Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2018shares | |
Document And Entity Information [Line Items] | |
Entity Registrant Name | TRANSCANADA CORP |
Entity Central Index Key | 1,232,384 |
Document Type | 40-F |
Document Period End Date | Dec. 31, 2018 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Common Stock, Shares Outstanding | 918,096,439 |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | FY |
TRANSCANADA PIPELINES LIMITED | |
Document And Entity Information [Line Items] | |
Entity Registrant Name | TRANSCANADA PIPELINES LTD |
Entity Central Index Key | 99,070 |
Document Type | 40-F |
Document Period End Date | Dec. 31, 2018 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Common Stock, Shares Outstanding | 887,333,320 |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | FY |
Consolidated statement of incom
Consolidated statement of income - CAD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues (Note 5) | |||
Revenues | $ 13,679 | $ 13,449 | $ 12,547 |
Income from Equity Investments (Note 9) | 714 | 773 | 514 |
Operating and Other Expenses | |||
Plant operating costs and other | 3,591 | 3,906 | 3,861 |
Commodity purchases resold | 1,488 | 2,382 | 2,172 |
Property taxes | 569 | 569 | 555 |
Depreciation and amortization | 2,350 | 2,055 | 1,939 |
Goodwill and other asset impairment charges (Notes 8, 11 and 12) | 801 | 1,257 | 1,388 |
Total Operating and Other Expenses | 8,799 | 10,169 | 9,915 |
Gain/(Loss) on Assets Held for Sale/Sold (Note 26) | 170 | 631 | (833) |
Financial Charges | |||
Interest expense (Note 17) | 2,265 | 2,069 | 1,998 |
Allowance for funds used during construction | (526) | (507) | (419) |
Interest income and other | 76 | (184) | (103) |
Total Financial Charges | 1,815 | 1,378 | 1,476 |
Income before Income Taxes | 3,949 | 3,306 | 837 |
Income Tax Expense/(Recovery) (Note 16) | |||
Current | 315 | 149 | 156 |
Deferred | 284 | 566 | 196 |
Deferred – U.S. Tax Reform and 2018 FERC Actions | (167) | (804) | 0 |
Income Tax (Recovery)/Expense | 432 | (89) | 352 |
Net Income | 3,517 | 3,395 | 485 |
Net (loss)/income attributable to non-controlling interests (Note 19) | (185) | 238 | 252 |
Net Income Attributable to Controlling Interests | 3,702 | 3,157 | 233 |
Preferred share dividends | 163 | 160 | 109 |
Net Income Attributable to Common Shares | $ 3,539 | $ 2,997 | $ 124 |
Net Income per Common Share (Note 20) | |||
Basic (in dollars per share) | $ 3.92 | $ 3.44 | $ 0.16 |
Diluted (in dollars per share) | 3.92 | 3.43 | 0.16 |
Dividends Declared per Common Share (in dollars per share) | $ 2.76 | $ 2.5 | $ 2.26 |
Weighted Average Number of Common Shares (Note 20) | |||
Basic (in shares) | 902 | 872 | 759 |
Diluted (in shares) | 903 | 874 | 760 |
Canadian Natural Gas Pipelines | |||
Revenues (Note 5) | |||
Revenues | $ 4,038 | $ 3,693 | $ 3,682 |
U.S. Natural Gas Pipelines | |||
Revenues (Note 5) | |||
Revenues | 4,314 | 3,584 | 2,526 |
Mexico Natural Gas Pipelines | |||
Revenues (Note 5) | |||
Revenues | 619 | 570 | 378 |
Liquids Pipelines | |||
Revenues (Note 5) | |||
Revenues | 2,584 | 2,009 | 1,755 |
Energy | |||
Revenues (Note 5) | |||
Revenues | $ 2,124 | $ 3,593 | $ 4,206 |
Consolidated statement of compr
Consolidated statement of comprehensive income - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | |||
Net Income | $ 3,517 | $ 3,395 | $ 485 |
Other Comprehensive Income/(Loss), Net of Income Taxes | |||
Foreign currency translation gains and losses on net investment in foreign operations | 1,358 | (749) | 3 |
Reclassification of foreign currency translation gains on disposal of foreign operations | 0 | (77) | 0 |
Change in fair value of net investment hedges | (42) | 0 | (10) |
Change in fair value of cash flow hedges | (10) | 3 | 30 |
Reclassification to net income of gains and losses on cash flow hedges | 21 | (2) | 42 |
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans | (114) | (11) | (26) |
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans | 15 | 16 | 16 |
Other comprehensive income/(loss) on equity investments | 86 | (106) | (87) |
Other comprehensive income/(loss) (Note 22) | 1,314 | (926) | (32) |
Comprehensive Income | 4,831 | 2,469 | 453 |
Comprehensive (loss)/income attributable to non-controlling interests | (13) | 83 | 241 |
Comprehensive Income Attributable to Controlling Interests | 4,844 | 2,386 | 212 |
Preferred share dividends | 163 | 160 | 109 |
Comprehensive Income Attributable to Common Shares | $ 4,681 | $ 2,226 | $ 103 |
Consolidated statement of cash
Consolidated statement of cash flows - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash Generated from Operations | |||
Net income | $ 3,517 | $ 3,395 | $ 485 |
Depreciation and amortization | 2,350 | 2,055 | 1,939 |
Goodwill and other asset impairment charges (Notes 8, 11 and 12) | 801 | 1,257 | 1,388 |
Deferred income taxes (Note 16) | 284 | 566 | 196 |
Deferred income taxes – U.S. Tax Reform and 2018 FERC Actions (Note 16) | (167) | (804) | 0 |
Income from equity investments (Note 9) | (714) | (773) | (514) |
Distributions received from operating activities of equity investments (Note 9) | 985 | 970 | 844 |
Employee post-retirement benefits funding, net of expense (Note 23) | (35) | (64) | (3) |
(Gain)/loss on assets held for sale/sold (Note 26) | (170) | (631) | 833 |
Equity allowance for funds used during construction | (374) | (362) | (253) |
Unrealized losses/(gains) on financial instruments | 220 | (149) | (149) |
Other | (40) | 43 | 55 |
(Increase)/decrease in operating working capital (Note 25) | (102) | (273) | 248 |
Net cash provided by operations | 6,555 | 5,230 | 5,069 |
Investing Activities | |||
Capital expenditures (Note 4) | (9,418) | (7,383) | (5,007) |
Capital projects in development (Note 4) | (496) | (146) | (295) |
Contributions to equity investments (Notes 4 and 9) | (1,015) | (1,681) | (765) |
Acquisitions, net of cash acquired | 0 | 0 | (13,608) |
Proceeds from sales of assets, net of transaction costs | 614 | 4,683 | 6 |
Reimbursement of costs related to capital projects in development (Note 12) | 470 | 634 | 0 |
Other distributions from equity investments (Note 9) | 121 | 362 | 727 |
Deferred amounts and other | (295) | (168) | 159 |
Net cash used in investing activities | (10,019) | (3,699) | (18,783) |
Financing Activities | |||
Notes payable issued/(repaid), net | 817 | 1,038 | (329) |
Long-term debt issued, net of issue costs | 6,238 | 3,643 | 12,333 |
Long-term debt repaid | (3,550) | (7,085) | (7,153) |
Junior subordinated notes issued, net of issue costs | 0 | 3,468 | 1,549 |
Dividends on common shares | (1,571) | (1,339) | (1,436) |
Dividends on preferred shares | (158) | (155) | (100) |
Distributions to non-controlling interests | (225) | (283) | (279) |
Common shares issued, net of issue costs | 1,148 | 274 | 7,747 |
Common shares repurchased (Note 20) | 0 | 0 | (14) |
Preferred shares issued, net of issue costs | 0 | 0 | 1,474 |
Partnership units of TC PipeLines, LP issued, net of issue costs | 49 | 225 | 215 |
Common units of Columbia Pipeline Partners LP acquired | 0 | (1,205) | 0 |
Net cash provided by/(used in) financing activities | 2,748 | (1,419) | 14,007 |
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents | 73 | (39) | (127) |
(Decrease)/Increase in Cash and Cash Equivalents | (643) | 73 | 166 |
Cash and Cash Equivalents, Beginning of year | 1,089 | 1,016 | 850 |
Cash and Cash Equivalents, End of year | $ 446 | $ 1,089 | $ 1,016 |
Consolidated balance sheet
Consolidated balance sheet - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Current Assets | ||
Cash and cash equivalents | $ 446 | $ 1,089 |
Accounts receivable | 2,535 | 2,522 |
Inventories | 431 | 378 |
Assets held for sale (Note 6) | 543 | 0 |
Other (Note 7) | 1,180 | 691 |
Total Current Assets | 5,135 | 4,680 |
Plant, Property and Equipment (Note 8) | 66,503 | 57,277 |
Equity Investments (Note 9) | 7,113 | 6,366 |
Regulatory Assets (Note 10) | 1,548 | 1,376 |
Goodwill (Note 11) | 14,178 | 13,084 |
Loan Receivable from Affiliate (Note 9) | 1,315 | 919 |
Intangible and Other Assets (Note 12) | 1,921 | 1,484 |
Restricted Investments | 1,207 | 915 |
Total Assets | 98,920 | 86,101 |
Current Liabilities | ||
Notes payable (Note 13) | 2,762 | 1,763 |
Accounts payable and other (Note 14) | 5,408 | 4,057 |
Dividends payable | 668 | 586 |
Accrued interest | 646 | 605 |
Current portion of long-term debt (Note 17) | 3,462 | 2,866 |
Total Current Liabilities | 12,946 | 9,877 |
Regulatory Liabilities (Note 10) | 3,930 | 4,321 |
Other Long-Term Liabilities (Note 15) | 1,008 | 727 |
Deferred Income Tax Liabilities (Note 16) | 6,026 | 5,403 |
Long-Term Debt (Note 17) | 36,509 | 31,875 |
Junior Subordinated Notes (Note 18) | 7,508 | 7,007 |
Total Liabilities | 67,927 | 59,210 |
