
Equity Investments | ||||||||||||
Asset impairment charges | CAD 20,000,000 |
EQUITY INVESTMENTS - Summarized
EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income | |||
Revenues | CAD 4,913 | CAD 4,336 | CAD 4,337 |
Operating and other expenses | (2,993) | (3,068) | (3,142) |
Net income | 1,636 | 1,080 | 1,046 |
Income/(Loss) from Equity Investments | 773 | 514 | CAD 440 |
Balance Sheet | |||
Current assets | 2,176 | 1,669 | |
Non-current assets | 17,869 | 15,853 | |
Current liabilities | (1,577) | (1,120) | |
Non-current liabilities | CAD (8,217) | CAD (5,867) |
EQUITY INVESTMENTS - Loan Recei
EQUITY INVESTMENTS - Loan Receivable From Affiliate (Details) CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017CAD | Dec. 06, 2017MXN | Apr. 21, 2017MXN | |
Sur de Texas | |||
Equity Investments | |||
Ownership interest (percent) | 60.00% | ||
Joint Venture | Sur de Texas | |||
Equity Investments | |||
Ownership interest (percent) | 60.00% | ||
Loans receivable from affiliates | CAD 919 | ||
Interest income, related party | CAD 34 | ||
Unsecured Loan Facility | Revolving credit facility | Joint Venture | |||
Equity Investments | |||
Credit facility, amount | MXN | MXN 21,300,000,000 | MXN 13,600,000,000 |
RATE-REGULATED BUSINESSES - Nar
RATE-REGULATED BUSINESSES - Narrative (Details) CAD in Millions | 1 Months Ended | 12 Months Ended | ||||
Apr. 30, 2016 | Mar. 31, 2016USD ($) | Dec. 31, 2017 | Dec. 31, 2015 | Dec. 31, 2014CAD | Dec. 31, 2013USD ($) | |
Public Utilities, General Disclosures [Line Items] | ||||||
After-tax annual contribution to reduce revenue requirement | CAD | CAD 20 | |||||
Fixed toll term (in years) | 6 years | |||||
Columbia Gas Transmission | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Maximum cost recovery and return on investment | $ | $ 1,100,000,000 | $ 1,500,000,000 | ||||
Cost recovery and return on investment, recognition period (in years) | 5 years | |||||
Cost recovery and return on investment, additional period (in years) | 3 years | |||||
Canadian Regulated Operations | Canadian Mainline | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved ROE on deemed common equity (percent) | 10.10% | |||||
Deemed common equity (percent) | 40.00% | |||||
National Energy Board | 2015 Revenue Requirement Settlement | NGTL System | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved ROE on deemed common equity (percent) | 10.10% | |||||
Deemed common equity (percent) | 40.00% | |||||
Approved composite depreciation rate | 3.16% | 3.10% | ||||
Period of settlement (in years) | 1 year | |||||
National Energy Board | 2015 Revenue Requirement Settlement | NGTL System | Canadian Regulated Operations | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved ROE on deemed common equity (percent) | 10.10% | |||||
Deemed common equity (percent) | 40.00% |
RATE-REGULATED BUSINESSES - Ass
RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) CAD in Millions, $ in Millions | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2017CAD | Dec. 31, 2006CAD | Dec. 31, 2006USD ($) | Jul. 31, 2016USD ($) |
Regulatory Assets | |||||||
Regulatory Assets | CAD 1,399 | CAD 1,355 | CAD 1,399 | ||||
Less: Current portion included in Other current assets (Note 7) | 23 | 33 | 23 | ||||
Total Regulatory Assets | 1,376 | 1,322 | 1,376 | ||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 4,584 | 2,299 | 4,584 | ||||
Less: Current portion included in Accounts payable and other (Note 14) | 263 | 178 | 263 | ||||
Total Regulatory Liabilities | 4,321 | 2,121 | 4,321 | ||||
Operating and debt-service regulatory liabilities | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 188 | 47 | CAD 188 | ||||
Remaining Recovery/ Settlement Period (years) | 1 year | ||||||
Pensions and other post retirement benefits | ANR PIPELINE COMPANY | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 66 | 141 | CAD 66 | ||||
Long term adjustment account | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 1,142 | 659 | CAD 1,142 | ||||
Remaining Recovery/ Settlement Period (years) | 46 years | ||||||
Pipeline abandonment trust balance | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 825 | 541 | CAD 825 | ||||
Bridging amortization account | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 202 | 451 | CAD 202 | ||||
Remaining Recovery/ Settlement Period (years) | 13 years | ||||||
Cost of removal | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 216 | 226 | CAD 216 | ||||
Deferred income taxes | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 75 | 75 | |||||
Deferred income taxes - U.S. Tax Reform | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 1,659 | 1,659 | |||||
Other | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 47 | 54 | 47 | ||||
Postretirement benefit costs | ANR PIPELINE COMPANY | |||||||
Other disclosures pertaining to regulated assets and liabilities | |||||||
Regulatory liability settlement | 26 | $ 21 | 46 | $ 34 | |||
Amount to be addressed In next settlement | CAD 40 | $ 32 | |||||
Deferred income taxes | |||||||
Regulatory Assets | |||||||
Regulatory Assets | 967 | 861 | 967 | ||||
Deferred income taxes - U.S. Tax Reform | |||||||
Regulatory Assets | |||||||
Regulatory Assets | (27) | CAD (27) | |||||
Operating and debt-service regulatory assets | |||||||
Regulatory Assets | |||||||
Regulatory Assets | 1 | ||||||
Remaining Recovery/ Settlement Period (years) | 1 year | ||||||
Pensions and other post retirement benefits | |||||||
Regulatory Assets | |||||||
Regulatory Assets | 388 | 382 | CAD 388 | ||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 164 | 180 | CAD 164 | ||||
Foreign exchange on long-term debt | |||||||
Regulatory Assets | |||||||
Regulatory Assets | 37 | ||||||
Foreign exchange on long-term debt | Minimum | |||||||
Regulatory Assets | |||||||
Remaining Recovery/ Settlement Period (years) | 1 year | ||||||
Foreign exchange on long-term debt | Maximum | |||||||
Regulatory Assets | |||||||
Remaining Recovery/ Settlement Period (years) | 12 years | ||||||
Other | |||||||
Regulatory Assets | |||||||
Regulatory Assets | CAD 71 | CAD 74 | CAD 71 |
GOODWILL (Details)
GOODWILL (Details) CAD in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2017CAD | Jun. 30, 2017USD ($) | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | |
Goodwill | |||||
Balance at the beginning of the period | CAD 13,958 | CAD 4,812 | |||
Impairment charge | (1,085) | ||||
Foreign exchange rate changes | (945) | 153 | |||
Columbia adjustment (Note 5) | 71 | ||||
Balance at the end of the period | 13,084 | 13,958 | |||
U.S. Natural Gas Pipelines | |||||
Goodwill | |||||
Balance at the beginning of the period | 13,958 | 3,667 | |||
Impairment charge | 0 | ||||
Foreign exchange rate changes | (945) | 213 | |||
Columbia adjustment (Note 5) | 71 | ||||
Balance at the end of the period | 13,084 | 13,958 | |||
Energy | |||||
Goodwill | |||||
Balance at the beginning of the period | 0 | 1,145 | |||
Impairment charge | (1,085) | ||||
Foreign exchange rate changes | 0 | (60) | |||
Columbia adjustment (Note 5) | 0 | ||||
Balance at the end of the period | CAD 0 | 0 | |||
Columbian Pipeline | |||||
Goodwill | |||||
Balance at the beginning of the period | $ | $ 7,747 | ||||
Acquisition of Columbia (Note 5) | 10,078 | ||||
Columbia adjustment (Note 5) | CAD 71 | $ 55 | |||
Balance at the end of the period | $ | $ 7,802 | ||||
Columbian Pipeline | U.S. Natural Gas Pipelines | |||||
Goodwill | |||||
Acquisition of Columbia (Note 5) | 10,078 | ||||
Columbian Pipeline | Energy | |||||
Goodwill | |||||
Acquisition of Columbia (Note 5) | CAD 0 |
GOODWILL - Narrative (Details)
GOODWILL - Narrative (Details) CAD in Millions, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Goodwill recorded on Company's acquisitions in the U.S. | |||||
Goodwill | CAD 13,084 | CAD 13,958 | CAD 4,812 | ||
Asset impairment charges | 1,257 | 1,388 | 3,745 | ||
Energy | |||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||
Goodwill | CAD 0 | 0 | CAD 1,145 | ||
Natural Gas – Ravenswood | Energy | |||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||
Asset impairment charges | 1,085 | ||||
Asset impairment charge, after tax | CAD 656 | ||||
Great Lakes | |||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||
Percentage of fair value in excess of carrying amount (less than) | 10.00% | 10.00% | |||
Goodwill | $ | $ 573 | $ 573 |
INTANGIBLE AND OTHER ASSETS (De
INTANGIBLE AND OTHER ASSETS (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Goodwill and Intangible Assets Disclosure [Abstract] | ||
Capital projects in development | CAD 596 | CAD 2,094 |
Deferred income tax assets (Note 16) | 255 | 313 |
Employee post-retirement benefits (Note 22) | 193 | 189 |
Fair value of derivative contracts (Note 23) | 73 | 133 |
Other | 306 | 218 |
Intangible and other assets | CAD 1,423 | CAD 2,947 |
INTANGIBLE AND OTHER ASSETS - N
INTANGIBLE AND OTHER ASSETS - Narrative (Details) - CAD CAD in Millions | Oct. 05, 2017 | Oct. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Finite-Lived Intangible Assets [Line Items] | ||||||
Gain on contract termination | CAD 634 | |||||
Asset impairment charges | CAD 1,257 | CAD 1,388 | CAD 3,745 | |||
Amortization expense | 9 | CAD 52 | ||||
Sundance A (expires 2017) | Energy | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Asset impairment charges | CAD 92 | 211 | ||||
Asset impairment charge, after tax | CAD 68 | CAD 155 | ||||
Energy East, Eastern Mainline and Upland Projects | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Asset impairment charges | CAD 1,153 | |||||
Asset impairment charge, after tax | CAD 870 |
NOTES PAYABLE (Details)
NOTES PAYABLE (Details) | 12 Months Ended | ||||||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2017MXN | Dec. 31, 2017USD ($) | Dec. 31, 2016MXN | Dec. 31, 2016USD ($) | |
Notes payable | |||||||
Outstanding at December 31 | CAD 1,763,000,000 | CAD 774,000,000 | |||||
Operated affiliates | |||||||
Notes payable | |||||||
Unused Capacity | 500,000,000 | 500,000,000 | |||||
Revolving credit facility | |||||||
Notes payable | |||||||
Cost to maintain | 7,000,000 | 10,000,000 | CAD 11,000,000 | ||||
Revolving and demand credit facilities | |||||||
Notes payable | |||||||
Total Facilities | 11,000,000,000 | 11,100,000,000 | |||||
Mexican subsidiary | Revolving credit facility | |||||||
Notes payable | |||||||
Total Facilities | MXN | MXN 5,000,000 | MXN 0 | |||||
Unused Capacity | MXN | 4,700,000 | ||||||
Mexican subsidiary | Notes payable | |||||||
Notes payable | |||||||
Outstanding at December 31 | CAD 17,000,000 | CAD 0 | MXN 275,000,000 | ||||
Weighted Average Interest Rate per Annum at December 31 | 8.00% | 0.00% | 8.00% | 8.00% | 0.00% | 0.00% | |
TCPL | Revolving credit facility | Maturing December 2022 | |||||||
Notes payable | |||||||
Total Facilities | CAD 3,000,000,000 | CAD 3,000,000,000 | |||||
Unused Capacity | 3,000,000,000 | ||||||
TCPL | Revolving credit facility | Maturing December 2018 | |||||||
Notes payable | |||||||
Total Facilities | $ | $ 2,000,000,000 | $ 2,000,000,000 | |||||
Unused Capacity | $ | $ 2,000,000,000 | ||||||
TCPL | Notes payable | |||||||
Notes payable | |||||||
Outstanding at December 31 | CAD 884,000,000 | CAD 509,000,000 | |||||
Weighted Average Interest Rate per Annum at December 31 | 1.60% | 0.90% | 1.60% | 1.60% | 0.90% | 0.90% | |
TCPL USA | Revolving credit facility | Maturing December 2018 | |||||||
Notes payable | |||||||
Total Facilities | CAD 1,000,000,000 | $ 1,000,000,000 | |||||
Unused Capacity | $ | $ 600,000,000 | ||||||
Columbia | Revolving credit facility | Maturing December 2018 | |||||||
Notes payable | |||||||
Total Facilities | $ | 1,000,000,000 | 1,000,000,000 | |||||
Unused Capacity | $ | 1,000,000,000 | ||||||
TAIL | Revolving credit facility | Maturing December 2018 | |||||||
Notes payable | |||||||
Total Facilities | $ | 500,000,000 | 500,000,000 | |||||
Unused Capacity | $ | 500,000,000 | ||||||
TAIL | Notes payable | |||||||
Notes payable | |||||||
Outstanding at December 31 | CAD 862,000,000 | CAD 265,000,000 | $ 688,000,000 | $ 197,000,000 | |||
Weighted Average Interest Rate per Annum at December 31 | 2.20% | 0.50% | 2.20% | 2.20% | 0.50% | 0.50% | |
TCPL/TCPL USA | Revolving credit facility | |||||||
Notes payable | |||||||
Total Facilities | CAD 1,900,000,000 | CAD 1,900,000,000 | |||||
Unused Capacity | CAD 500,000,000 |
ACCOUNTS PAYABLE AND OTHER (Det
ACCOUNTS PAYABLE AND OTHER (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Payables and Accruals [Abstract] | ||
Trade payables | CAD 2,847 | CAD 2,443 |
Fair value of derivative contracts (Note 23) | 387 | 607 |
Unredeemed shares of Columbia | 312 | 317 |
Regulatory liabilities (Note 10) | 263 | 178 |
Other | 262 | 331 |
Accounts payable and other | CAD 4,071 | CAD 3,876 |
OTHER LONG-TERM LIABILITIES (De
OTHER LONG-TERM LIABILITIES (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred Costs, Noncurrent [Abstract] | ||
Employee post-retirement benefits (Note 22) | CAD 389 | CAD 448 |
Fair value of derivative contracts (Note 23) | 72 | 330 |
Asset retirement obligations | 98 | 108 |
Guarantees (Note 26) | 16 | 82 |
Other | 152 | 215 |
Other Long-Term Liabilities | CAD 727 | CAD 1,183 |
INCOME TAXES - U.S. Tax Reform
INCOME TAXES - U.S. Tax Reform (Details) - CAD CAD in Millions | Dec. 22, 2017 | Dec. 31, 2017 |
Income Tax Contingency [Line Items] | ||
Provisional income tax expense (benefit) | CAD 816 | |
Effect of income tax act on deferred income tax expense | CAD (816) | |
Other Post-Retirement Benefit Plans | ||
Income Tax Contingency [Line Items] | ||
Effect of income tax act on deferred income tax expense | 12 | |
Deferred income taxes - U.S. Tax Reform | ||
Income Tax Contingency [Line Items] | ||
Regulatory Liabilities | CAD 1,686 |
INCOME TAXES - Provision (Detai
INCOME TAXES - Provision (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Current | |||
Canada | CAD 113 | CAD 117 | CAD 45 |
Foreign | 36 | 40 | 92 |
Total | 149 | 157 | 137 |
Deferred | |||
Canada | (203) | 97 | 33 |
Foreign | 751 | 95 | (135) |
Deferred – U.S. Tax Reform | (804) | 0 | 0 |
Total | (256) | 192 | (102) |
Income Tax (Recovery)/Expense | CAD (107) | CAD 349 | CAD 35 |
INCOME TAXES - Geographic Compo
INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Canada | CAD (408) | CAD 304 | CAD (623) |
Foreign | 3,645 | 618 | (482) |
Income/(Loss) before Income Taxes | CAD 3,237 | CAD 922 | CAD (1,105) |
INCOME TAXES - Reconciliation o
INCOME TAXES - Reconciliation of Income Tax (Recovery)/Expense (Details) - CAD | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Income/(loss) before income taxes | CAD 3,237,000,000 | CAD 922,000,000 | CAD (1,105,000,000) |
Federal and provincial statutory tax rate (percent) | 27.00% | 27.00% | 26.00% |
Expected income tax expense/(recovery) | CAD 874,000,000 | CAD 249,000,000 | CAD (287,000,000) |
U.S. Tax Reform | (804,000,000) | 0 | 0 |
Foreign income tax rate differentials | (81,000,000) | (196,000,000) | 14,000,000 |
Income from equity investments and non-controlling interests | (64,000,000) | (68,000,000) | (56,000,000) |
Income tax differential related to regulated operations | (42,000,000) | 81,000,000 | 159,000,000 |
Non-taxable portion of capital gains | (42,000,000) | 0 | 0 |
Asset impairment charges | 34,000,000 | 242,000,000 | 170,000,000 |
Non-deductible amounts | 4,000,000 | 18,000,000 | 0 |
Tax rate and legislative changes | 0 | 0 | 34,000,000 |
Other | 14,000,000 | 23,000,000 | 1,000,000 |
Income Tax (Recovery)/Expense | (107,000,000) | 349,000,000 | 35,000,000 |
Foreign tax rate differential related to asset impairments, amount | CAD 0 | CAD 112,000,000 | CAD 311,000,000 |
INCOME TAXES - Deferred Assets
INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred Income Tax Assets | ||
Tax loss and credit carryforwards | CAD 1,365 | CAD 2,049 |
Difference in accounting and tax bases of impaired assets and assets held for sale | 651 | 1,168 |
Regulatory and other deferred amounts | 512 | 277 |
Unrealized foreign exchange losses on long-term debt | 216 | 446 |
Financial instruments | 10 | 34 |
Other | 180 | 287 |
Deferred tax assets, gross | 2,934 | 4,261 |
Less: Valuation allowance | 832 | 1,336 |
Deferred tax assets, net of Valuation allowance | 2,102 | 2,925 |
Deferred Income Tax Liabilities | ||
Difference in accounting and tax bases of plant, property and equipment and PPAs | 6,240 | 9,015 |
Equity investments | 632 | 905 |
Taxes on future revenue requirement | 238 | 198 |
Other | 140 | 156 |
Deferred tax liabilities, gross | 7,250 | 10,274 |
Net Deferred Income Tax Liabilities | 5,148 | 7,349 |
Deferred Income Tax Assets | ||
Intangible and other assets (Note 12) | 255 | 313 |
Deferred Income Tax Liabilities | ||
Deferred income tax liabilities | 5,403 | 7,662 |
Net Deferred Income Tax Liabilities | CAD 5,148 | CAD 7,349 |
INCOME TAXES - Reconciliation91
INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Unrecognized tax benefit at beginning of year | CAD 15 | CAD 13 | CAD 13 |
Gross increases – tax positions in prior years | 0 | 3 | 2 |
Gross decreases – tax positions in prior years | (1) | 0 | (2) |
Gross increases – tax positions in current year | 2 | 2 | 1 |
Settlement | 0 | (1) | 0 |
Lapse of statutes of limitations | (3) | (2) | (1) |
Unrecognized Tax Benefit at End of Year | CAD 13 | CAD 15 | CAD 13 |
INCOME TAXES - Narrative (Detai
INCOME TAXES - Narrative (Details) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Net operating loss carryforwards | |||||
Tax loss and credit carryforwards | CAD 1,365,000,000 | CAD 2,049,000,000 | |||
Deferred income tax liabilities on the unremitted earnings of foreign investments | 569,000,000 | 481,000,000 | |||
Income tax payments, net of refunds | 247,000,000 | 105,000,000 | CAD 164,000,000 | ||
Interest expense (reversal) reflected within net tax expense | 0 | 0 | 1,000,000 | ||
Income tax penalties expense | 0 | 0 | CAD 0 | ||
Accrued interest expense | 4,000,000 | 4,000,000 | |||
Income tax penalties accrued | 0 | 0 | |||
Canada federal and provincial | |||||
Net operating loss carryforwards | |||||
Unused net operating loss carryforwards | 1,231,000,000 | 1,736,000,000 | |||
Capital loss carryforwards | 0 | ||||
Capital loss carryforwards unrecognized | 668,000,000 | 654,000,000 | |||
Canada federal and provincial | Alternative minimum tax | |||||
Net operating loss carryforwards | |||||
Minimum tax credits | 82,000,000 | 68,000,000 | |||
U.S. federal | |||||
Net operating loss carryforwards | |||||
Unused net operating loss carryforwards | $ | $ 1,800 | $ 2,545 | |||
Tax loss and credit carryforwards | CAD 0 | CAD 0 | |||
Operating loss carryforward unrecognized | $ | 710 | 58 | |||
U.S. federal | Alternative minimum tax | |||||
Net operating loss carryforwards | |||||
Minimum tax credits | $ | 56 | 37 | |||
Mexican Tax Authority | |||||
Net operating loss carryforwards | |||||
Tax loss and credit carryforwards | $ | $ 7 | $ 54 |
LONG-TERM DEBT - Schedule of Ac
LONG-TERM DEBT - Schedule of Activity and Summary of Principal Repayments (Details) | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
Jun. 30, 2017CAD | Jun. 30, 2017USD ($) | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2016USD ($) | |
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 34,677,000,000 | CAD 40,048,000,000 | |||||
Current portion of long-term debt | (2,866,000,000) | (1,838,000,000) | |||||
Unamortized debt discount and issue costs | (174,000,000) | (191,000,000) | |||||
Fair value adjustments | 238,000,000 | 293,000,000 | |||||
Long-term debt, excluding current maturities | 31,875,000,000 | 38,312,000,000 | |||||
Decrease in fair value of interest rate hedge | 4,000,000 | 0 | |||||
Repayments of Long-term Debt [Abstract] | |||||||
2,018 | 2,866,000,000 | ||||||
2,019 | 3,189,000,000 | ||||||
2,020 | 2,834,000,000 | ||||||
2,021 | 2,085,000,000 | ||||||
2,022 | 1,929,000,000 | ||||||
Columbian Pipeline | |||||||
Debt Instrument [Line Items] | |||||||
Estimated increase (decrease) in fair value of acquired liabilities, long-term debt | CAD 300,000,000 | $ 231,000,000 | 242,000,000 | 293,000,000 | |||
TRANSCANADA PIPELINES LIMITED | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | 26,149,000,000 | 29,303,000,000 | |||||
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Dates Between 2018 and 2020 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 500,000,000 | CAD 600,000,000 | |||||
Interest Rate | 10.80% | 10.70% | 10.80% | 10.70% | |||
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Date of 2021 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 501,000,000 | CAD 537,000,000 | $ 400,000,000 | $ 400,000,000 | |||
Interest Rate | 9.90% | 9.90% | 9.90% | 9.90% | |||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 6,504,000,000 | CAD 5,804,000,000 | |||||
Interest Rate | 4.90% | 4.60% | 4.90% | 4.60% | |||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 18,644,000,000 | CAD 19,660,000,000 | $ 14,892,000,000 | $ 14,642,000,000 | |||
Interest Rate | 5.10% | 5.10% | 5.10% | 5.10% | |||
TRANSCANADA PIPELINES LIMITED | Acquisition Bridge Facility | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 0 | CAD 2,702,000,000 | $ 0 | $ 2,013,000,000 | |||
Interest Rate | 0.00% | 1.90% | 0.00% | 1.90% | |||
NOVA GAS TRANSMISSION LTD. | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 895,000,000 | CAD 917,000,000 | |||||
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Dates of 2024 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 100,000,000 | CAD 100,000,000 | |||||
Interest Rate | 9.90% | 9.90% | 9.90% | 9.90% | |||
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Date of 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 250,000,000 | CAD 269,000,000 | $ 200,000,000 | $ 200,000,000 | |||
Interest Rate | 7.90% | 7.90% | 7.90% | 7.90% | |||
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity between 2025 and 2030 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 504,000,000 | CAD 504,000,000 | |||||
Interest Rate | 7.40% | 7.40% | 7.40% | 7.40% | |||
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity Date of 2026 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 41,000,000 | CAD 44,000,000 | $ 33,000,000 | $ 33,000,000 | |||
Interest Rate | 7.50% | 7.50% | 7.50% | 7.50% | |||
TRANSCANADA PIPELINE USA LTD. | Acquisition Bridge Facility | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 0 | CAD 2,283,000,000 | $ 0 | $ 1,700,000,000 | |||
Interest Rate | 0.00% | 1.90% | 0.00% | 1.90% | |||
Columbian Pipeline | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 3,443,000,000 | CAD 3,692,000,000 | $ 2,750,000,000 | $ 2,750,000,000 | |||
Interest Rate | 4.00% | 4.00% | 4.00% | 4.00% | |||
TC PIPELINES, LP | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 2,573,000,000 | CAD 2,054,000,000 | |||||
TC PIPELINES, LP | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 1,502,000,000 | CAD 940,000,000 | $ 1,200,000,000 | $ 700,000,000 | |||
Interest Rate | 4.40% | 4.70% | 4.40% | 4.70% | |||
TC PIPELINES, LP | Unsecured Loan Facility | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 232,000,000 | CAD 215,000,000 | $ 185,000,000 | $ 160,000,000 | |||
Interest Rate | 2.70% | 1.90% | 2.70% | 1.90% | |||
TC PIPELINES, LP | Unsecured Term Loan | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 839,000,000 | CAD 899,000,000 | $ 670,000,000 | $ 670,000,000 | |||
Interest Rate | 2.70% | 1.90% | 2.70% | 1.90% | |||
TC PIPELINES, LP | Unsecured Term Loan Maturing October 2020 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | $ | $ 170,000,000 | ||||||
TC PIPELINES, LP | Unsecured Term Loan Maturing October 2022 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | $ | $ 500,000,000 | ||||||
ANR PIPELINE COMPANY | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 842,000,000 | CAD 903,000,000 | $ 672,000,000 | $ 672,000,000 | |||
Interest Rate | 7.20% | 7.20% | 7.20% | 7.20% | |||
GAS TRANSMISSION NORTHWEST LLC | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 382,000,000 | CAD 423,000,000 | |||||
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 313,000,000 | CAD 336,000,000 | $ 250,000,000 | $ 250,000,000 | |||
Interest Rate | 5.60% | 5.60% | 5.60% | 5.60% | |||
GAS TRANSMISSION NORTHWEST LLC | Unsecured Term Loan | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 69,000,000 | CAD 87,000,000 | $ 55,000,000 | $ 65,000,000 | |||
Interest Rate | 1.10% | 1.60% | 1.10% | 1.60% | |||
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 324,000,000 | CAD 373,000,000 | $ 259,000,000 | $ 278,000,000 | |||
Interest Rate | 7.70% | 7.70% | 7.70% | 7.70% | |||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Senior Secured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 38,000,000 | CAD 71,000,000 | $ 30,000,000 | $ 53,000,000 | |||
Interest Rate | 6.00% | 6.00% | 6.00% | 6.00% | |||
TUSCARORA GAS TRANSMISSION COMPANY | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 31,000,000 | CAD 29,000,000 | |||||
TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 31,000,000 | CAD 13,000,000 | $ 25,000,000 | $ 10,000,000 | |||
Interest Rate | 1.10% | 1.90% | 1.10% | 1.90% | |||
TUSCARORA GAS TRANSMISSION COMPANY | Senior Secured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding at December 31 | CAD 0 | CAD 16,000,000 | $ 0 | $ 12,000,000 | |||
Interest Rate | 0.00% | 4.00% | 0.00% | 4.00% |
LONG-TERM DEBT - Long-Term Debt
LONG-TERM DEBT - Long-Term Debt Issued (Details) CAD in Millions, $ in Millions | 1 Months Ended | ||||||||||||||
Nov. 30, 2017USD ($) | Sep. 30, 2017CAD | Aug. 31, 2017USD ($) | May 31, 2017USD ($) | Jun. 30, 2016CAD | Jun. 30, 2016USD ($) | Apr. 30, 2016USD ($) | Jan. 31, 2016USD ($) | Nov. 30, 2015USD ($) | Oct. 31, 2015CAD | Sep. 30, 2015USD ($) | Jul. 31, 2015CAD | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Jan. 31, 2015USD ($) | |
TRANSCANADA PIPELINES LIMITED | Senior unsecured notes, floating interest rate | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 550 | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | 2.125% senior unsecured note, due November 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 700 | ||||||||||||||
Interest Rate | 2.125% | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | 3.39% medium term notes, due March 2028 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | CAD | CAD 300 | ||||||||||||||
Interest Rate | 3.39% | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | 4.33% medium term notes, due September 2047 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | CAD | CAD 700 | ||||||||||||||
Interest Rate | 4.33% | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | Acquisition Bridge Facility | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 5,213 | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | 3.69% medium term notes, due July 2023 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | CAD | CAD 300 | ||||||||||||||
Interest Rate | 3.69% | 3.69% | |||||||||||||
Long-term debt, re-issuance yield, percent | 2.69% | 2.69% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | 4.35% medium term notes, due June 2046 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | CAD | CAD 700 | ||||||||||||||
Interest Rate | 4.35% | 4.35% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | 4.875% senior unsecured notes, due January 2026 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 850 | ||||||||||||||
Interest Rate | 4.875% | 4.875% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | 3.125% senior unsecured notes, due January 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 400 | ||||||||||||||
Interest Rate | 3.125% | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | 1.625% senior unsecured notes, due November 2017 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 1,000 | ||||||||||||||
Interest Rate | 1.625% | 1.625% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | 4.55% medium-term notes, due November 2041 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | CAD | CAD 400 | ||||||||||||||
Interest Rate | 4.55% | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | 3.30% medium-term notes, due July 2025 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | CAD | CAD 750 | ||||||||||||||
Interest Rate | 3.30% | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | 4.60% senior unsecured notes, due March 2045 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 750 | ||||||||||||||
Interest Rate | 4.60% | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | 1.875% senior unsecured notes, due January 2018 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 500 | ||||||||||||||
Interest Rate | 1.875% | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior unsecured notes, floating rates, due in January 2018 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 250 | ||||||||||||||
TUSCARORA GAS TRANSMISSION COMPANY | Term loan, floating interest rate | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 25 | $ 10 | |||||||||||||
TC PIPELINES, LP | 3.90% Senior Unsecured Notes | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 500 | ||||||||||||||
Interest Rate | 3.90% | ||||||||||||||
TC PIPELINES, LP | Unsecured term loan, floating rate, due October 2018 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 170 | ||||||||||||||
TC PIPELINES, LP | 4.375% senior unsecured notes, due March 2025 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 350 | ||||||||||||||
Interest Rate | 4.375% | ||||||||||||||
TRANSCANADA PIPELINE USA LTD. | Acquisition Bridge Facility | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 1,700 | ||||||||||||||
ANR PIPELINE COMPANY | 4.14% senior unsecured notes, due June 2026 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 240 | ||||||||||||||
Interest Rate | 4.14% | 4.14% | |||||||||||||