EQUITY | ||
Common shares, no par value (Note 20) | 23,174 | 21,167 |
Preferred shares (Note 21) | 3,980 | 3,980 |
Additional paid-in capital | 17 | 0 |
Retained earnings | 2,773 | 1,623 |
Accumulated other comprehensive loss (Note 22) | (606) | (1,731) |
Controlling Interests | 29,338 | 25,039 |
Non-controlling interests (Note 19) | 1,655 | 1,852 |
Total Equity | 30,993 | 26,891 |
Total Liabilities and Equity | $ 98,920 | $ 86,101 |
Consolidated balance sheet (Par
Consolidated balance sheet (Parenthetical) - shares shares in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Common shares issued (in shares) | 918 | 881 |
Common shares outstanding (in shares) | 918 | 881 |
Consolidated statement of equit
Consolidated statement of equity - CAD ($) $ in Millions | Total | Equity Attributable to Controlling Interests | Common Shares | Preferred Shares | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Loss | Equity Attributable to Non-Controlling Interests |
Balance at beginning of year at Dec. 31, 2015 | $ 12,102 | $ 2,499 | $ 7 | $ 2,769 | $ (939) | $ 1,717 | ||
Shares issued: | ||||||||
Under dividend reinvestment and share purchase plan | 177 | |||||||
On exercise of stock options | 74 | |||||||
Under public offerings, net of issue costs | 7,752 | 1,481 | ||||||
Shares repurchased | (6) | (8) | ||||||
Issuance of stock options, net of exercises | 6 | |||||||
Dilution from TC PipeLines, LP units issued | 24 | 215 | ||||||
Asset drop-downs to TC PipeLines, LP | (38) | |||||||
Columbia Pipeline Partners LP acquisition | (40) | |||||||
Reclassification of additional paid-in capital deficit to retained earnings | 9 | |||||||
Net income attributable to controlling interests | $ 233 | 233 | ||||||
Common share dividends | (1,733) | |||||||
Preferred share dividends | (122) | |||||||
Reclassification of additional paid-in capital deficit to retained earnings | (9) | |||||||
Other comprehensive income/(loss) attributable to controlling interests (Note 22) | (32) | (21) | ||||||
Net (loss)/income attributable to non-controlling interests | (252) | 252 | ||||||
Other comprehensive income/(loss) attributable to non-controlling interests | (11) | |||||||
Issuance of TC PipeLines, LP units | ||||||||
Proceeds, net of issue costs | 24 | 215 | ||||||
Decrease in TransCanada's ownership of TC PipeLines, LP | (40) | |||||||
Distributions declared to non-controlling interests | (279) | |||||||
Reclassification from/(to) common units subject to rescission or redemption (Note 19) | (1,179) | |||||||
Acquisition of non-controlling interests in Columbia Pipeline Partners LP | 1,051 | |||||||
Balance at end of year at Dec. 31, 2016 | 25,983 | $ 24,257 | 20,099 | 3,980 | 1,138 | (960) | 1,726 | |
Shares issued: | ||||||||
Under at-the-market equity issuance program, net of issue costs | 216 | |||||||
Under dividend reinvestment and share purchase plan | 790 | |||||||
On exercise of stock options | 62 | |||||||
Issuance of stock options, net of exercises | 6 | |||||||
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 | 341 | |||||||
Net income attributable to controlling interests | 3,157 | 3,157 | ||||||
Common share dividends | (2,184) | |||||||
Preferred share dividends | (159) | |||||||
Reclassification of additional paid-in capital deficit to retained earnings | (341) | |||||||
Other comprehensive income/(loss) attributable to controlling interests (Note 22) | (926) | (771) | ||||||
Net (loss)/income attributable to non-controlling interests | (238) | 238 | ||||||
Other comprehensive income/(loss) attributable to non-controlling interests | (155) | |||||||
Issuance of TC PipeLines, LP units | ||||||||
Proceeds, net of issue costs | 26 | 225 | ||||||
Decrease in TransCanada's ownership of TC PipeLines, LP | (171) | (41) | ||||||
Distributions declared to non-controlling interests | (280) | |||||||
Reclassification from/(to) common units subject to rescission or redemption (Note 19) | 106 | |||||||
Impact of Columbia Pipeline Partners LP acquisition | 33 | |||||||
Balance at end of year at Dec. 31, 2017 | 26,891 | 25,039 | 21,167 | 3,980 | 1,623 | (1,731) | 1,852 | |
Shares issued: | ||||||||
Under at-the-market equity issuance program, net of issue costs | 1,118 | |||||||
Under dividend reinvestment and share purchase plan | 855 | |||||||
On exercise of stock options | 34 | |||||||
Issuance of stock options, net of exercises | 10 | |||||||
Dilution from TC PipeLines, LP units issued | 7 | 49 | ||||||
Columbia Pipeline Partners LP acquisition | (9) | |||||||
Net income attributable to controlling interests | 3,702 | 3,702 | ||||||
Common share dividends | (2,501) | |||||||
Preferred share dividends | (163) | |||||||
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform (Note 3) | 17 | (17) | ||||||
Other comprehensive income/(loss) attributable to controlling interests (Note 22) | 1,314 | 1,142 | ||||||
Net (loss)/income attributable to non-controlling interests | 185 | (185) | ||||||
Other comprehensive income/(loss) attributable to non-controlling interests | 172 | |||||||
Issuance of TC PipeLines, LP units | ||||||||
Proceeds, net of issue costs | 7 | 49 | ||||||
Decrease in TransCanada's ownership of TC PipeLines, LP | (9) | |||||||
Distributions declared to non-controlling interests | (224) | |||||||
Balance at end of year at Dec. 31, 2018 | $ 30,993 | $ 29,338 | $ 23,174 | $ 3,980 | $ 17 | $ 2,773 | $ (606) | $ 1,655 |
DESCRIPTION OF TRANSCANADA'S BU
DESCRIPTION OF TRANSCANADA'S BUSINESS | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
DESCRIPTION OF TRANSCANADA'S BUSINESS | DESCRIPTION OF TRANSCANADA'S BUSINESS TransCanada Corporation (TransCanada or the Company) is a leading North American energy infrastructure company which operates in 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, consisting of corporate and administrative functions that provide governance, financing and other support to the Company's business segments. Canadian Natural Gas Pipelines The Canadian Natural Gas Pipelines segment consists of the Company's investments in 40,686 km ( 25,281 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 50,199 km ( 31,192 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 1,670 km ( 1,038 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 10 power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These include assets in Alberta, Ontario, Québec, New Brunswick and Arizona. At December 31, 2018, the Coolidge generating station is classified as Assets held for sale. Refer to Note 6, Assets held for sale, for further information. |
ACCOUNTING POLICIES
ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2018 | |
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 TransCanada 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. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation. Use of Estimates and Judgments In preparing these consolidated financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but they do not involve significant subjectivity or uncertainty. Others also have a material impact but the assumptions underlying these accounting estimates also relate to matters that are highly uncertain at the time the estimate or judgment is made or are subjective. Significant estimates and judgments used in the preparation of the consolidated financial statements that involve assumptions that are highly uncertain or subjective include, but are not limited to: • fair value of plant, property and equipment and equity investments (Notes 8 and 9) • fair value of goodwill (Note 11) • fair value of intangible assets (Note 12) and • fair value of assets and liabilities acquired in a business combination (Note 26). Significant estimates and judgments used in the preparation of the consolidated financial statements that are provided by an independent expert or do not involve assumptions that are highly uncertain or subjective include, but are not limited to: • depreciation rates of plant, property and equipment (Note 8) • carrying value of regulatory assets and liabilities (Note 10) • 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 23) • fair value of financial instruments (Note 24) and • provisions for commitments, contingencies, guarantees (Note 27) and restructuring costs (Note 28). 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), the Alberta Energy Regulator (AER) or the B.C. Oil and Gas Commission (OGC). 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 TransCanada'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. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An asset qualifies for the use of RRA when it meets three criteria: • a regulator must establish or approve the rates for the regulated services or activities • the regulated rates must be designed to recover the cost of providing the services or products and • it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers because of the demand for services or products and the level of direct or indirect competition. TransCanada'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 the Company's 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. Once in operation, the Coastal GasLink pipeline is not expected to apply RRA. Revenue Recognition Canadian Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Canadian natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. Revenues from the Company's Canadian natural gas pipelines are subject to regulatory decisions by the NEB. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural gas capacity for transportation services, which includes a return of and on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are generally 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 tolls. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved return on equity (ROE) assumptions. Adjustments to revenues are recorded when the NEB decision is received. Canadian natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. U.S. Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. 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. U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Natural Gas Storage and Other Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage including specifications with regards to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores for customers. 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 term of the contract. The Company also owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas and associated liquids are produced. Midstream natural gas service revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas for which it provides midstream services. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Liquids Pipelines Capacity Arrangements and Transportation Revenues from the Company's liquids pipelines are generated mainly from providing customers with firm capacity arrangements to transport crude oil. The performance obligation in these contracts is the reservation of a specified amount of capacity together with the transportation of crude oil on a monthly basis. Revenues earned from these arrangements are recognized ratably over the term of the contract regardless of the amount of crude oil that is transported. Revenues for interruptible or volumetric-based services are recognized when the service is performed. Liquids pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the crude oil that it transports for customers. Energy Power Generation Revenues from the Company's Energy business are primarily derived from long-term contractual commitments to provide power capacity to meet the demands of the market, and from the sale of electricity to both centralized markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are invoiced and received on a monthly basis. Natural Gas Storage and Other Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Revenues are recognized as the services are provided. Term storage revenues are invoiced and received on a monthly basis. Revenues earned from the sale of proprietary natural gas are recognized in the month of delivery. Revenues from ancillary services are recognized as the service is provided. The Company does not take ownership of the natural gas that it stores for customers. Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. Inventories Inventories primarily consist of materials and supplies including spare parts and fuel, crude oil in transit and natural gas inventory in storage. 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. Once an asset is classified as held for sale, depreciation expense is no longer recorded. 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 seven 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 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. Impairment of Long-Lived Assets The Company reviews long-lived assets such as plant, property and equipment, equity investments and capital projects in development 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 that are estimated for an asset within Plant, property and equipment, or the estimated selling price of any long-lived asset 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 and 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 Company will then perform the quantitative goodwill impairment test. The Company can elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Company compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. 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. TransCanada has PPAs for the sale of power that are accounted for as operating leases where TransCanada 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 TransCanada 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 was subleased to third parties under terms and conditions similar to the PPAs, and was 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), TransCanada 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 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. For those AROs that the Company records, the following assumptions are used: • when the asset is expected to be retired • the scope and cost of abandonment and reclamation activities that are required and • appropriate inflation and discount rates. 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 because the Company intends to operate them as long as there is supply and demand. 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, and 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 or cancelled/retired by government agencies. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TransCanada are not attributed a value for accounting purposes. When required, TransCanada accrues emission liabilities on the Consolidated balance sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues. Stock Options and Other Compensation Programs TransCanada's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period with an offset to Additional paid-in capital. Upon exercise of stock options, amounts originally recorded against Additional paid-in capital are reclassified to Common shares on the Consolidated balance sheet. 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 (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 (AOCI) and into net income over the expected 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 h |
ACCOUNTING CHANGES
ACCOUNTING CHANGES | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Changes and Error Corrections [Abstract] | |
ACCOUNTING CHANGES | ACCOUNTING CHANGES Changes in Accounting Policies for 2018 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 from these contracts in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in amounts that reflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as the Company's "performance obligations." The total consideration to which the Company expects to be entitled can include fixed and variable amounts. The Company has variable revenue that is subject to factors outside the Company’s influence, such as market prices, actions of third parties and weather conditions. The Company considers this variable revenue to be "constrained" as it cannot be reliably estimated, and therefore recognizes variable revenue when the service is provided. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and related cash flows. The Company’s accounting policies related to revenue recognition have not substantially changed as a result of adopting the new guidance on revenue from contracts with customers. Results reported for 2018 reflect the application of the new guidance, while the 2017 and 2016 comparative results were prepared and reported under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP." Under legacy U.S. GAAP, revenues were recognized when the risk, rewards, and benefits were transferred to the customer by the Company providing the goods or services under the contract, in an amount the Company expected to collect from the customer. Under the new guidance applied in 2018, revenues are recognized when the Company satisfies its performance obligations by transferring control of the promised goods or services to its customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company has elected to utilize a practical expedient to recognize revenues from its U.S. and certain Mexico natural gas pipelines contracts as customers are invoiced. The new guidance was effective January 1, 2018, was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition. Refer to Note 5, Revenues, for further information related to the impact of adopting 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 changes 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 was effective January 1, 2018 and did not have a material impact on the Company's 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 intra-entity asset transfers when the transfer occurs. The new guidance was effective January 1, 2018, was applied using a modified retrospective approach, and resulted in an adjustment to retained earnings of $95 million . In February 2018, the FASB issued new guidance that allows a reclassification from AOCI to retained earnings for stranded tax effects resulting from U.S. Tax Reform. This guidance can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change is recognized. This new guidance is effective January 1, 2019, however, early adoption is permitted. The Company elected to early adopt this guidance effective fourth quarter 2018 and used a portfolio approach for releasing the income tax effects from AOCI to retained earnings. The Company applied this guidance retrospectively, at the beginning of the period of adoption, resulting in an adjustment to retained earnings of $17 million . 