GAS TRANSMISSION NORTHWEST LLC | Unsecured term loan, floating interest rate, due June 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Amount | $ 75 |
LONG-TERM DEBT - Retired (Detai
LONG-TERM DEBT - Retired (Details) CAD in Millions, $ in Millions | 1 Months Ended | ||||||||||||||||
Dec. 31, 2017CAD | Nov. 30, 2017USD ($) | Aug. 31, 2017USD ($) | Jun. 30, 2017USD ($) | Apr. 30, 2017USD ($) | Feb. 28, 2017USD ($) | Jan. 31, 2017CAD | Nov. 30, 2016USD ($) | Oct. 31, 2016CAD | Jun. 30, 2016USD ($) | Feb. 29, 2016CAD | Jan. 31, 2016USD ($) | Aug. 31, 2015CAD | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Jan. 31, 2015USD ($) | Nov. 30, 2015 | |
TRANSCANADA PIPELINES LIMITED | Debentures, 9.80% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | CAD | CAD 100 | ||||||||||||||||
Interest Rate | 9.80% | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | 1.625% senior unsecured notes, due November 2017 | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 1,000 | ||||||||||||||||
Interest Rate | 1.625% | 1.625% | |||||||||||||||
TRANSCANADA PIPELINES LIMITED | Bridge facility, floating rates | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 1,513 | $ 500 | $ 3,200 | ||||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes 5.10% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | CAD | CAD 300 | ||||||||||||||||
Interest Rate | 5.10% | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes at 4.65% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | CAD | CAD 400 | ||||||||||||||||
Interest Rate | 4.65% | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 7.69% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 84 | ||||||||||||||||
Interest Rate | 7.69% | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, Floating Rate | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 500 | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes 0.75% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 750 | ||||||||||||||||
Interest Rate | 0.75% | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Debentures, 11.90% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | CAD | CAD 150 | ||||||||||||||||
Interest Rate | 11.90% | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 3.40% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 500 | ||||||||||||||||
Interest Rate | 3.40% | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 0.875% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 500 | ||||||||||||||||
Interest Rate | 0.875% | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 4.875% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 300 | ||||||||||||||||
Interest Rate | 4.875% | 4.875% | |||||||||||||||
TUSCARORA GAS TRANSMISSION COMPANY | Senior Secured Notes, 3.82% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 12 | ||||||||||||||||
Interest Rate | 3.82% | ||||||||||||||||
TRANSCANADA PIPELINE USA LTD. | Bridge facility, floating rates | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 1,070 | $ 630 | |||||||||||||||
NOVA GAS TRANSMISSION LTD. | Debentures, 12.20% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | CAD | CAD 225 | ||||||||||||||||
Interest Rate | 12.20% | ||||||||||||||||
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes, 5.09% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount | $ 75 | ||||||||||||||||
Interest Rate | 5.09% |
LONG-TERM DEBT - Interest Expen
LONG-TERM DEBT - Interest Expense and Payments (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Interest Expense [Abstract] | |||
Capitalized interest | CAD (173) | CAD (176) | CAD (280) |
Amortization and other financial charges | 67 | 102 | 31 |
Interest expense | 2,137 | 1,927 | 1,398 |
Interest payments on long-term debt and junior subordinated notes, net of interest capitalized on construction projects | 2,055 | 1,757 | 1,295 |
Short-term debt | |||
Interest Expense [Abstract] | |||
Interest on debt | 101 | 56 | 44 |
Total long-term debt (excluding junior subordinated notes) | |||
Interest Expense [Abstract] | |||
Interest on debt | 1,794 | 1,765 | 1,487 |
Junior subordinated notes | |||
Interest Expense [Abstract] | |||
Interest on debt | CAD 348 | CAD 180 | CAD 116 |
JUNIOR SUBORDINATED NOTES (Deta
JUNIOR SUBORDINATED NOTES (Details) | 1 Months Ended | 3 Months Ended | |||||||||
May 31, 2017USD ($) | Mar. 31, 2017USD ($) | Aug. 31, 2016USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | May 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2007USD ($) | |
Debt Instrument [Line Items] | |||||||||||
Outstanding at December 31 | CAD 34,677,000,000 | CAD 40,048,000,000 | |||||||||
Unamortized debt discount and issue costs | (174,000,000) | (191,000,000) | |||||||||
Long-term Debt | $ | $ 1,100,000,000 | $ 850,000,000 | |||||||||
TRANSCANADA PIPELINES LIMITED | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Outstanding at December 31 | 26,149,000,000 | 29,303,000,000 | |||||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Outstanding at December 31 | 7,071,000,000 | 3,961,000,000 | |||||||||
Unamortized debt discount and issue costs | (64,000,000) | (30,000,000) | |||||||||
Long-term Debt | 7,007,000,000 | 3,931,000,000 | |||||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067 | Junior subordinated notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ | $ 1,000,000,000 | ||||||||||
Outstanding at December 31 | CAD 1,252,000,000 | CAD 1,343,000,000 | |||||||||
Effective Interest Rate | 5.00% | 5.00% | 6.40% | 6.40% | |||||||
Debt converted | $ | $ 1,000,000,000 | ||||||||||
Stated interest rate | 6.35% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067 | Junior subordinated notes | LIBOR | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis points (percent) | 2.21% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2075 | Junior subordinated notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ | $ 750,000,000 | ||||||||||
Outstanding at December 31 | CAD 939,000,000 | CAD 1,007,000,000 | |||||||||
Effective Interest Rate | 5.90% | 5.90% | 5.50% | 5.50% | |||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2076 | Junior subordinated notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ | $ 1,200,000,000 | ||||||||||
Outstanding at December 31 | CAD 1,502,000,000 | CAD 1,611,000,000 | |||||||||
Effective Interest Rate | 6.60% | 6.60% | 6.20% | 6.20% | |||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2077 | Junior subordinated notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ | $ 1,500,000,000 | ||||||||||
Outstanding at December 31 | CAD 1,878,000,000 | CAD 0 | |||||||||
Effective Interest Rate | 5.60% | 5.60% | 0.00% | 0.00% | |||||||
TRANSCANADA PIPELINES LIMITED | Canadian junior subordinated debt, due 2077 | Junior subordinated notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ | $ 1,500,000,000 | ||||||||||
Outstanding at December 31 | CAD 1,500,000,000 | CAD 0 | |||||||||
Effective Interest Rate | 5.10% | 5.10% | 0.00% | 0.00% | |||||||
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-A | Junior subordinated notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ | $ 1,500,000,000 | $ 1,500,000,000 | |||||||||
Stated interest rate | 5.55% | 5.55% | |||||||||
Administrative charge (percent) | 0.25% | 0.25% | |||||||||
Redemption price as a percentage of principal amount plus accrued and unpaid interest | 100.00% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-A | March 2027 until March 2047 | Junior subordinated notes | LIBOR | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis points (percent) | 3.458% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-A | March 2047 until March 2077 | Junior subordinated notes | LIBOR | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis points (percent) | 4.208% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-B | Junior subordinated notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | CAD 1,500,000,000 | ||||||||||
Stated interest rate | 4.90% | ||||||||||
Administrative charge (percent) | 0.25% | ||||||||||
Redemption price as a percentage of principal amount plus accrued and unpaid interest | 100.00% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-B | May 2027 until May 2047 | Junior subordinated notes | LIBOR | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis points (percent) | 3.33% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-B | May 2047 to May 2077 | Junior subordinated notes | LIBOR | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis points (percent) | 4.08% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2016-A | Junior subordinated notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ | $ 1,200,000,000 | ||||||||||
Stated interest rate | 6.125% | ||||||||||
Administrative charge (percent) | 0.25% | ||||||||||
Redemption price as a percentage of principal amount plus accrued and unpaid interest | 100.00% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2016-A | August 2026 until August 2046 | Junior subordinated notes | LIBOR | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis points (percent) | 4.89% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2016-A | August 2046 to August 2076 | Junior subordinated notes | LIBOR | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis points (percent) | 5.64% | ||||||||||
TransCanada Trust | Trust Notes - Series 2017-A | Notes payable | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ | $ 1,500,000,000 | $ 1,500,000,000 | |||||||||
Stated interest rate, period of time (in years) | 10 years | ||||||||||
TransCanada Trust | Trust Notes - Series 2017-A | First Ten Years | Notes payable | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate | 5.30% | 5.30% | |||||||||
TransCanada Trust | Trust Notes - Series 2017-B | Notes payable | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | CAD 1,500,000,000 | ||||||||||
Stated interest rate, period of time (in years) | 10 years | ||||||||||
TransCanada Trust | Trust Notes - Series 2017-B | First Ten Years | Notes payable | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate | 4.65% | ||||||||||
TransCanada Trust | Trust Notes - Series 2016-A | Notes payable | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ | $ 1,200,000,000 | ||||||||||
Stated interest rate, period of time (in years) | 10 years | ||||||||||
TransCanada Trust | Trust Notes - Series 2016-A | First Ten Years | Notes payable | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate | 5.875% |
NON-CONTROLLING INTERESTS (Deta
NON-CONTROLLING INTERESTS (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Non-controlling interest included in the Consolidated Balance Sheet | |||
Non-controlling interest | CAD 1,852 | CAD 1,726 | |
Non-controlling interests included in the Consolidated Statement of Income | |||
Non-controlling interest | 238 | 252 | CAD 6 |
Noncontrolling Interest | |||
Non-controlling interests included in the Consolidated Statement of Income | |||
Non-controlling interest | (238) | (252) | (6) |
Noncontrolling Interest | TC PipeLines, LP | |||
Non-controlling interest included in the Consolidated Balance Sheet | |||
Non-controlling interest | 1,852 | 1,596 | |
Non-controlling interests included in the Consolidated Statement of Income | |||
Non-controlling interest | 220 | 215 | (13) |
Noncontrolling Interest | Portland Natural Gas Transmission System | |||
Non-controlling interest included in the Consolidated Balance Sheet | |||
Non-controlling interest | 0 | 130 | |
Non-controlling interests included in the Consolidated Statement of Income | |||
Non-controlling interest | 9 | 20 | 19 |
Noncontrolling Interest | Columbia Pipeline Partners LP | |||
Non-controlling interests included in the Consolidated Statement of Income | |||
Non-controlling interest | CAD 9 | CAD 17 | CAD 0 |
NON-CONTROLLING INTERESTS - Nar
NON-CONTROLLING INTERESTS - Narrative (Details) $ / shares in Units, shares in Millions, CAD in Millions, $ in Millions | Jun. 01, 2017 | Feb. 17, 2017USD ($)$ / shares | Jan. 01, 2016 | May 19, 2016shares | May 31, 2017CAD | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | Dec. 31, 2016USD ($) | Jul. 01, 2016 |
Non-controlling interests | |||||||||||
Asset impairment charges | CAD 1,257 | CAD 1,388 | CAD 3,745 | ||||||||
Common units outstanding, subject to rescission, amount | 0 | 1,179 | |||||||||
Noncontrolling Interest | |||||||||||
Non-controlling interests | |||||||||||
Share price (in dollars per share) | $ / shares | $ 17 | ||||||||||
Stub period distribution payments acquired (in dollars per share) | $ / shares | $ 0.10 | ||||||||||
Aggregate transaction value | $ 921 | 41 | 40 | 11 | |||||||
Columbian Pipeline | Noncontrolling Interest | |||||||||||
Non-controlling interests | |||||||||||
Percentage of non-controlling interests | 53.50% | ||||||||||
Columbia Pipeline Partners LP | |||||||||||
Non-controlling interests | |||||||||||
Common units outstanding, subject to rescission, amount | 1,073 | $ 799 | |||||||||
TC PipeLines, LP | |||||||||||
Non-controlling interests | |||||||||||
Asset impairment charges | $ | $ 199 | ||||||||||
Fees received for services provided | CAD 5 | 5 | CAD 4 | ||||||||
Common units outstanding, subject to rescission, amount | CAD 106 | $ 82 | |||||||||
Reclassification to Common Units of CPPL, subject to redemption (in shares) | shares | 1.6 | ||||||||||
Expiration period from the date of purchase | 1 year | ||||||||||
TC PipeLines, LP | Noncontrolling Interest | |||||||||||
Non-controlling interests | |||||||||||
Percentage of non-controlling interests | 74.30% | 73.20% | 73.20% | ||||||||
Asset impairment charges | $ | $ 143 | ||||||||||
TC PipeLines, LP | Noncontrolling Interest | Minimum | |||||||||||
Non-controlling interests | |||||||||||
Percentage of non-controlling interests | 72.00% | 71.70% | 71.70% | 72.00% | |||||||
TC PipeLines, LP | Noncontrolling Interest | Maximum | |||||||||||
Non-controlling interests | |||||||||||
Percentage of non-controlling interests | 73.20% | 72.00% | 72.00% | 73.20% | |||||||
Portland Natural Gas Transmission System | |||||||||||
Non-controlling interests | |||||||||||
Fees received for services provided | CAD 4 | CAD 10 | CAD 11 | ||||||||
Portland Natural Gas Transmission System | Noncontrolling Interest | |||||||||||
Non-controlling interests | |||||||||||
Percentage of non-controlling interests | 0.00% | 38.30% | 38.30% | ||||||||
Ownership interest before transaction, percent | 11.81% | 49.90% |
COMMON SHARES - Reconciliation
COMMON SHARES - Reconciliation (Details) shares in Thousands, CAD in Millions, $ in Billions | Oct. 31, 2017CADshares | Jul. 31, 2017CADshares | Apr. 28, 2017CADshares | Jan. 31, 2017CADshares | Jul. 01, 2016CAD | Jul. 01, 2016USD ($) | Dec. 31, 2017CADshares | Dec. 31, 2016CADshares | Dec. 31, 2015CADshares |
Increase (decrease) in equity | |||||||||
Outstanding at the beginning of the period (in shares) | shares | 859,000 | ||||||||