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 period and end of period total amounts on the statement of cash flows. This new guidance was effective January 1, 2018, was applied retrospectively, and did not have an impact on the Company's consolidated financial statements. Employee post-retirement benefits In March 2017, the FASB issued new guidance that requires 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 was effective January 1, 2018 and did not have a material impact on the Company's consolidated financial statements. Hedge accounting In August 2017, the FASB issued new guidance 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 requires additional disclosures including cumulative basis adjustments for fair value hedges and the effect of hedging on individual line items in the statement of income. This new guidance is effective January 1, 2019 with early adoption permitted. This new guidance, which the Company elected to adopt effective January 1, 2018, was applied prospectively and did not have a material impact on the Company's consolidated financial statements. Derecognition of Nonfinancial Assets In February 2017, the FASB issued new guidance that clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset. The FASB also amended the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. This new guidance was effective January 1, 2018, was applied using the modified retrospective transition method and did not have a material impact on the Company's consolidated financial statements. 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 with early adoption permitted. The Company elected to adopt this guidance effective fourth quarter 2018 as it simplified goodwill impairment testing. The guidance was applied prospectively and used in the 2018 annual goodwill impairment test. Future Accounting Changes Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required 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. 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. Lessees will classify leases as finance or operating, with classification affecting the pattern of expense recognition in the statement of income. The new guidance does not make extensive changes to lessor accounting. The Company currently expects that substantially all of its leases where the Company is the lessor will continue to be classified as operating leases under the new standard. In January 2018, the FASB issued an optional practical expedient, to be applied upon transition, to omit the evaluation of land easements not previously accounted for as leases that existed or expired prior to the entity's adoption of the new lease guidance. An entity that elects this practical expedient is required to apply it consistently to all of its existing or expired land easements not previously accounted for as leases. The Company will apply this practical expedient upon transition to the new standard. The new guidance is effective January 1, 2019, with early adoption permitted. The Company will adopt the new standard on its effective date. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application being January 1, 2019. In July 2018, the FASB issued a transition option allowing entities to not apply the new guidance, including disclosure requirements, to the comparative periods they present in their financial statements in the year of adoption. The Company will apply this transition option and use the effective date as the date of initial application. Consequently, financial information will not be updated and disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. The Company will elect the package of practical expedients which permits entities not to reassess prior conclusions about lease identification, lease classification and initial direct costs under the rules of the new standard. The Company believes that the most significant effects of adoption will relate to the recognition of new ROU assets and lease liabilities on the Company's balance sheet for its operating leases and providing significant new disclosures about the Company's leasing activities. The guidance will not impact the Company's income statement. On adoption, the Company will recognize ROU assets of approximately $606 million and additional operating lease liabilities of approximately $600 million based on the present value of the remaining minimum lease payments for existing operating leases. The new standard also provides practical expedients for a Company’s ongoing accounting. The Company will elect the short-term lease recognition exemption for all eligible leases. This means, for those leases that qualify, the Company will not recognize ROU assets or lease liabilities. The Company will also elect the practical expedient to not separate lease and non-lease components for all leases for which the Company is the lessee and for facility and liquids tank terminals for which the Company is the lessor. 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 as 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. Fair value measurement In August 2018, the FASB issued new guidance that amends certain disclosure requirements for fair value measurements. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Defined benefit plans In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to DB pension and other post retirement benefit plans. This new guidance is effective January 1, 2021, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Implementation costs of cloud computing arrangements In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting arrangement over the term of the arrangement. This guidance is effective January 1, 2020, however, early adoption is permitted. This guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Consolidation In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. |
SEGMENTED INFORMATION
SEGMENTED INFORMATION | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
SEGMENTED INFORMATION | SEGMENTED INFORMATION year ended December 31, 2018 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 4,038 4,314 619 2,584 2,124 — 13,679 Intersegment revenues — 162 — — 56 (218 ) 2 — 4,038 4,476 619 2,584 2,180 (218 ) 13,679 Income from equity investments 12 256 22 64 355 5 3 714 Plant operating costs and other (1,405 ) (1,368 ) (34 ) (630 ) (313 ) 159 2 (3,591 ) Commodity purchases resold — — — — (1,488 ) — (1,488 ) Property taxes (266 ) (199 ) — (98 ) (6 ) — (569 ) Depreciation and amortization (1,129 ) (664 ) (97 ) (341 ) (119 ) — (2,350 ) Goodwill and other asset impairment charges — (801 ) — — — — (801 ) Gain on sale of assets — — — — 170 — 170 Segmented earnings/(losses) 1,250 1,700 510 1,579 779 (54 ) 5,764 Interest expense (2,265 ) Allowance for funds used during construction 526 Interest income and other 3 (76 ) Income before income taxes 3,949 Income tax expense (432 ) Net income 3,517 Net loss attributable to non-controlling interests 185 Net income attributable to controlling interests 3,702 Preferred share dividends (163 ) Net income attributable to common shares 3,539 Capital spending Capital expenditures 2,442 5,591 463 110 767 45 9,418 Capital projects in development 36 1 — 459 — — 496 Contributions to equity investments — 179 334 12 490 — 1,015 2,478 5,771 797 581 1,257 45 10,929 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. Refer to Note 9, Equity investments, for further 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 ) 2 — 3,693 3,635 570 2,009 3,593 (51 ) 13,449 Income/(loss) from equity investments 11 240 (9 ) (3 ) 471 63 3 773 Plant operating costs and other (1,300 ) (1,340 ) (42 ) (623 ) (550 ) (51 ) 2 (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 sale of assets — — — — 631 — 631 Segmented earnings/(losses) 1,236 1,760 426 (251 ) 1,552 (39 ) 4,684 Interest expense (2,069 ) Allowance for funds used during construction 507 Interest income and other 3 184 Income before income taxes 3,306 Income tax recovery 89 Net income 3,395 Net income attributable to non-controlling interests (238 ) Net income attributable to controlling interests 3,157 Preferred share dividends (160 ) Net income attributable to common shares 2,997 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 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income/(loss) from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term 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 ) 2 — 3,682 2,582 378 1,755 4,206 (56 ) 12,547 Income/(loss) from equity investments 12 214 (3 ) (1 ) 292 — 514 Plant operating costs and other (1,245 ) (1,057 ) (43 ) (568 ) (884 ) (64 ) 2 (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 (1,998 ) Allowance for funds used during construction 419 Interest income and other 103 Income before income taxes 837 Income tax expense (352 ) Net income 485 Net income attributable to non-controlling interests (252 ) Net income attributable to controlling interests 233 Preferred share dividends (109 ) Net income attributable to common shares 124 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 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. at December 31 2018 2017 (millions of Canadian $) Total Assets by segment Canadian Natural Gas Pipelines 18,407 16,904 U.S. Natural Gas Pipelines 44,115 35,898 Mexico Natural Gas Pipelines 7,058 5,716 Liquids Pipelines 17,352 15,438 Energy 8,475 8,503 Corporate 3,513 3,642 98,920 86,101 Geographic Information year ended December 31 2018 2017 2016 (millions of Canadian $) Revenues Canada – domestic 4,187 3,618 3,697 Canada – export 1,075 1,255 1,177 United States 7,798 8,006 7,295 Mexico 619 570 378 13,679 13,449 12,547 at December 31 2018 2017 (millions of Canadian $) Plant, Property and Equipment Canada 23,226 21,632 United States 37,385 30,693 Mexico 5,892 4,952 66,503 57,277 |
REVENUES
REVENUES | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer [Text Block] | REVENUES On January 1, 2018, the Company adopted new FASB guidance on revenue from contracts with customers using the modified retrospective transition method for all contracts that were in effect on the date of adoption. Results reported for 2018 reflect the application of the new guidance, while the 2017 and 2016 comparative results were prepared and reported under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP." Disaggregation of Revenues The following tables summarizes total Revenues for the year ended December 31, 2018 . (millions of Canadian $) Canadian U.S. Mexico Liquids Pipelines Energy Total Revenues from contracts with customers Capacity arrangements and transportation 4,038 3,549 614 2,079 — 10,280 Power generation — — — — 1,771 1,771 Natural gas storage and other — 654 5 3 81 743 4,038 4,203 619 2,082 1,852 12,794 Other revenues 1,2 — 111 — 502 272 885 4,038 4,314 619 2,584 2,124 13,679 1 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 24, Risk management and financial instruments, for further information on income from financial instruments. 2 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 16, Income taxes, for further information. Revenues from contracts with customers are recognized net of any taxes collected from customers which are subsequently remitted to governmental authorities. The Company's contracts with customers include natural gas and liquids pipelines capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other contracts. Financial Statement Impact of Adopting Revenue from Contracts with Customers The Company adopted the new guidance using the modified retrospective transition method. As a practical expedient under this transition method, the Company is not required to analyze completed contracts at the date of adoption. As a result of adopting the new guidance, the Company made the adjustments described below on January 1, 2018. Capacity Arrangements and Transportation For certain natural gas pipeline capacity contracts, amounts are invoiced to the customer in accordance with the terms of the contract, however, the related revenues are recognized when the Company satisfies its performance obligation to provide committed capacity ratably over the term of the contract. This difference in timing between revenue recognition and amounts invoiced creates a contract asset or contract liability under the new revenue recognition guidance. Under legacy U.S. GAAP, these differences were recorded as Accounts receivable. Under the new guidance, contract assets are included in Other current assets and Intangibles and other assets and contract liabilities are included in Accounts payable and other and Other long-term liabilities. Impact of New Revenue Recognition Guidance on Date of Adoption The following table illustrates the impact of the adoption of the new revenue recognition guidance on the Company's previously reported consolidated balance sheet line items: As reported Adjustment (millions of Canadian $) December 31, 2017 January 1, 2018 Current Assets Accounts receivable 2,522 (62 ) 2,460 Other 1 691 79 770 Current Liabilities Accounts payable and other 2 4,057 17 4,074 1 Adjustment relates to contract assets previously included in Accounts receivable. 2 Adjustment relates to contract liabilities previously included in Accounts receivable. Pro-forma Financial Statements under Legacy U.S. GAAP As required by the new revenue recognition guidance, the following tables illustrate the pro-forma impact on the affected line items on the Consolidated balance sheet, as at December 31, 2018 , using legacy U.S. GAAP: December 31, 2018 As reported Pro-forma using legacy U.S. GAAP (millions of Canadian $) Current Assets Accounts receivable 2,535 2,694 Other 1,180 1,021 Contract Balances (millions of Canadian $) December 31, 2018 January 1, 2018 Receivables from contracts with customers 1,684 1,736 Contract assets 1 159 79 Long-term contract assets 2 21 — Contract liabilities 3 11 17 Long-term contract liabilities 4 121 — 1 Recorded as part of Other current assets on the Consolidated balance sheet. 2 Recorded as part of Intangibles and other assets on the Consolidated balance sheet. 3 Comprised of deferred revenue recorded in Accounts payable and other on the Consolidated balance sheet. During the year ended December 31, 2018 , $17 million of revenue was recognized that was included in the contract liability at the beginning of the year. 4 Comprised of deferred revenue recorded in Other long-term liabilities on the Consolidated balance sheet. Contract assets and long-term contract assets primarily relate to the Company’s right to revenues for services completed but not invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in contract assets is primarily related to the transfer to Accounts receivable when these rights become unconditional and the customer is invoiced, as well as the recognition of additional revenues that remain to be invoiced. Contract liabilities and long-term contract liabilities primarily relate to force majeure fixed capacity payments received on long-term capacity arrangements in Mexico. Future Revenues from Remaining Performance Obligations As required by the new revenue recognition guidance, the following provides disclosure on future revenues allocated to remaining performance obligations representing contracted revenues that have not yet been recognized. Certain contracts that qualify for the use of one of the following practical expedients are excluded from the future revenues disclosures: 1. The original expected duration of the contract is one year or less. 2. The Company recognizes revenue from the contract that is equal to the amount invoiced, where the amount invoiced represents the value to the customer of the service performed to date. This is referred to as the "right to invoice" practical expedient. 