Outstanding at the beginning of the period | CAD 20,981 | ||||||||
Outstanding at the end of the period (in shares) | shares | 872,000 | 859,000 | |||||||
Outstanding at the end of the period | CAD 21,761 | CAD 20,981 | |||||||
Proceeds from shares issued | CAD 780 | CAD 4,661 | CAD 0 | ||||||
Common Shares | |||||||||
Increase (decrease) in equity | |||||||||
Outstanding at the beginning of the period (in shares) | shares | 859,135 | 779,479 | 779,479 | ||||||
Outstanding at the beginning of the period | CAD 20,981 | CAD 16,320 | CAD 16,320 | ||||||
Issuance of common shares for cash (in shares) | shares | 3,100 | 3,000 | 3,400 | 3,000 | 12,499 | 79,656 | 0 | ||
Issuance of common shares for cash | CAD 189 | CAD 190 | CAD 214 | CAD 187 | CAD 780 | CAD 4,661 | CAD 0 | ||
Outstanding at the end of the period (in shares) | shares | 871,634 | 859,135 | 779,479 | ||||||
Outstanding at the end of the period | CAD 21,761 | CAD 20,981 | CAD 16,320 | ||||||
Columbian Pipeline | |||||||||
Increase (decrease) in equity | |||||||||
Proceeds from shares issued | CAD 2,500 | ||||||||
Bridge Facility | |||||||||
Increase (decrease) in equity | |||||||||
Repayments of lines of credit | CAD 2,000 | ||||||||
Bridge Facility | Columbian Pipeline | |||||||||
Increase (decrease) in equity | |||||||||
Proceeds from lines of credit | $ | $ 6.9 |
COMMON SHARES - Common Shares I
COMMON SHARES - Common Shares Issued and Outstanding (Details) - CAD shares in Thousands, CAD in Millions | Oct. 31, 2017 | Jul. 31, 2017 | Apr. 28, 2017 | Jan. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restrictions on dividends payment | CAD 14,600 | CAD 9,700 | CAD 4,100 | ||||
Common Shares | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares issued (in shares) | 3,100 | 3,000 | 3,400 | 3,000 | 12,499 | 79,656 | 0 |
Proceeds from shares issued | CAD 189 | CAD 190 | CAD 214 | CAD 187 | CAD 780 | CAD 4,661 | CAD 0 |
COMMON SHARES - Options (Detail
COMMON SHARES - Options (Details) - Employee Stock Option | 12 Months Ended |
Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Contractual life | 7 years |
Award vesting period | 3 years |
Vesting in year one | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Award vesting rights percentage | 33.33% |
Vesting in year two | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Award vesting rights percentage | 33.33% |
Vesting in year three | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Award vesting rights percentage | 33.34% |
COMMON SHARES - Stock Options A
COMMON SHARES - Stock Options Assumptions Used (Details) - CAD CAD / shares in Units, CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan, Assumptions Used in Calculations [Abstract] | |||
Weighted average fair value (in dollars per share) | CAD 7.22 | CAD 5.67 | CAD 6.45 |
Expected life (years) | 5 years 8 months 12 days | 5 years 9 months 18 days | 5 years 9 months 18 days |
Interest rate | 1.20% | 0.70% | 1.10% |
Volatility | 18.00% | 21.00% | 18.00% |
Dividend yield | 3.60% | 4.90% | 3.70% |
Forfeiture rate | 0.00% | 5.00% | 5.00% |
Expense for stock options | CAD 12 | CAD 15 | CAD 13 |
Unrecognized compensation costs related to non-vested stock options | CAD 15 | ||
Employee Stock Option | |||
Defined Benefit Plan, Assumptions Used in Calculations [Abstract] | |||
Expense recognition period (in years) | 3 years |
COMMON SHARES - Summary of Addi
COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD shares in Millions, CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |||
Total intrinsic value of options exercised | CAD 28 | CAD 31 | CAD 10 |
Fair value of options that have vested | CAD 140 | CAD 126 | CAD 91 |
Total options vested (in shares) | 2.3 | 2.1 | 2 |
Options, exercisable, intrinsic value | CAD 83 | ||
Options, outstanding, intrinsic value | CAD 110 |
OTHER COMPREHENSIVE (LOSS)_I105
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Before Tax Amount | |||
Other Comprehensive Income (Loss) | CAD (957) | CAD (29) | CAD 522 |
Income Tax Recovery/(Expense) | |||
Other Comprehensive Income (Loss) | 31 | (3) | 80 |
Net of Tax Amount | |||
Other comprehensive (loss)/income (Note 21) | (926) | (32) | 602 |
Foreign currency translation losses on net investment in foreign operations | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (746) | 3 | 798 |
Reclassification from accumulated other comprehensive Income | (77) | ||
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | (3) | 0 | 15 |
Reclassification from AOCI | 0 | ||
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | (749) | 3 | 813 |
Reclassification from accumulated other comprehensive income | (77) | ||
Change in fair value of net investment hedges | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | 0 | (14) | (505) |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 0 | 4 | 133 |
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | 0 | (10) | (372) |
Cash flow hedge | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | 3 | 44 | (92) |
Reclassification from accumulated other comprehensive Income | (3) | 71 | 144 |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 0 | (14) | 35 |
Reclassification from AOCI | 1 | (29) | (56) |
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | 3 | 30 | (57) |
Reclassification from accumulated other comprehensive income | (2) | 42 | 88 |
Pension and other post-retirement benefits | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (14) | (38) | 74 |
Reclassification from accumulated other comprehensive Income | 21 | 22 | 41 |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 3 | 12 | (23) |
Reclassification from AOCI | (5) | (6) | (9) |
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | (11) | (26) | 51 |
Reclassification from accumulated other comprehensive income | 16 | 16 | 32 |
Other comprehensive loss on equity investments | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (141) | (117) | 62 |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 35 | 30 | (15) |
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | CAD (106) | CAD (87) | CAD 47 |
OTHER COMPREHENSIVE (LOSS)_I106
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | CAD 23,535,000,000 | CAD 20,297,000,000 | |
Other comprehensive (loss)/income (Note 21) | (926,000,000) | (32,000,000) | CAD 602,000,000 |
Balance at end of year | 24,269,000,000 | 23,535,000,000 | 20,297,000,000 |
Accumulated benefit obligation, (increase) decrease for settlement and curtailment | 27,000,000 | ||
Cash flow hedge loss reported in AOCI and expected to be reclassified to net income in the next 12 months, net of tax | 19,000,000 | ||
Cash flow hedge gain (loss) to be reclassified within twelve months, net of tax | (14,000,000) | ||
Currency Translation Adjustments | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (376,000,000) | (383,000,000) | (518,000,000) |
Other comprehensive income/(loss), before reclassifications | (590,000,000) | 7,000,000 | 135,000,000 |
Amounts reclassified from AOCI | (77,000,000) | 0 | 0 |
Other comprehensive (loss)/income (Note 21) | (667,000,000) | 7,000,000 | 135,000,000 |
Balance at end of year | (1,043,000,000) | (376,000,000) | (383,000,000) |
Cash Flow Hedges | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (28,000,000) | (97,000,000) | (128,000,000) |
Other comprehensive income/(loss), before reclassifications | (1,000,000) | 27,000,000 | (57,000,000) |
Amounts reclassified from AOCI | (2,000,000) | 42,000,000 | 88,000,000 |
Other comprehensive (loss)/income (Note 21) | (3,000,000) | 69,000,000 | 31,000,000 |
Balance at end of year | (31,000,000) | (28,000,000) | (97,000,000) |
Pension and Other Post-Retirement Benefit Plan Adjustments | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (208,000,000) | (198,000,000) | (281,000,000) |
Other comprehensive income/(loss), before reclassifications | (11,000,000) | (26,000,000) | 51,000,000 |
Amounts reclassified from AOCI | 16,000,000 | 16,000,000 | 32,000,000 |
Other comprehensive (loss)/income (Note 21) | 5,000,000 | (10,000,000) | 83,000,000 |
Balance at end of year | (203,000,000) | (208,000,000) | (198,000,000) |
Equity Investments | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (348,000,000) | (261,000,000) | (308,000,000) |
Other comprehensive income/(loss), before reclassifications | (117,000,000) | (101,000,000) | 33,000,000 |
Amounts reclassified from AOCI | 11,000,000 | 14,000,000 | 14,000,000 |
Other comprehensive (loss)/income (Note 21) | (106,000,000) | (87,000,000) | 47,000,000 |
Balance at end of year | (454,000,000) | (348,000,000) | (261,000,000) |
Accumulated Other Comprehensive Loss | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (960,000,000) | (939,000,000) | (1,235,000,000) |
Other comprehensive income/(loss), before reclassifications | (719,000,000) | (93,000,000) | 162,000,000 |
Amounts reclassified from AOCI | (52,000,000) | 72,000,000 | 134,000,000 |
Other comprehensive (loss)/income (Note 21) | (771,000,000) | (21,000,000) | 296,000,000 |
Balance at end of year | (1,731,000,000) | (960,000,000) | (939,000,000) |
Accumulated foreign currency adjustment attributable to noncontrolling interest | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Other comprehensive income/(loss), before reclassifications | (159,000,000) | (14,000,000) | 306,000,000 |
Accumulated net gain (loss) from cash flow hedges attributable to noncontrolling interest | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Other comprehensive income/(loss), before reclassifications | CAD 4,000,000 | CAD 3,000,000 | CAD 0 |
OTHER COMPREHENSIVE (LOSS)_I107
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Interest expense | CAD 1,447 | CAD 1,391 | CAD 1,206 |
Income tax (recovery)/expense | 107 | (349) | (35) |
Gain (loss) on assets held for sale/sold | 631 | (833) | (125) |
Cash Flow Hedges | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Net of tax | 2 | (42) | (88) |
Pension and other post-retirement benefit plan adjustments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Net of tax | (16) | (16) | (32) |
Currency translation adjustments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Net of tax | 77 | 0 | 0 |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash Flow Hedges | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Total before tax | 3 | (71) | (144) |
Income tax (recovery)/expense | (1) | 29 | 56 |
Net Income/(Loss) Attributable to Common Shares | 2 | (42) | (88) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash Flow Hedges | Commodities | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Revenues (Energy) | 20 | (57) | (128) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash Flow Hedges | Interest | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Interest expense | (17) | (14) | (16) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Amortization of actuarial loss and past service cost | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Total before tax | (15) | (22) | (41) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Settlement charge | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Total before tax | (2) | 0 | 0 |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Pension and other post-retirement benefit plan adjustments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Total before tax | (17) | (22) | (41) |
Income tax (recovery)/expense | 5 | 6 | 9 |
Net of tax | (12) | (16) | (32) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Other comprehensive income on equity investments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Income from equity investments | (15) | (19) | (19) |
Income tax (recovery)/expense | 4 | 5 | 5 |
Net Income/(Loss) Attributable to Common Shares | (11) | (14) | (14) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Currency translation adjustments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Income tax (recovery)/expense | 0 | 0 | |
Net Income/(Loss) Attributable to Common Shares | 77 | CAD 0 | CAD 0 |
Gain (loss) on assets held for sale/sold | CAD 77 |
EMPLOYEE POST-RETIREMENT BEN108
EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments and Changes (Details) CAD in Millions | Sep. 30, 2017CAD | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Apr. 01, 2017election |
Employee post-retirement benefits | |||||
Expected average remaining life expectancy of former employees over which past service costs are amortized (in years) | 12 years | 12 years | 12 years | ||
Expense for savings plan and DC Plans | CAD 42 | CAD 52 | CAD 41 | ||
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | |||||
Savings and DC Plans | 42 | 52 | 41 | ||
Total cash contributions | 212 | 171 | CAD 143 | ||
Other comprehensive income (loss), defined benefit plan, settlement and curtailment gain (loss) | (27) | ||||
Change in Plan Assets | |||||
Plan assets at fair value – beginning of year | 3,562 | ||||
Plan assets at fair value – end of year | 3,816 | 3,562 | |||
Amounts recognized in the Balance Sheet | |||||
Intangible and other assets (Note 12) | 193 | 189 | |||
Other long-term liabilities (Note 15) | CAD (389) | CAD (448) | |||
Pension Benefit Plans | |||||
Employee post-retirement benefits | |||||
Consecutive period of employment for highest average earnings (in years) | 3 years | ||||
Expected average remaining service life of employees over which past service costs are amortized (in years) | 9 years | 9 years | 12 years | ||
Number of final elections | election | 1 | ||||
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | |||||
DB Plans and Other post-retirement benefit plans | CAD 163 | CAD 111 | CAD 96 | ||
Total amount outstanding under letters of credit | CAD 260 | CAD 233 | |||
Discount rate | 3.60% | 4.00% | |||
Remeasurements impact on unrealized actuarial gain (loss), recorded in regulated assets | CAD (2) | CAD 0 | 0 | ||
Change in Benefit Obligation | |||||
Benefit obligation – beginning of year | 3,456 | 2,780 | |||
Service cost | 113 | 107 | |||
Interest cost | 135 | 127 | |||
Employee contributions | 5 | 4 | |||
Benefits paid | (166) | (204) | |||
Actuarial loss/(gain) | 253 | 111 | |||
Acquisition of Columbia | 0 | 527 | |||
Curtailment | (14) | 0 | |||
Settlement | (66) | 2 | |||
Foreign exchange rate changes | (70) | 2 | |||
Benefit obligation – end of year | 3,646 | 3,456 | 2,780 | ||
Change in Plan Assets | |||||
Plan assets at fair value – beginning of year | 3,208 | 2,591 | |||
Actual return on plan assets | 358 | 227 | |||
Employer contributions | 163 | 111 | 96 | ||
Employee contributions | 5 | 4 | |||
Benefits paid | (166) | (204) | |||
Acquisition of Columbia | 0 | 475 | |||
Settlement | (57) | 0 | |||
Foreign exchange rate changes | (60) | 4 | |||
Plan assets at fair value – end of year | 3,451 | 3,208 | 2,591 | ||
Funded Status – Plan Deficit | (195) | (248) | |||
Amounts recognized in the Balance Sheet | |||||
Intangible and other assets (Note 12) | 0 | 0 | |||
Accounts payable and other | (1) | 0 | |||
Other long-term liabilities (Note 15) | (194) | (248) | |||
Net | (195) | (248) | |||
Other Post-Retirement Benefit Plans | |||||
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | |||||
DB Plans and Other post-retirement benefit plans | CAD 7 | CAD 8 | 6 | ||
Discount rate | 3.70% | 4.15% | |||
Remeasurements impact on unrealized actuarial gain (loss), recorded in regulated assets | CAD 0 | CAD 0 | 0 | ||
Change in Benefit Obligation | |||||
Benefit obligation – beginning of year | 372 | 225 | |||
Service cost | 4 | 3 | |||
Interest cost | 14 | 13 | |||
Employee contributions | 3 | 2 | |||
Benefits paid | (19) | (16) | |||
Actuarial loss/(gain) | 19 | (8) | |||
Acquisition of Columbia | 0 | 151 | |||
Curtailment | (2) | 0 | |||
Settlement | 0 | 0 | |||
Foreign exchange rate changes | (16) | 2 | |||
Benefit obligation – end of year | 375 | 372 | 225 | ||
Change in Plan Assets | |||||
Plan assets at fair value – beginning of year | 354 | 45 | |||
Actual return on plan assets | 45 | 14 | |||
Employer contributions | 7 | 8 | 6 | ||
Employee contributions | 3 | 2 | |||
Benefits paid | (19) | (16) | |||
Acquisition of Columbia | 0 | 294 | |||
Settlement | 0 | 0 | |||
Foreign exchange rate changes | (25) | 7 | |||
Plan assets at fair value – end of year | 365 | 354 | 45 | ||
Funded Status – Plan Deficit | (10) | (18) | |||
Amounts recognized in the Balance Sheet | |||||
Intangible and other assets (Note 12) | 193 | 189 | |||
Accounts payable and other | (8) | (7) | |||
Other long-term liabilities (Note 15) | (195) | (200) | |||
Net | (10) | (18) | |||
Canadian | Pension Benefit Plans | |||||
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | |||||
Letter of credit to the DB Plan | 27 | CAD 20 | CAD 33 | ||
Total amount outstanding under letters of credit | CAD 260 | ||||
U.S. | Pension Benefit Plans | |||||
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | |||||
Discount rate | 4.10% | ||||
Other comprehensive income (loss), defined benefit plan, settlement and curtailment gain (loss) | CAD 3 | ||||
Net periodic benefit cost (credit), gain (loss) due to settlement | CAD 2 | ||||
Columbia DB Plan | Pension Benefit Plans | |||||
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | |||||
Discount rate | 3.70% | ||||
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans | CAD 16 | ||||
Remeasurements impact on unrealized actuarial gain (loss), recorded in regulated assets | 14 | ||||
Remeasurement impact recorded in OCI | CAD 2 |
EMPLOYEE POST-RETIREMENT BEN109
EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Funded status based on accumulated benefit obligation | |||
Plan assets at fair value | CAD 3,816 | CAD 3,562 | |
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 100.00% | 100.00% | |
Pension Benefit Plans | |||
Benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Projected benefit obligation | CAD (3,646) | CAD (3,456) | |
Plan assets at fair value | 3,451 | 3,208 | |
Funded Status – Plan Deficit | (195) | (248) | |
Funded status based on accumulated benefit obligation | |||
Accumulated benefit obligation | (3,372) | (3,202) | |
Plan assets at fair value | 3,451 | 3,208 | CAD 2,591 |
Funded Status – Plan Surplus | 79 | 6 | |
Accumulated benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Accumulated benefit obligation | (944) | (990) | |
Plan assets at fair value | 925 | 868 | |
Funded Status – Plan Deficit | CAD (19) | CAD (122) | |
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 100.00% | 100.00% | |
Pension Benefit Plans | Debt securities | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 30.00% | 31.00% | |
Amount of debt or common shares included in plan assets | CAD 7 | CAD 9 | |
Percentage of Plan Assets | 0.20% | 0.20% | |
Pension Benefit Plans | Debt securities | Minimum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 25.00% | ||
Pension Benefit Plans | Debt securities | Maximum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 40.00% | ||
Pension Benefit Plans | Equity securities | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 64.00% | 63.00% | |
Amount of debt or common shares included in plan assets | CAD 3 | CAD 4 | |
Percentage of Plan Assets | 0.10% | 0.10% | |
Pension Benefit Plans | Equity securities | Minimum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 45.00% | ||
Pension Benefit Plans | Equity securities | Maximum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 75.00% | ||
Pension Benefit Plans | Alternatives | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 6.00% | 6.00% | |
Pension Benefit Plans | Alternatives | Minimum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 5.00% | ||
Pension Benefit Plans | Alternatives | Maximum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 15.00% | ||
Other Post-Retirement Benefit Plans | |||
Benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Projected benefit obligation | CAD (203) | CAD (207) | |
Plan assets at fair value | 0 | 0 | |
Funded Status – Plan Deficit | (203) | (207) | |
Funded status based on accumulated benefit obligation | |||
Plan assets at fair value | CAD 365 | CAD 354 | CAD 45 |
EMPLOYEE POST-RETIREMENT BEN110
EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 3,816 | CAD 3,562 | |
Percentage of Total Portfolio | 100.00% | 100.00% | |
Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 1,186 | CAD 1,089 | |
Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 2,414 | 2,274 | |
Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 216 | 199 | CAD 14 |
Cash and Cash Equivalents | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 61 | CAD 34 | |
Percentage of Total Portfolio | 2.00% | 1.00% | |
Cash and Cash Equivalents | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 44 | CAD 22 | |
Cash and Cash Equivalents | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 17 | 12 | |
Cash and Cash Equivalents | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity securities | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 561 | CAD 531 | |
Percentage of Total Portfolio | 15.00% | 15.00% | |
Equity securities | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 897 | CAD 980 | |
Percentage of Total Portfolio | 24.00% | 27.00% | |
Equity securities | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 367 | CAD 366 | |
Percentage of Total Portfolio | 10.00% | 10.00% | |
Equity securities | Global | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 301 | CAD 235 | |
Percentage of Total Portfolio | 8.00% | 7.00% | |
Equity securities | Emerging | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 155 | CAD 144 | |
Percentage of Total Portfolio | 4.00% | 4.00% | |
Equity securities | Quoted Prices in Active Markets (Level I) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 410 | CAD 388 | |
Equity securities | Quoted Prices in Active Markets (Level I) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 543 | 504 | |
Equity securities | Quoted Prices in Active Markets (Level I) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 45 | 39 | |
Equity securities | Quoted Prices in Active Markets (Level I) | Global | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity securities | Quoted Prices in Active Markets (Level I) | Emerging | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 8 | 7 | |
Equity securities | Significant Other Observable Inputs (Level II) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 151 | 143 | |
Equity securities | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 354 | 476 | |
Equity securities | Significant Other Observable Inputs (Level II) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 322 | 327 | |
Equity securities | Significant Other Observable Inputs (Level II) | Global | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 301 | 235 | |
Equity securities | Significant Other Observable Inputs (Level II) | Emerging | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 147 | 137 | |
Equity securities | Significant Unobservable Inputs (Level III) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity securities | Significant Unobservable Inputs (Level III) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity securities | Significant Unobservable Inputs (Level III) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity securities | Significant Unobservable Inputs (Level III) | Global | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity securities | Significant Unobservable Inputs (Level III) | Emerging | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Federal | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 193 | CAD 192 | |
Percentage of Total Portfolio | 5.00% | 5.00% | |
Federal | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 244 | CAD 82 | |
Percentage of Total Portfolio | 6.00% | 2.00% | |
Federal | Quoted Prices in Active Markets (Level I) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Federal | Quoted Prices in Active Markets (Level I) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Federal | Significant Other Observable Inputs (Level II) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 193 | 192 | |
Federal | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 244 | 82 | |
Federal | Significant Unobservable Inputs (Level III) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Federal | Significant Unobservable Inputs (Level III) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Provincial | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 194 | CAD 179 | |
Percentage of Total Portfolio | 5.00% | 5.00% | |
Provincial | Quoted Prices in Active Markets (Level I) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Provincial | Significant Other Observable Inputs (Level II) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 194 | 179 | |
Provincial | Significant Unobservable Inputs (Level III) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Municipal | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 8 | CAD 8 | |
Percentage of Total Portfolio | 0.00% | 0.00% | |
Municipal | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 4 | CAD 39 | |
Percentage of Total Portfolio | 0.00% | 1.00% | |
Municipal | Quoted Prices in Active Markets (Level I) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Municipal | Quoted Prices in Active Markets (Level I) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Municipal | Significant Other Observable Inputs (Level II) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 8 | 8 | |
Municipal | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 4 | 39 | |
Municipal | Significant Unobservable Inputs (Level III) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Municipal | Significant Unobservable Inputs (Level III) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Corporate | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 122 | CAD 126 | |
Percentage of Total Portfolio | 3.00% | 4.00% | |
Corporate | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 234 | CAD 188 | |
Percentage of Total Portfolio | 6.00% | 5.00% | |
Corporate | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 5 | CAD 21 | |
Percentage of Total Portfolio | 0.00% | 1.00% | |
Corporate | Quoted Prices in Active Markets (Level I) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Corporate | Quoted Prices in Active Markets (Level I) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Corporate | Quoted Prices in Active Markets (Level I) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Corporate | Significant Other Observable Inputs (Level II) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 122 | 126 | |
Corporate | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 234 | 188 | |
Corporate | Significant Other Observable Inputs (Level II) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 5 | 21 | |
Corporate | Significant Unobservable Inputs (Level III) | Canadian | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Corporate | Significant Unobservable Inputs (Level III) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Corporate | Significant Unobservable Inputs (Level III) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
State | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 41 | CAD 41 | |
Percentage of Total Portfolio | 1.00% | 1.00% | |
State | Quoted Prices in Active Markets (Level I) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
State | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 41 | 41 | |
State | Significant Unobservable Inputs (Level III) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Government | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 4 | CAD 6 | |
Percentage of Total Portfolio | 0.00% | 0.00% | |
Government | Quoted Prices in Active Markets (Level I) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Government | Significant Other Observable Inputs (Level II) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 4 | 6 | |
Government | Significant Unobservable Inputs (Level III) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Mortgage backed | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 73 | CAD 62 | |
Percentage of Total Portfolio | 2.00% | 2.00% | |
Mortgage backed | Quoted Prices in Active Markets (Level I) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Mortgage backed | Significant Other Observable Inputs (Level II) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 73 | 62 | |
Mortgage backed | Significant Unobservable Inputs (Level III) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Real estate | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 140 | CAD 133 | |
Percentage of Total Portfolio | 4.00% | 4.00% | |
Real estate | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Real estate | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Real estate | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 140 | 133 | |
Infrastructure | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 70 | CAD 58 | |
Percentage of Total Portfolio | 2.00% | 2.00% | |
Infrastructure | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Infrastructure | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Infrastructure | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 70 | 58 | |
Private equity funds | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 6 | CAD 8 | |
Percentage of Total Portfolio | 0.00% | 0.00% | |
Private equity funds | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Private equity funds | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Private equity funds | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 6 | 8 | |
Funds held on deposit | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 136 | CAD 129 | |
Percentage of Total Portfolio | 3.00% | 4.00% | |
Funds held on deposit | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 136 | CAD 129 | |