3. The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time. The following provides a discussion of the transaction price allocated to future performance obligations as well as practical expedients used by the Company. Capacity Arrangements and Transportation As at December 31, 2018 , future revenues from long-term pipeline capacity arrangements and transportation contracts extending through 2043 are approximately $30.1 billion , of which approximately $6.0 billion is expected to be recognized in 2019. Future revenues from long-term capacity arrangements and transportation contracts do not include constrained variable revenues or arrangements to which the right to invoice practical expedient has been applied. As a result, these amounts are not representative of potential total future revenues expected from these contracts. Future revenues from the Company's Canadian natural gas pipelines' regulated firm capacity contracts include fixed revenues for the time periods that tolls under current rate settlements are in effect, which is approximately one to three years. Many of these contracts are long-term in nature and revenues from the remaining performance obligations that extend beyond the current rate settlement term are considered to be fully constrained since future tolls remain unknown. Revenues from these contracts will be recognized once the performance obligation to provide capacity has been satisfied and the regulator has approved the applicable tolls. In addition, the Company considers interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. These variable revenues are recognized on a monthly basis when the Company satisfies the performance obligation and have been excluded from the future revenues disclosure as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts are allocated entirely to unsatisfied performance obligations at December 31, 2018 . The Company also applies the right to invoice practical expedient to all of its U.S. and certain of its Mexico regulated natural gas pipeline capacity arrangements and flow-through revenues. Revenues from regulated capacity arrangements are recognized based on current rates and flow-through revenues are earned from the recovery of operating expenses. These revenues are recognized on a monthly basis as the Company performs the services and are excluded from future revenues disclosures. Revenues from liquids pipelines capacity arrangements have a variable component based on volumes transported. As a result, these variable revenues are excluded from the future revenues disclosures as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts are allocated entirely to unsatisfied performance obligations at December 31, 2018 . Power Generation The Company has long-term power generation contracts extending through 2030. Revenues from power generation have a variable component related to market prices that are subject to factors outside the Company’s influence. These revenues are considered to be fully constrained and are recognized on a monthly basis when the Company satisfies the performance obligation. The Company applies the practical expedient related to variable revenues to these contracts. As a result, future revenues from these contracts are excluded from the disclosures. Natural Gas Storage and Other As at December 31, 2018 , future revenues from long-term natural gas storage and other contracts extending through 2033 are approximately $1.2 billion , of which approximately $283 million is expected to be recognized in 2019. The Company applies the practical expedients related to contracts that are for a duration of one year or less and where it recognizes variable consideration, and therefore excludes the related revenues from the future revenues disclosure. As a result, this amount is lower than the potential total future revenues from these contracts. |
ASSETS HELD FOR SALE
ASSETS HELD FOR SALE | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
ASSETS HELD FOR SALE | ASSETS HELD FOR SALE Coolidge Generating Station On December 14, 2018, TransCanada entered into an agreement to sell its Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC for approximately US$ 465 million , subject to timing of the close and related adjustments. In January 2019, pursuant to the terms of the Coolidge PPA, Salt River Project Agriculture Improvement and Power District, the counterparty to this arrangement, exercised their right of first refusal on this sale. The sale will result in an estimated gain of approximately $ 65 million ($ 50 million after tax) including the impact of an estimated $ 10 million of foreign currency translation gains. This gain will be recognized upon closing of the sale transaction, which is expected to occur mid-2019. At December 31, 2018, the related assets and liabilities were classified as held for sale in the Energy segment as follows: (millions of Canadian $) Assets held for sale Accounts receivable 6 Plant, property and equipment 537 Total assets held for sale 543 Liabilities related to assets held for sale Other long-term liabilities (3 ) Total liabilities related to assets held for sale 1 (3 ) 1 Included in Accounts payable and other on the Consolidated balance sheet. |
OTHER CURRENT ASSETS
OTHER CURRENT ASSETS | 12 Months Ended |
Dec. 31, 2018 | |
Other Assets [Abstract] | |
OTHER CURRENT ASSETS | OTHER CURRENT ASSETS at December 31 2018 2017 (millions of Canadian $) Fair value of derivative contracts (Note 24) 737 332 Contract assets (Note 5) 159 — Regulatory assets (Note 10) 83 23 Cash provided as collateral 55 99 Prepaid expenses 41 109 Other 105 128 1,180 691 |
PLANT, PROPERTY AND EQUIPMENT
PLANT, PROPERTY AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
PLANT, PROPERTY AND EQUIPMENT | PLANT, PROPERTY AND EQUIPMENT 2018 2017 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 10,764 4,500 6,264 10,153 4,190 5,963 Compression 3,289 1,677 1,612 3,021 1,593 1,428 Metering and other 1,247 613 634 1,188 569 619 15,300 6,790 8,510 14,362 6,352 8,010 Under construction 2,111 — 2,111 940 — 940 17,411 6,790 10,621 15,302 6,352 8,950 Canadian Mainline Pipeline 10,077 6,777 3,300 9,763 6,455 3,308 Compression 3,642 2,656 986 3,605 2,499 1,106 Metering and other 652 241 411 655 207 448 14,371 9,674 4,697 14,023 9,161 4,862 Under construction 149 — 149 156 — 156 14,520 9,674 4,846 14,179 9,161 5,018 Other Canadian Natural Gas Pipelines 1 Other 1,842 1,420 422 1,815 1,363 452 Under construction 124 — 124 4 — 4 1,966 1,420 546 1,819 1,363 456 33,897 17,884 16,013 31,300 16,876 14,424 U.S. Natural Gas Pipelines Columbia Gas Pipeline 6,711 251 6,460 3,550 125 3,425 Compression 2,932 132 2,800 1,547 64 1,483 Metering and other 2,884 75 2,809 2,306 37 2,269 12,527 458 12,069 7,403 226 7,177 Under construction 4,347 — 4,347 3,332 — 3,332 16,874 458 16,416 10,735 226 10,509 ANR Pipeline 1,600 443 1,157 1,427 365 1,062 Compression 1,978 388 1,590 1,582 286 1,296 Metering and other 1,217 324 893 961 268 693 4,795 1,155 3,640 3,970 919 3,051 Under construction 272 — 272 358 — 358 5,067 1,155 3,912 4,328 919 3,409 2018 2017 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,322 951 1,371 2,107 822 1,285 Great Lakes 2,180 1,251 929 1,988 1,113 875 Columbia Gulf 1,753 74 1,679 1,115 37 1,078 Midstream 1,212 91 1,121 1,085 54 1,031 Other 2 1,190 474 716 1,950 574 1,376 8,657 2,841 5,816 8,245 2,600 5,645 Under construction 846 — 846 699 — 699 9,503 2,841 6,662 8,944 2,600 6,344 31,444 4,454 26,990 24,007 3,745 20,262 Mexico Natural Gas Pipelines Pipeline 3,172 301 2,871 2,872 214 2,658 Compression 506 41 465 448 30 418 Metering and other 640 91 549 573 65 508 4,318 433 3,885 3,893 309 3,584 Under construction 1,990 — 1,990 1,368 — 1,368 6,308 433 5,875 5,261 309 4,952 Liquids Pipelines Keystone Pipeline System Pipeline 9,780 1,271 8,509 9,002 992 8,010 Pumping equipment 1,065 184 881 1,022 152 870 Tanks and other 3 3,598 488 3,110 3,314 385 2,929 14,443 1,943 12,500 13,338 1,529 11,809 Under construction 4 18 — 18 456 — 456 14,461 1,943 12,518 13,794 1,529 12,265 Intra-Alberta Pipelines 5 Pipeline 762 22 740 748 3 745 Pumping equipment 104 3 101 104 — 104 Tanks and other 291 8 283 259 1 258 1,157 33 1,124 1,111 4 1,107 Under construction 84 — 84 47 — 47 1,241 33 1,208 1,158 4 1,154 15,702 1,976 13,726 14,952 1,533 13,419 Energy Natural Gas 6 2,062 708 1,354 2,645 743 1,902 Wind 7 — — — 673 204 469 Natural Gas Storage and Other 741 169 572 734 156 578 2,803 877 1,926 4,052 1,103 2,949 Under construction 1,735 — 1,735 1,028 — 1,028 4,538 877 3,661 5,080 1,103 3,977 Corporate 448 210 238 411 168 243 92,337 25,834 66,503 81,011 23,734 57,277 1 Includes Foothills, Ventures LP, Great Lakes Canada and Coastal GasLink . 2 Includes Portland, North Baja, Tuscarora and Crossroads as well as Bison for 2017. Bison's remaining carrying value was fully impaired at December 31, 2018. 3 Includes tanks that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $ 194 million and $ 23 million , respectively, at December 31, 2018 (2017 – $ 184 million and $ 19 million , respectively), while revenues of $ 15 million were recognized in 2018 (2017 – $ 16 million ; 2016 – $ 16 million ). 4 Certain costs related to the Keystone XL project were recorded in Plant, property and equipment at December 31, 2017. In 2018, these costs were reclassified to Capital projects in development as the Company recommenced capitalizing Keystone XL development costs. 