Funds held on deposit | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Funds held on deposit | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 |
EMPLOYEE POST-RETIREMENT BEN111
EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Net change in the Level III fair value category | ||
Plan assets at fair value – beginning of year | CAD 3,562 | |
Plan assets at fair value – end of year | 3,816 | CAD 3,562 |
Significant Unobservable Inputs (Level III) | ||
Net change in the Level III fair value category | ||
Plan assets at fair value – beginning of year | 199 | 14 |
Purchases and sales | 11 | 183 |
Realized and unrealized gains | 6 | 2 |
Plan assets at fair value – end of year | CAD 216 | CAD 199 |
EMPLOYEE POST-RETIREMENT BEN112
EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Other post-retirement benefit plans, Savings Plan and DC Plans | |||
Company's expected funding contributions for savings plan and DC Plans | CAD 45 | ||
Health care benefits | |||
Assumed average annual rate of increase in the per capita cost of covered health care benefits | 7.00% | ||
Percentage level to which average annual rate was assumed to decrease | 5.00% | ||
Effects of a one per cent change in assumed health care cost trend rates | |||
Effect on total of service and interest cost components, Increase | CAD 1 | ||
Effect on total of service and interest cost components, Decrease | (1) | ||
Effect on post-retirement benefit obligation, Increase | 15 | ||
Effect on post-retirement benefit obligation, Decrease | (13) | ||
Pension Benefit Plans | |||
DB Plans | |||
Company's expected funding contributions | 98 | ||
Other post-retirement benefit plans, Savings Plan and DC Plans | |||
Expected estimated additional letter of credit | 27 | ||
Estimated future benefit payments, which reflect expected future service | |||
2,018 | 181 | ||
2,019 | 187 | ||
2,020 | 190 | ||
2,021 | 196 | ||
2,022 | 200 | ||
2023 to 2027 | CAD 1,054 | ||
Weighted average actuarial assumptions adopted in measuring the benefit obligations | |||
Discount rate | 3.60% | 4.00% | |
Rate of compensation increase | 3.00% | 1.20% | |
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs | |||
Discount rate | 3.95% | 4.20% | 4.15% |
Expected long-term rate of return on plan assets | 6.50% | 6.70% | 6.95% |
Rate of compensation increase | 1.20% | 0.80% | 3.15% |
Net benefit cost | |||
Service cost | CAD 108 | CAD 107 | CAD 108 |
Interest cost | 122 | 127 | 115 |
Expected return on plan assets | (178) | (175) | (155) |
Amortization of actuarial loss | 14 | 20 | 35 |
Amortization of past service cost | 0 | 0 | 2 |
Amortization of regulatory asset | 37 | 27 | 23 |
Amortization of transitional obligation related to regulated business | 0 | 0 | 0 |
Settlement charge – regulatory asset | 2 | 0 | 0 |
Settlement charge – AOCI | 2 | 0 | 0 |
Net Benefit Cost Recognized | 107 | 106 | 128 |
Pre-tax amounts recognized in AOCI | |||
Net loss | 273 | 270 | 247 |
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year | |||
Estimated net loss that will be amortized | 19 | ||
Pre-tax amounts recognized in OCI | |||
Amortization of net loss from AOCI to OCI | (18) | (20) | (34) |
Amortization of prior service costs from AOCI to OCI | 0 | 0 | (2) |
Curtailment | (14) | 0 | 0 |
Settlement | (11) | 0 | 0 |
Funded status adjustment | 46 | 43 | (67) |
Total pre-tax amounts recognized in OCI | 3 | CAD 23 | CAD (103) |
Other Post-Retirement Benefit Plans | |||
DB Plans | |||
Company's expected funding contributions | 7 | ||
Estimated future benefit payments, which reflect expected future service | |||
2,018 | 19 | ||
2,019 | 20 | ||
2,020 | 20 | ||
2,021 | 20 | ||
2,022 | 20 | ||
2023 to 2027 | CAD 98 | ||
Weighted average actuarial assumptions adopted in measuring the benefit obligations | |||
Discount rate | 3.70% | 4.15% | |
Rate of compensation increase | 0.00% | 0.00% | |
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs | |||
Discount rate | 4.15% | 4.30% | 4.20% |
Expected long-term rate of return on plan assets | 6.05% | 5.95% | 4.60% |
Rate of compensation increase | 0.00% | 0.00% | 0.00% |
Net benefit cost | |||
Service cost | CAD 4 | CAD 3 | CAD 3 |
Interest cost | 14 | 13 | 10 |
Expected return on plan assets | (21) | (11) | (2) |
Amortization of actuarial loss | 1 | 2 | 3 |
Amortization of past service cost | 0 | 0 | 1 |
Amortization of regulatory asset | 1 | 1 | 1 |
Amortization of transitional obligation related to regulated business | 0 | 2 | 2 |
Settlement charge – regulatory asset | 0 | 0 | 0 |
Settlement charge – AOCI | 0 | 0 | 0 |
Net Benefit Cost Recognized | (1) | 10 | 18 |
Pre-tax amounts recognized in AOCI | |||
Net loss | 11 | 21 | 28 |
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year | |||
Estimated net loss that will be amortized | 1 | ||
Pre-tax amounts recognized in OCI | |||
Amortization of net loss from AOCI to OCI | (1) | (2) | (4) |
Amortization of prior service costs from AOCI to OCI | 0 | 0 | (1) |
Curtailment | (2) | 0 | 0 |
Settlement | 0 | 0 | 0 |
Funded status adjustment | (7) | (5) | (7) |
Total pre-tax amounts recognized in OCI | CAD (10) | CAD (7) | CAD (12) |
RISK MANAGEMENT AND FINANCIA113
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) CAD in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Derivative [Line Items] | ||||
Fair Value | CAD (54) | CAD (428) | ||
Designated as a net investment hedge | ||||
Derivative [Line Items] | ||||
Fair Value | (194) | (432) | ||
Designated as a net investment hedge | US$ denominated | ||||
Derivative [Line Items] | ||||
Notional or Principal Amount | $ | $ 1,700 | $ 2,500 | ||
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019) | ||||
Derivative [Line Items] | ||||
Fair Value | (199) | (425) | ||
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019) | US$ denominated | ||||
Derivative [Line Items] | ||||
Notional or Principal Amount | $ | 1,200 | 2,350 | ||
Net realized gains related to the interest component | 4 | 6 | ||
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2018) | ||||
Derivative [Line Items] | ||||
Fair Value | 5 | 0 | ||
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2018) | US$ denominated | ||||
Derivative [Line Items] | ||||
Notional or Principal Amount | $ | 500 | 0 | ||
Designated as a net investment hedge | U.S. dollar foreign exchange forward contracts | ||||
Derivative [Line Items] | ||||
Fair Value | CAD 0 | CAD (7) | ||
Designated as a net investment hedge | U.S. dollar foreign exchange forward contracts | US$ denominated | ||||
Derivative [Line Items] | ||||
Notional or Principal Amount | $ | $ 0 | $ 150 |
RISK MANAGEMENT AND FINANCIA114
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge CAD in Millions, $ in Millions | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) |
Derivative [Line Items] | ||||
Notional amount | CAD | CAD 25,400 | CAD 26,600 | ||
Fair value | CAD | CAD 28,900 | CAD 29,400 | ||
US$ denominated | ||||
Derivative [Line Items] | ||||
Notional amount | $ | $ 20,200 | $ 19,800 | ||
Fair value | $ | $ 23,100 | $ 21,900 |
RISK MANAGEMENT AND FINANCIA115
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) CAD in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | |
Concentration Risk [Line Items] | |||
Financing receivable, recorded investment, past due | CAD 0 | ||
Provision for other credit losses | 0 | ||
Customer Concentration Risk | |||
Concentration Risk [Line Items] | |||
Credit risk concentration | CAD 0 | CAD 200 | $ 149 |
RISK MANAGEMENT AND FINANCIA116
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) CAD in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Carrying and fair values of non-derivative financial instruments | ||||
Long-term debt, including current portion (Note 17) | CAD (34,677) | CAD (40,048) | ||
Junior subordinated notes (Note 18) | (7,007) | (3,931) | ||
Long-term debt | $ | $ 1,100 | $ 850 | ||
Interest rate swap agreements | ||||
Carrying and fair values of non-derivative financial instruments | ||||
Fair value adjustments - gains (losses) | 4 | 2 | ||
Long-term debt hedged | $ | $ 1,100 | $ 850 | ||
Level II | Carrying Amount | ||||
Carrying and fair values of non-derivative financial instruments | ||||
Long-term debt, including current portion (Note 17) | (34,741) | (40,150) | ||
Junior subordinated notes (Note 18) | (7,007) | (3,931) | ||
Total liabilities | (41,748) | (44,081) | ||
Level II | Fair Value | ||||
Carrying and fair values of non-derivative financial instruments | ||||
Long-term debt, including current portion (Note 17) | (40,180) | (45,047) | ||
Junior subordinated notes (Note 18) | (7,233) | (3,825) | ||
Total liabilities | CAD (47,413) | CAD (48,872) |
RISK MANAGEMENT AND FINANCIA117
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) MXN in Millions, CAD in Millions, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2017CADGWhBcfMMBbls | Dec. 31, 2016CADGWhBcfMMBbls | Dec. 31, 2017MXN | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Total Derivatives | |||||
Derivative Assets | CAD 405 | CAD 509 | |||
Derivative Liabilities | (459) | (937) | |||
Total Derivatives | (54) | (428) | |||
Total trading activity | |||||
Total Derivatives | |||||
Derivative Assets | 389 | 480 | |||
Derivative Liabilities | (244) | (486) | |||
Total Derivatives | 145 | (6) | |||
Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 8 | 12 | |||
Derivative Liabilities | (8) | (1) | |||
Total Derivatives | 0 | 11 | |||
Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 1 | |||
Derivative Liabilities | (5) | (2) | |||
Total Derivatives | (5) | (1) | |||
Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 8 | 16 | |||
Derivative Liabilities | (202) | (448) | |||
Total Derivatives | (194) | (432) | |||
Commodities | Power | |||||
Total Derivatives | |||||
Derivative Assets | 319 | 479 | |||
Derivative Liabilities | CAD (242) | CAD (448) | |||
Commodities | Power | Not designated as hedging instrument | Purchases | |||||
Notional and Maturity Summary | |||||
Power (in GWH) | GWh | 66,132 | 86,887 | |||
Commodities | Power | Not designated as hedging instrument | Sales | |||||
Notional and Maturity Summary | |||||
Power (in GWH) | GWh | 42,836 | 58,561 | |||
Commodities | Natural Gas | Not designated as hedging instrument | Purchases | |||||
Notional and Maturity Summary | |||||
Natural gas (in BCF and mmbbls) | Bcf | 133 | 182 | |||
Commodities | Natural Gas | Not designated as hedging instrument | Sales | |||||
Notional and Maturity Summary | |||||
Natural gas (in BCF and mmbbls) | Bcf | 135 | 147 | |||
Commodities | Liquids | Not designated as hedging instrument | Purchases | |||||
Notional and Maturity Summary | |||||
Natural gas (in BCF and mmbbls) | MMBbls | 6 | 6 | |||
Commodities | Liquids | Not designated as hedging instrument | Sales | |||||
Notional and Maturity Summary | |||||
Natural gas (in BCF and mmbbls) | MMBbls | 7 | 6 | |||
Foreign exchange | |||||
Total Derivatives | |||||
Derivative Assets | CAD 78 | CAD 26 | |||
Derivative Liabilities | (212) | (486) | |||
Notional and Maturity Summary | |||||
Notional or Principal Amount | MXN 100 | $ 2,931 | $ 2,394 | ||
Foreign exchange | Power | |||||
Notional and Maturity Summary | |||||
Notional or Principal Amount | 0 | 0 | 0 | ||
Foreign exchange | Natural Gas | |||||
Notional and Maturity Summary | |||||
Notional or Principal Amount | 0 | 0 | 0 | ||
Foreign exchange | Liquids | |||||
Notional and Maturity Summary | |||||
Notional or Principal Amount | 0 | 0 | 0 | ||
Interest rate | |||||
Total Derivatives | |||||
Derivative Assets | 8 | 4 | |||
Derivative Liabilities | (5) | (3) | |||
Notional and Maturity Summary | |||||
Notional or Principal Amount | MXN 0 | $ 2,300 | $ 1,550 | ||
Other current assets | |||||
Total Derivatives | |||||
Derivative Assets | 332 | 376 | |||
Other current assets | Total trading activity | |||||
Total Derivatives | |||||
Derivative Assets | 320 | 362 | |||
Other current assets | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 4 | 7 | |||
Other current assets | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 1 | |||
Other current assets | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 8 | 6 | |||
Other current assets | Commodities | |||||
Total Derivatives | |||||
Derivative Assets | 250 | 357 | |||
Other current assets | Commodities | Commodities | |||||
Total Derivatives | |||||
Derivative Assets | 249 | 351 | |||
Other current assets | Commodities | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 1 | 6 | |||
Other current assets | Commodities | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Other current assets | Commodities | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Other current assets | Foreign exchange | |||||
Total Derivatives | |||||
Derivative Assets | 78 | 16 | |||
Other current assets | Foreign exchange | Foreign exchange | |||||
Total Derivatives | |||||
Derivative Assets | 70 | 10 | |||
Other current assets | Foreign exchange | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Other current assets | Foreign exchange | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Other current assets | Foreign exchange | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 8 | 6 | |||
Other current assets | Interest rate | |||||
Total Derivatives | |||||
Derivative Assets | 4 | 3 | |||
Other current assets | Interest rate | Interest rate | |||||
Total Derivatives | |||||
Derivative Assets | 1 | 1 | |||
Other current assets | Interest rate | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 3 | 1 | |||
Other current assets | Interest rate | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 1 | |||
Other current assets | Interest rate | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Intangible and other assets | |||||
Total Derivatives | |||||
Derivative Assets | 73 | 133 | |||
Intangible and other assets | Total trading activity | |||||
Total Derivatives | |||||
Derivative Assets | 69 | 118 | |||
Intangible and other assets | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 4 | 5 | |||
Intangible and other assets | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Intangible and other assets | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 10 | |||
Intangible and other assets | Commodities | |||||
Total Derivatives | |||||
Derivative Assets | 69 | 122 | |||
Intangible and other assets | Commodities | Commodities | |||||
Total Derivatives | |||||
Derivative Assets | 69 | 118 | |||
Intangible and other assets | Commodities | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 4 | |||
Intangible and other assets | Commodities | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Intangible and other assets | Commodities | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Intangible and other assets | Foreign exchange | |||||
Total Derivatives | |||||
Derivative Assets | 10 | ||||
Intangible and other assets | Foreign exchange | Foreign exchange | |||||
Total Derivatives | |||||