5 Includes Northern Courier and White Spruce. Northern Courier is accounted for as an operating lease and was placed in service on November 1, 2017. The cost and accumulated depreciation of this facility were $ 1,130 million and $ 32 million , respectively, at December 31, 2018 (2017 – $ 1,111 million and $ 4 million , respectively), while revenues of $ 142 million were recognized in 2018 (2017 – $ 20 million ). 6 Includes Coolidge, Grandview, Bécancour, Halton Hills and the Alberta cogeneration natural gas-fired facilities. Coolidge, Grandview and Bécancour have long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $ 655 million and $ 268 million , respectively, at December 31, 2018 ( 2017 – $ 1,264 million and $ 354 million , respectively). At December 31, 2018, the cost and accumulated depreciation of Coolidge were reclassified to Assets held for sale. Refer to Note 6, Assets held for sale, for further information. Revenues of $ 216 million were recognized in 2018 ( 2017 – $ 215 million ; 2016 – $ 212 million ) through the sale of electricity under the related PPAs for these assets. 7 The Company closed the sale of its Cartier Wind power assets on October 24, 2018. Refer to Note 26, Acquisitions and dispositions, for further information. Bison Impairment At December 31, 2018, the Company evaluated its investment in its Bison natural gas pipeline for impairment in connection with the termination of certain customer transportation agreements. The termination of these agreements released the Company from providing any future services. With the loss of these future cash flows and the persistence of unfavourable market conditions which have inhibited system flows on the pipeline, the Company determined that the asset’s remaining carrying value was no longer recoverable and recognized a non-cash impairment charge of $722 million pre-tax in its U.S. Natural Gas Pipelines segment. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. As Bison is a TC PipeLines, LP asset, in which the Company has a 25.5 per cent interest, the Company's share of the impairment charge, after tax and net of non-controlling interests, was $140 million . The termination of the transportation agreements resulted in the receipt of $130 million in termination payments which were recorded in Revenues in 2018. The Company's share of this amount, after tax and net of non-controlling interests, was $25 million . 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 At December 31, 2017, 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 of certain equipment after determining that it was no longer recoverable. This turbine equipment was previously purchased for a power development project that did not proceed. 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, 2018 | |
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 2018 2017 2016 2018 2017 Canadian Natural Gas Pipelines TQM 50.0 % 12 11 12 71 68 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 87 87 92 677 641 Iroquois 2 50.0 % 60 59 54 291 280 Millennium 3 47.5 % 75 66 33 511 291 Pennant Midstream 3 47.0 % 17 11 6 256 228 Other Various 17 17 29 113 92 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % 27 66 (3 ) 627 399 TransGas nil — (12 ) — — — Liquids Pipelines Grand Rapids 5 50.0 % 65 17 (1 ) 1,028 996 Other 6 Various (1 ) (20 ) — 21 20 Energy Bruce Power 7 48.3 % 311 434 293 3,166 2,987 Portlands Energy 8 50.0 % 36 31 33 289 301 ASTC Power Partnership 50.0 % — — (37 ) — — Other Various 8 6 3 63 63 714 773 514 7,113 6,366 1 At December 31, 2018 , 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 ( 2017 – US$115 million ) due to the fair value assessment of assets at the time of acquisition. 2 At December 31, 2018 , the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million ( 2017 – US$41 million ) due mainly to the fair value assessment of the assets at the time of acquisition. 3 Acquired as part of Columbia Pipeline Group, Inc. (Columbia) on July 1, 2016. Income from Equity investments reflects equity earnings from the date of acquisition. 4 TransCanada 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 foreign exchange gains and losses recorded in the Corporate segment which are fully offset in Interest income and other in the Consolidated statement of income. 5 Grand Rapids was placed in service in August 2017. At December 31, 2018 , the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $102 million ( 2017 – $105 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, 2018 and 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil . 7 At December 31, 2018 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $870 million ( 2017 – $902 million ) due to the fair value assessment of assets at the time of acquisitions. 8 At December 31, 2018 , the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million ( 2017 – $73 million ) due mainly to interest capitalized during construction. TransGas de Occidente S.A. Impairment In August 2017, TransCanada 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 non-cash impairment charge represented the write-down of the remaining carrying value of the equity investment which 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 Income from equity investments in its Liquids Pipelines segment 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, TransCanada 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, 2018 were $ 1,106 million ( 2017 – $ 1,332 million ; 2016 – $ 1,571 million ) of which $ 121 million ( 2017 – $ 362 million ; 2016 – $ 727 million ) was included in Investing activities in the Consolidated statement of cash flows with respect to distributions received from Bruce Power from its financing program. Contributions made to equity investments for the year ended December 31, 2018 were $ 1,015 million ( 2017 – $ 1,681 million ; 2016 – $ 765 million ) and are included in Investing activities in the Consolidated statement of cash flows. For 2018 , contributions include $ 179 million ( 2017 – $977 million ) related to TransCanada's proportionate share of the Sur de Texas debt financing requirements. Summarized Financial Information of Equity Investments year ended December 31 2018 2017 2016 (millions of Canadian $) Income Revenues 4,836 4,913 4,336 Operating and other expenses (3,545 ) (2,993 ) (3,068 ) Net income 1,515 1,636 1,080 Net income attributable to TransCanada 714 773 514 at December 31 2018 2017 (millions of Canadian $) Balance Sheet Current assets 2,209 2,176 Non-current assets 20,647 17,869 Current liabilities (2,049 ) (1,577 ) Non-current liabilities (9,042 ) (8,217 ) Loan receivable from affiliate TransCanada holds a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. In 2017, TransCanada entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. At December 31, 2018 , the Company’s consolidated balance sheet included a MXN $18.9 billion or $1.3 billion ( 2017 – MXN$ 14.4 billion or $0.9 billion ) loan receivable from the Sur de Texas joint venture which represents TransCanada’s proportionate share of long-term debt financing requirements related to the joint venture. Interest income and other included interest income of $120 million in 2018 ( 2017 – $34 million ) 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, 2018 | |
Regulated Operations [Abstract] | |
RATE-REGULATED BUSINESSES | RATE-REGULATED BUSINESSES TransCanada'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 TransCanada'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. TransCanada's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return on capital as approved by the NEB. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent 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 NGTL's 2018 results reflect the terms of the 2018-2019 Revenue Requirement Settlement (the 2018-2019 Settlement) approved by the NEB in June 2018. This two -year settlement includes an ROE of 10.1 per cent on 40 per cent deemed common equity, a composite depreciation rate of approximately 3.5 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. 