Derivative Assets | 0 | ||||
Intangible and other assets | Foreign exchange | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | ||||
Intangible and other assets | Foreign exchange | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | ||||
Intangible and other assets | Foreign exchange | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 10 | ||||
Intangible and other assets | Interest rate | |||||
Total Derivatives | |||||
Derivative Assets | 4 | 1 | |||
Intangible and other assets | Interest rate | Interest rate | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Intangible and other assets | Interest rate | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 4 | 1 | |||
Intangible and other assets | Interest rate | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Intangible and other assets | Interest rate | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Assets | 0 | 0 | |||
Accounts payable and other | |||||
Total Derivatives | |||||
Derivative Liabilities | (387) | (607) | |||
Accounts payable and other | Total trading activity | |||||
Total Derivatives | |||||
Derivative Liabilities | (218) | (368) | |||
Accounts payable and other | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (6) | (1) | |||
Accounts payable and other | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (4) | (1) | |||
Accounts payable and other | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (159) | (237) | |||
Accounts payable and other | Commodities | |||||
Total Derivatives | |||||
Derivative Liabilities | (214) | (330) | |||
Accounts payable and other | Commodities | Commodities | |||||
Total Derivatives | |||||
Derivative Liabilities | (208) | (330) | |||
Accounts payable and other | Commodities | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (6) | 0 | |||
Accounts payable and other | Commodities | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Accounts payable and other | Commodities | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Accounts payable and other | Foreign exchange | |||||
Total Derivatives | |||||
Derivative Liabilities | (169) | (275) | |||
Accounts payable and other | Foreign exchange | Foreign exchange | |||||
Total Derivatives | |||||
Derivative Liabilities | (10) | (38) | |||
Accounts payable and other | Foreign exchange | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Accounts payable and other | Foreign exchange | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Accounts payable and other | Foreign exchange | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (159) | (237) | |||
Accounts payable and other | Interest rate | |||||
Total Derivatives | |||||
Derivative Liabilities | (4) | (2) | |||
Accounts payable and other | Interest rate | Interest rate | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Accounts payable and other | Interest rate | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | (1) | |||
Accounts payable and other | Interest rate | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (4) | (1) | |||
Accounts payable and other | Interest rate | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Other long-term liabilities | |||||
Total Derivatives | |||||
Derivative Liabilities | (72) | (330) | |||
Other long-term liabilities | Total trading activity | |||||
Total Derivatives | |||||
Derivative Liabilities | (26) | (118) | |||
Other long-term liabilities | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (2) | 0 | |||
Other long-term liabilities | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (1) | (1) | |||
Other long-term liabilities | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (43) | (211) | |||
Other long-term liabilities | Commodities | |||||
Total Derivatives | |||||
Derivative Liabilities | (28) | (118) | |||
Other long-term liabilities | Commodities | Commodities | |||||
Total Derivatives | |||||
Derivative Liabilities | (26) | (118) | |||
Other long-term liabilities | Commodities | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (2) | 0 | |||
Other long-term liabilities | Commodities | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Other long-term liabilities | Commodities | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Other long-term liabilities | Foreign exchange | |||||
Total Derivatives | |||||
Derivative Liabilities | (43) | (211) | |||
Other long-term liabilities | Foreign exchange | Foreign exchange | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Other long-term liabilities | Foreign exchange | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Other long-term liabilities | Foreign exchange | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Other long-term liabilities | Foreign exchange | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (43) | (211) | |||
Other long-term liabilities | Interest rate | |||||
Total Derivatives | |||||
Derivative Liabilities | (1) | (1) | |||
Other long-term liabilities | Interest rate | Interest rate | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Other long-term liabilities | Interest rate | Cash Flow Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
Other long-term liabilities | Interest rate | Fair Value Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | (1) | (1) | |||
Other long-term liabilities | Interest rate | Net Investment Hedges | |||||
Total Derivatives | |||||
Derivative Liabilities | 0 | 0 | |||
LMCI Restricted Investments | |||||
Gain (Loss) on Investments, Realized and Unrealized | |||||
Net unrealized (losses)/gains in the year ended December 31 | (3) | (28) | |||
Net realized (losses)/gains in the year ended December 31 | (1) | 0 | |||
Other Restricted Investments | |||||
Gain (Loss) on Investments, Realized and Unrealized | |||||
Net unrealized (losses)/gains in the year ended December 31 | 1 | (1) | |||
Net realized (losses)/gains in the year ended December 31 | 0 | 0 | |||
Fixed income securities | LMCI Restricted Investments | |||||
Fair value | |||||
Fixed income securities (maturing within 1 year) | 0 | 0 | |||
Fixed income securities (maturing within 1-5 years) | 0 | 0 | |||
Fixed income securities (maturing within 5-10 years) | 14 | 9 | |||
Fixed income securities (maturing after 10 years) | 790 | 513 | |||
Fixed income securities | 804 | 522 | |||
Fixed income securities | Other Restricted Investments | |||||
Fair value | |||||
Fixed income securities (maturing within 1 year) | 23 | 19 | |||
Fixed income securities (maturing within 1-5 years) | 107 | 117 | |||
Fixed income securities (maturing within 5-10 years) | 0 | 0 | |||
Fixed income securities (maturing after 10 years) | 0 | 0 | |||
Fixed income securities | CAD 130 | CAD 136 |
RISK MANAGEMENT AND FINANCIA118
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses)/Gains (Details) - CAD | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commodities | |||
Derivative [Line Items] | |||
Amount of unrealized gains/(losses) in the year | CAD 62,000,000 | CAD 123,000,000 | CAD (37,000,000) |
Amount of realized (losses)/gains in the year | (107,000,000) | (204,000,000) | (151,000,000) |
Commodities | Derivative instruments in hedging relationships | |||
Derivative [Line Items] | |||
Amount of realized gains/(losses) in the year | 23,000,000 | (167,000,000) | (179,000,000) |
Foreign exchange | |||
Derivative [Line Items] | |||
Amount of unrealized gains/(losses) in the year | 88,000,000 | 25,000,000 | (21,000,000) |
Amount of realized (losses)/gains in the year | 18,000,000 | 62,000,000 | (112,000,000) |
Foreign exchange | Derivative instruments in hedging relationships | |||
Derivative [Line Items] | |||
Amount of realized gains/(losses) in the year | 5,000,000 | (101,000,000) | 0 |
Interest rate | |||
Derivative [Line Items] | |||
Amount of unrealized gains/(losses) in the year | (1,000,000) | 0 | 0 |
Amount of realized (losses)/gains in the year | 1,000,000 | 0 | 0 |
Interest rate | Derivative instruments in hedging relationships | |||
Derivative [Line Items] | |||
Amount of realized gains/(losses) in the year | 1,000,000 | 4,000,000 | CAD 8,000,000 |
U.S. Northeast Merchant Power Assets | |||
Derivative [Line Items] | |||
Gain (loss) on cash flow hedge | CAD 0 | ||
Loss on cash flow hedge | CAD 42,000,000 |
RISK MANAGEMENT AND FINANCIA119
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - CAD | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Components of OCI related to derivatives | |||
Components of fair value hedge ineffectiveness, amounts excluded from assessment of hedge effectiveness, amount | CAD 0 | CAD 0 | |
Cash Flow Hedges | |||
Components of OCI related to derivatives | |||
Change in fair value of derivative instruments recognized in OCI (effective portion) | 3,000,000 | 44,000,000 | CAD (92,000,000) |
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion) | (3,000,000) | 71,000,000 | 144,000,000 |
Cash Flow Hedges | Commodities | Power | |||
Components of OCI related to derivatives | |||
Change in fair value of derivative instruments recognized in OCI (effective portion) | (1,000,000) | 39,000,000 | (92,000,000) |
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion) | (20,000,000) | 57,000,000 | 128,000,000 |
Cash Flow Hedges | Interest rate | |||
Components of OCI related to derivatives | |||
Change in fair value of derivative instruments recognized in OCI (effective portion) | 4,000,000 | 5,000,000 | 0 |
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion) | CAD 17,000,000 | CAD 14,000,000 | CAD 16,000,000 |
RISK MANAGEMENT AND FINANCIA120
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative – Asset | ||
Gross Derivative Instruments Presented on the Balance Sheet | CAD 405,000,000 | CAD 509,000,000 |
Amounts Available for Offset | (255,000,000) | (389,000,000) |
Net Amounts | 150,000,000 | 120,000,000 |
Derivative – Liability | ||
Gross Derivative Instruments Presented on the Balance Sheet | (459,000,000) | (937,000,000) |
Amounts Available for Offset | 255,000,000 | 389,000,000 |
Net Amounts | (204,000,000) | (548,000,000) |
Cash collateral provided by the Company | 165,000,000 | 305,000,000 |
Letters of credit provided by the Company | 30,000,000 | 27,000,000 |
Cash collateral received by the Company | 0 | 0 |
Letters of credit received by the Company | 3,000,000 | 3,000,000 |
Credit Risk Related Contingent Features | ||
Aggregate fair value of derivative instruments in a net liability position | 2,000,000 | 19,000,000 |
Derivative liability, fair value of collateral | 0 | 0 |
Additional collateral required if credit-risk-related contingent features were triggered | 2,000,000 | 19,000,000 |
Foreign exchange | ||
Derivative – Asset | ||
Gross Derivative Instruments Presented on the Balance Sheet | 78,000,000 | 26,000,000 |
Amounts Available for Offset | (56,000,000) | (26,000,000) |
Net Amounts | 22,000,000 | 0 |
Derivative – Liability | ||
Gross Derivative Instruments Presented on the Balance Sheet | (212,000,000) | (486,000,000) |
Amounts Available for Offset | 56,000,000 | 26,000,000 |
Net Amounts | (156,000,000) | (460,000,000) |
Interest rate | ||
Derivative – Asset | ||
Gross Derivative Instruments Presented on the Balance Sheet | 8,000,000 | 4,000,000 |
Amounts Available for Offset | (1,000,000) | (1,000,000) |
Net Amounts | 7,000,000 | 3,000,000 |
Derivative – Liability | ||
Gross Derivative Instruments Presented on the Balance Sheet | (5,000,000) | (3,000,000) |
Amounts Available for Offset | 1,000,000 | 1,000,000 |
Net Amounts | (4,000,000) | (2,000,000) |
Power | Commodities | ||
Derivative – Asset | ||
Gross Derivative Instruments Presented on the Balance Sheet | 319,000,000 | 479,000,000 |
Amounts Available for Offset | (198,000,000) | (362,000,000) |
Net Amounts | 121,000,000 | 117,000,000 |
Derivative – Liability | ||
Gross Derivative Instruments Presented on the Balance Sheet | (242,000,000) | (448,000,000) |
Amounts Available for Offset | 198,000,000 | 362,000,000 |
Net Amounts | CAD (44,000,000) | CAD (86,000,000) |
RISK MANAGEMENT AND FINANCIA121
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Hierarchy | ||
Derivative Instrument Assets: | CAD 405 | CAD 509 |
Derivative Instrument Liabilities: | (459) | (937) |
Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 319 | 479 |
Derivative Instrument Liabilities: | (242) | (448) |
Foreign exchange contracts | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 78 | 26 |
Derivative Instrument Liabilities: | (212) | (486) |
Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 8 | 4 |
Derivative Instrument Liabilities: | (5) | (3) |
Recurring basis | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | (54) | (428) |
Recurring basis | Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 319 | 479 |
Derivative Instrument Liabilities: | (242) | (448) |
Recurring basis | Foreign exchange contracts | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 78 | 26 |
Derivative Instrument Liabilities: | (212) | (486) |
Recurring basis | Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 8 | 4 |
Derivative Instrument Liabilities: | (5) | (3) |
Recurring basis | Quoted Prices in Active Markets (Level I) | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | (6) | 32 |
Recurring basis | Quoted Prices in Active Markets (Level I) | Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 21 | 134 |
Derivative Instrument Liabilities: | (27) | (102) |
Recurring basis | Quoted Prices in Active Markets (Level I) | Foreign exchange contracts | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 0 | 0 |
Derivative Instrument Liabilities: | 0 | 0 |
Recurring basis | Quoted Prices in Active Markets (Level I) | Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 0 | 0 |
Derivative Instrument Liabilities: | 0 | 0 |
Recurring basis | Significant Other Observable Inputs (Level II) | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | (41) | (476) |
Recurring basis | Significant Other Observable Inputs (Level II) | Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 283 | 326 |
Derivative Instrument Liabilities: | (193) | (343) |
Recurring basis | Significant Other Observable Inputs (Level II) | Foreign exchange contracts | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 78 | 26 |
Derivative Instrument Liabilities: | (212) | (486) |
Recurring basis | Significant Other Observable Inputs (Level II) | Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 8 | 4 |
Derivative Instrument Liabilities: | (5) | (3) |
Recurring basis | Significant Unobservable Inputs (Level III) | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | (7) | 16 |
Recurring basis | Significant Unobservable Inputs (Level III) | Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 15 | 19 |
Derivative Instrument Liabilities: | (22) | (3) |
Recurring basis | Significant Unobservable Inputs (Level III) | Foreign exchange contracts | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 0 | 0 |
Derivative Instrument Liabilities: | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level III) | Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 0 | 0 |
Derivative Instrument Liabilities: | CAD 0 | CAD 0 |
RISK MANAGEMENT AND FINANCIA122
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Energy Revenue | ||
Net change in the Level III fair value category | ||
Revenues include unrealized gains (loss) attributed to derivatives in the Level III category | CAD (7) | CAD 7 |
Commodity contract | Power | ||
Net change in the Level III fair value category | ||
Balance at beginning of year | 16 | 9 |
Transfers out of Level III | (19) | (1) |
Total (losses)/gains included in Net income | (17) | 13 |
Sales | (5) | (3) |
Settlements | 18 | (2) |
Balance at end of year | (7) | CAD 16 |
Commodity contract | Power | Level III | ||
Net change in the Level III fair value category | ||
Decrease in fair value of outstanding derivative instruments included in Level III due to a 10% increase in commodity prices | 2 | |
Increase in fair value of outstanding derivative instruments included in Level III due to a 10% decrease in commodity prices | CAD 2 |
CHANGES IN OPERATING WORKING123
CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CHANGES IN OPERATING WORKING CAPITAL | |||
Increase in Accounts receivable | CAD (573) | CAD (487) | CAD (19) |
Increase in Inventories | (38) | (87) | (3) |
Decrease/(increase) in Assets held for sale | 14 | (13) | 0 |
Decrease/(increase) in Other current assets | 189 | 328 | (273) |
Increase/(decrease) in Accounts payable and other | 149 | 432 | (103) |
Increase in Accrued interest | 12 | 62 | 91 |
(Decrease)/increase in Liabilities related to assets held for sale | (25) | 16 | 0 |
(Increase)/decrease in Operating Working Capital | CAD (272) | CAD 251 | CAD (307) |
OTHER ACQUISITIONS AND DISPO124
OTHER ACQUISITIONS AND DISPOSITIONS (Details) CAD in Millions, $ in Millions | Dec. 19, 2017CAD | Jun. 02, 2017USD ($) | Jun. 01, 2017USD ($) | Apr. 19, 2017USD ($) | May 01, 2016USD ($) | Mar. 31, 2016CAD | Mar. 31, 2016USD ($) | Feb. 29, 2016USD ($) | Jan. 31, 2016USD ($) | Dec. 31, 2015CAD | Apr. 30, 2015USD ($) | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Nov. 30, 2015 |
Business Acquisition [Line Items] | |||||||||||||||
Contributions to equity investments | CAD | CAD 1,681 | CAD 765 | CAD 493 | ||||||||||||
Gain (loss) on disposal | CAD | 631 | (833) | (125) | ||||||||||||
Proceeds from sale of assets, net of transaction costs | CAD | CAD 5,317 | 6 | CAD 0 | ||||||||||||
Natural Gas – Ironwood | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Purchase price | $ | $ 653 | ||||||||||||||
Iroquois | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Ownership interest (percent) | 50.00% | 49.35% | 49.35% | ||||||||||||
Additional ownership acquired (percent) | 0.65% | 4.87% | 4.87% | ||||||||||||
Contributions to equity investments | $ | $ 7 | $ 54 | |||||||||||||
Iroquois | U.S. Natural Gas Pipelines | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Ownership interest (percent) | 0.66% | 50.00% | 50.00% | ||||||||||||
Iroquois | Disposal group, disposed of by sale, not discontinued operations | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Ownership interest before transaction, percent | 49.34% | ||||||||||||||
PNGTS | Disposal group, disposed of by sale, not discontinued operations | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Ownership interest before transaction, percent | 11.81% | 49.90% | |||||||||||||
Total consideration | $ | $ 223 | ||||||||||||||
Cash received | $ | 188 | ||||||||||||||
Assumption of debt by purchaser | $ | $ 35 | ||||||||||||||
Gas Transmission Northwest | Disposal group, disposed of by sale, not discontinued operations | Natural Gas | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Ownership interest before transaction, percent | 30.00% | ||||||||||||||
Total consideration | $ | $ 457 | ||||||||||||||
Cash received | $ | 264 | ||||||||||||||
Assumption of debt by purchaser | $ | 98 | ||||||||||||||
Gas Transmission Northwest | Disposal group, disposed of by sale, not discontinued operations | Natural Gas | Class B units | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Receipt of new units | $ | $ 95 | ||||||||||||||
Ontario Solar Assets | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Proceeds from sale of assets, net of transaction costs | CAD | CAD 541 | ||||||||||||||
Gain (loss) on disposition of property plant equipment | CAD | 127 | ||||||||||||||
Gain (loss) on disposition of property plant equipment, net of tax | CAD | CAD 136 | ||||||||||||||
TC Hydro | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Proceeds from sale of assets, net of transaction costs | $ | $ 1,070 | ||||||||||||||
Gain (loss) on disposition of property plant equipment | CAD | CAD 715 | ||||||||||||||
Gain (loss) on disposition of property plant equipment, net of tax | CAD | 440 | ||||||||||||||
Gain (loss) on disposition of property plant and equipment foreign currency translation amount | CAD | 5 | ||||||||||||||
Ravenswood, Ironwood, Kibby Wind and Ocean State Power | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Proceeds from sale of assets, net of transaction costs | $ | $ 2,029 | ||||||||||||||
Gain (loss) on disposition of property plant equipment | CAD | (211) | (829) | |||||||||||||
Gain (loss) on disposition of property plant equipment, net of tax | CAD | (167) | (863) | |||||||||||||
Foreign currency translation gain on assets held for sale | CAD | CAD 2 | CAD 70 | |||||||||||||
Bruce B | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Ownership interest (percent) | 46.50% | 46.50% | 31.60% | ||||||||||||
Additional ownership acquired (percent) | 14.89% | 14.89% | |||||||||||||
Contributions to equity investments | CAD | CAD 236 | ||||||||||||||
Bruce Power | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Ownership interest (percent) | 48.50% | 48.50% | |||||||||||||
Bruce A | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Ownership interest (percent) | 48.90% | ||||||||||||||
PNGTS And Iroquois Transmission systems | Disposal group, disposed of by sale, not discontinued operations | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total consideration | $ | $ 765 | ||||||||||||||
Cash received | $ | 597 | ||||||||||||||
Assumption of debt by purchaser | $ | $ 168 | ||||||||||||||
TC Offshore LLC | Disposal group, not discontinued operations | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Gain (loss) on disposal | CAD | CAD (4) | CAD (125) |
COMMITMENTS, CONTINGENCIES A125
COMMITMENTS, CONTINGENCIES AND GUARANTEES - Operating Leases (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Minimum Lease Payments | |||
2,018 | CAD 75 | ||
2,019 | 76 | ||
2,020 | 73 | ||
2,021 | 71 | ||
2,022 | 63 | ||
2023 and thereafter | 443 | ||
Minimum Lease Payments | 801 | ||
Amounts Recoverable under Subleases | |||
2,018 | 4 | ||
2,019 | 2 | ||
2,020 | 2 | ||
2,021 | 1 | ||
2,022 | 0 | ||
2023 and thereafter | 2 | ||
Amounts Recoverable under Subleases | 11 | ||
Net Payments | |||
2,018 | 71 | ||
2,019 | 74 | ||
2,020 | 71 | ||
2,021 | 70 | ||
2,022 | 63 | ||
2023 and thereafter | 441 | ||
Net Payments | 790 | ||
Rent Expense | |||
Net rental expense on operating leases | CAD 93 | CAD 145 | CAD 131 |
Minimum | |||
Rent Expense | |||
Operating leases optional renewable terms, low end of range | 1 year | ||
Maximum | |||
Rent Expense | |||
Operating leases optional renewable terms, low end of range | 25 years |
COMMITMENTS, CONTINGENCIES A126
COMMITMENTS, CONTINGENCIES AND GUARANTEES - Other Commitments and Contingencies (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Contingencies | ||
Amount accrued related to operating facilities for the estimated expenses to remediate the sites | CAD 34 | CAD 39 |
Canadian Natural Gas Pipelines | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 300 | |
U.S. Natural Gas Pipelines | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 400 | |
Mexico Natural Gas Pipelines | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 700 | |
Liquids Pipelines | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 100 | |
Energy | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 400 | |
Corporate | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | CAD 100 |
COMMITMENTS, CONTINGENCIES A127
COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Guarantees | ||
Potential Exposure | CAD 507 | CAD 980 |
Carrying Value | 16 | 82 |
Sur de Texas | ||
Guarantees | ||
Potential Exposure | 315 | 805 |
Carrying Value | 2 | 53 |
Bruce Power | ||
Guarantees | ||
Potential Exposure | 88 | 88 |
Carrying Value | 1 | 1 |
Other jointly owned entities | ||
Guarantees | ||
Potential Exposure | 104 | 87 |
Carrying Value | CAD 13 | CAD 28 |
CORPORATE RESTRUCTURING COST128
CORPORATE RESTRUCTURING COSTS (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Restructuring Cost and Reserve [Line Items] | |||
Provision recorded for restructuring charges | CAD 62 | CAD 99 | CAD 87 |
Total corporate restructuring charges | 6 | 44 | |
Restructuring and related activities, costs capitalized | 8 | ||
Employee Severance | |||
Restructuring Cost and Reserve [Line Items] | |||
Corporate restructuring costs incurred | 122 | ||
Provision recorded for restructuring charges | 9 | 36 | 60 |
Total corporate restructuring charges | 0 | 0 | 209 |
Restructuring costs recoverable through regulatory and tolling structures | 58 | ||
Cumulative restructuring costs incurred | 86 | ||
Employee Severance | Regulatory asset | |||
Restructuring Cost and Reserve [Line Items] | |||
Total corporate restructuring charges | 3 | 22 | 44 |
Employee Severance | Plant operating cost and other | |||
Restructuring Cost and Reserve [Line Items] | |||
Total corporate restructuring charges | 3 | 22 | CAD 157 |
Lease Commitments | |||
Restructuring Cost and Reserve [Line Items] | |||
Total corporate restructuring charges | 6 | CAD 44 | |
Cumulative restructuring costs incurred | CAD 38 |
CORPORATE RESTRUCTURING COSTS -
CORPORATE RESTRUCTURING COSTS - Schedule of Change In Restructuring Liability (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Restructuring Reserve [Roll Forward] | |||
Restructuring liability as at the beginning of period | CAD 99 | CAD 87 | |
Restructuring charges | 6 | 44 | |
Cash payments | (43) | (32) | |
Restructuring Liability as at the end of period | 62 | 99 | CAD 87 |
Employee Severance | |||
Restructuring Reserve [Roll Forward] | |||
Restructuring liability as at the beginning of period | 36 | 60 | |
Restructuring charges | 0 | 0 | 209 |
Cash payments | (27) | (24) | |
Restructuring Liability as at the end of period | 9 | 36 | 60 |
Lease Commitments | |||
Restructuring Reserve [Roll Forward] | |||
Restructuring liability as at the beginning of period | 63 | 27 | |
Restructuring charges | 6 | 44 | |
Cash payments | (16) | (8) | |
Restructuring Liability as at the end of period | CAD 53 | CAD 63 | CAD 27 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - CAD | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | |||
Outstanding December 31 | CAD 2,551,000,000 | CAD 2,358,000,000 | |
Interest expense, related party | 68,000,000 | 38,000,000 | CAD 28,000,000 |
Demand Credit Facility | |||
Related Party Transaction [Line Items] | |||
Outstanding December 31 | CAD 2,551,000,000 | CAD 2,358,000,000 | |
Effective Interest Rate | 3.20% | 2.70% | |
Transcanada | |||
Related Party Transaction [Line Items] | |||
Interest income, related party | CAD 0 | CAD 19,000,000 | 29,000,000 |
Accounts payable, related parties | 16,000,000 | 19,000,000 | |
Interest Related Party | |||
Related Party Transaction [Line Items] | |||
Interest paid | 68,000,000 | CAD 36,000,000 | CAD 29,000,000 |
Unsecured Loan Facility | Line of Credit | Operated affiliates | |||
Related Party Transaction [Line Items] | |||
Amount | CAD 3,000,000,000 |
VARIABLE INTEREST ENTITIES (Det
VARIABLE INTEREST ENTITIES (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Variable interest entity ownership percentage | 100.00% |
VARIABLE INTEREST ENTITIES - As
VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Current Assets | ||||
Cash and cash equivalents | CAD 1,044 | CAD 967 | CAD 813 | CAD 484 |
Accounts receivable | 2,537 | 2,093 | ||
Inventories | 378 | 368 | ||
Other | 691 | 908 | ||
Total Current Assets | 4,650 | 8,053 | ||
Plant, Property and Equipment | 57,277 | 54,475 | ||
Equity Investments | 6,366 | 6,544 | ||
Goodwill | 13,084 | 13,958 | CAD 4,812 | |
Total Assets | 86,010 | 87,941 | ||
Current Liabilities | ||||
Accounts payable and other | 4,071 | 3,876 | ||
Accrued interest | 605 | 595 | ||
Current portion of long-term debt | 2,866 | 1,838 | ||
Total Current Liabilities | 12,408 | 10,018 | ||
Total Regulatory Liabilities | 4,321 | 2,121 | ||
Other Long-Term Liabilities (Note 15) | 727 | 1,183 | ||
Deferred Income Tax Liabilities | 5,403 | 7,662 | ||
Long-Term Debt | 31,875 | 38,312 | ||
Total Liabilities | 61,741 | 63,227 | ||
Variable Interest Entity, Primary Beneficiary | ||||
Current Assets | ||||
Cash and cash equivalents | 41 | 77 | ||
Accounts receivable | 63 | 71 | ||
Inventories | 23 | 25 | ||
Other | 11 | 10 | ||
Total Current Assets | 138 | 183 | ||
Plant, Property and Equipment | 3,535 | 3,685 | ||
Equity Investments | 917 | 606 | ||
Goodwill | 490 | 525 | ||
Intangible and Other Assets | 3 | 1 | ||
Total Assets | 5,083 | 5,000 | ||
Current Liabilities | ||||
Accounts payable and other | 137 | 80 | ||
Dividends payable | 1 | 0 | ||
Accrued interest | 23 | 21 | ||
Current portion of long-term debt | 88 | 76 | ||
Total Current Liabilities | 249 | 177 | ||
Total Regulatory Liabilities | 34 | 34 | ||
Other Long-Term Liabilities (Note 15) | 3 | 4 | ||
Deferred Income Tax Liabilities | 13 | 7 | ||
Long-Term Debt | 3,244 | 2,827 | ||
Total Liabilities | CAD 3,543 | CAD 3,049 |
VARIABLE INTEREST ENTITIES - Ca
VARIABLE INTEREST ENTITIES - Carrying Value of VIEs and Maximum Exposure (Details) - Variable Interest Entity, Not Primary Beneficiary - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Balance sheet | ||
Equity investments | CAD 4,372 | CAD 4,964 |
Off-balance sheet | ||
Potential exposure to guarantees | 171 | 163 |
Maximum exposure to loss | CAD 4,543 | CAD 5,127 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - CAD shares in Thousands, CAD in Millions | Jan. 31, 2018 | Oct. 31, 2017 | Jul. 31, 2017 | Apr. 28, 2017 | Jan. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Subsequent Event [Line Items] | ||||||||
Proceeds from shares issued | CAD 780 | CAD 4,661 | CAD 0 | |||||
Common Shares | ||||||||
Subsequent Event [Line Items] | ||||||||
Number of shares issued (in shares) | 3,100 | 3,000 | 3,400 | 3,000 | 12,499 | 79,656 | 0 | |
Common Shares | Subsequent Event | ||||||||
Subsequent Event [Line Items] | ||||||||
Number of shares issued (in shares) | 3,400 | |||||||
Proceeds from shares issued | CAD 192 |