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 TransCanada contribution to reduce the revenue requirement. Toll stabilization is achieved through the 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 2015-2020 six -year fixed toll term of the NEB 2014 Decision. The NEB 2014 Decision also directed TransCanada to file an application to review tolls for the 2018-2020 period. In December 2018, an NEB decision was received on the 2018-2020 Tolls Review (NEB 2018 Decision) which included an accelerated amortization of the December 31, 2017 LTAA balance and an increase to the composite depreciation rate from 3.2 per cent to 3.9 per cent . U.S. Regulated Operations TransCanada'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. In 2018, FERC prescribed changes (2018 FERC Actions) related to U.S. Tax Reform and income taxes for rate-making purposes in a master limited partnership (MLP) that impact future earnings and cash flows of FERC-regulated pipelines. The 2018 FERC Actions also established a process and schedule by which all FERC-regulated interstate pipelines and natural gas storage facilities had to either (i) file a new uncontested rate settlement or (ii) file a FERC Form 501-G that quantifies the isolated impact of U.S. Tax Reform on FERC-regulated pipelines and natural gas storage assets as well as the impact of the 2018 FERC Actions on pipelines held by MLPs. The impact of the 2018 FERC Actions on the Company's more significant U.S. regulated natural gas pipelines is included 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. In response to the 2018 FERC Actions, Columbia Gas filed a Form 501-G including a statement explaining its rationale why the pipeline’s rates are not required to change. ANR Pipeline ANR Pipeline operates under rates established under a FERC-approved rate settlement in 2016. Under terms of the 2016 settlement, neither ANR Pipeline nor the settling parties could file for new rates to become effective earlier than August 1, 2019. However, ANR Pipeline is required to file for new rates to be effective no later than August 1, 2022. In December 2018, ANR Pipeline filed a Form 501-G including a statement explaining its rationale why the pipeline’s rates are not required to change. Columbia Gulf Columbia Gulf’s natural gas transportation services are provided under a tariff at rates subject to FERC approval. In September 2016, 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 required 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. In response to the 2018 FERC Actions, Columbia Gulf filed a Form 501-G including a statement explaining its rationale why the pipeline’s rates are not required to change. TC PipeLines, LP TransCanada owns a 25.5 per cent interest in TC PipeLines, LP, which has ownership interests in eight wholly-owned or partially-owned natural gas pipelines serving major markets in the U.S. As TC PipeLines, LP is an MLP, all pipelines it owns wholly or in part were potentially impacted by the 2018 FERC Actions which creates a presumption that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in their regulated cost-of-service rates. Additionally, to the extent an entity’s income tax allowance is eliminated from rates, it must also eliminate its existing accumulated deferred income tax (ADIT) balance from its rate base. Refer to Note 16, Income Taxes for further information regarding the impact of these changes to TransCanada. Great Lakes Great Lakes reached a rate settlement with its customers, which was approved by FERC on February 22, 2018, decreasing Great Lakes' maximum transportation rates by 27 per cent effective October 1, 2017. This settlement does not contain a 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. As a result of the 2018 FERC Actions, Great Lakes made a limited Section 4 filing which had the effect of reducing rates by 2 per cent from what was in place prior to the FERC changes in 2018. The reduction in rates became effective on February 1, 2019 after the limited Section 4 filing was accepted by FERC on January 31, 2019. Mexico Regulated Operations TransCanada's Mexico natural gas pipelines are regulated by the CRE and operate in accordance with CRE-approved tariffs. The rates in effect on TransCanada's Mexico natural gas pipelines were established based on CRE-approved contracts that provide for the recovery of costs of providing services and a return on and of invested capital. Regulatory Assets and Liabilities at December 31 2018 2017 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 1,051 940 n/a Operating and debt-service regulatory assets 2 12 — 1 Pensions and other post-retirement benefits 1,3 379 388 n/a Foreign exchange on long-term debt 1,4 46 — 1-11 Other 143 71 n/a 1,631 1,399 Less: Current portion included in Other current assets (Note 7) 83 23 1,548 1,376 Regulatory Liabilities Operating and debt-service regulatory liabilities 2 96 188 1 Pensions and other post-retirement benefits 3 53 164 n/a ANR related post-employment and retirement benefits other than pension 5 54 66 n/a Long term adjustment account 6 1,015 1,142 2-45 Bridging amortization account 6 305 202 12 Pipeline abandonment trust balance 1,113 825 n/a Cost of removal 7 261 216 n/a Deferred income taxes 165 75 n/a Deferred income taxes – U.S. Tax Reform 8 1,394 1,659 n/a Other 65 47 n/a 4,521 4,584 Less: Current portion included in Accounts payable and other (Note 14) 591 263 3,930 4,321 1 These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period. 2 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulator for inclusion in determining tolls for the following calendar year. 3 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates. 4 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. 5 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, $11 million ( US$8 million ) of the regulatory liability balance at December 31, 2018 ( 2017 – $26 million ; US$21 million ) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $43 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. 6 These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. The 2018 LTAA balance of $ 1,015 million consists of $ 932 million to be amortized over two years with the remaining balance to be amortized over 45 years . 7 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 operations for future costs to be incurred. 8 These balances represent the impact of U.S. Tax Reform. The regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax liabilities that gave rise to the regulatory liabilities. See Note 16, Income taxes, for further information on U.S. Tax Reform. |
GOODWILL
GOODWILL | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL | GOODWILL The Company has recorded the following Goodwill on its acquisitions: (millions of Canadian $) U.S. Natural Gas Pipelines Balance at January 1, 2017 13,958 Columbia adjustment (Note 26) 71 Foreign exchange rate changes (945 ) Balance at December 31, 2017 13,084 Tuscarora impairment charge (79 ) Foreign exchange rate changes 1,173 Balance at December 31, 2018 14,178 Tuscarora In the fourth quarter of 2018, the Company finalized its regulatory filing for Tuscarora in response to the 2018 FERC Actions and Form 501-G requirements. In January 2019, Tuscarora reached a settlement-in-principle with its customers which was filed with FERC. As a result of these developments, as well as changes to other valuation assumptions responsive to Tuscarora’s commercial environment, it was determined that the fair value of Tuscarora did not exceed its carrying value, including goodwill. The fair value of the reporting unit was determined using a discounted cash flow analysis. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. As a result, the Company recorded a goodwill impairment charge of $79 million pre-tax within the U.S. Natural Gas Pipelines segment. This non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. As Tuscarora is a TC PipeLines, LP asset, the Company's share of this amount, after tax and net of non-controlling interests, was $15 million . The goodwill balance related to Tuscarora at December 31, 2018 was US$23 million (2017 – US$82 million ). Great Lakes At December 31, 2018, 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 in its most recent valuation. Assumptions used in the analysis regarding Great Lakes’ ability to realize long-term value in the North American energy market included the impact of its 501-G election, revenue opportunities on the system as well as changes to other valuation assumptions responsive to Great Lakes’ commercial environment. 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 balance relating to Great Lakes. The goodwill balance related to Great Lakes at December 31, 2018 was US$573 million (2017 – US$573 million ). Ravenswood 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 analysis 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, 2018 | |
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |
INTANGIBLE AND OTHER ASSETS | INTANGIBLE AND OTHER ASSETS at December 31 2018 2017 (millions of Canadian $) Capital projects in development 1,051 596 Deferred income tax assets (Note 16) 322 316 Employee post-retirement benefits (Note 23) 192 193 Fair value of derivative contracts (Note 24) 61 73 Other 295 306 1,921 1,484 Capital projects in development Keystone XL In January 2018, the Company recommenced capitalizing development costs related to Keystone XL. In addition, certain project costs that were recorded in Plant, property and equipment at December 31, 2017 were transferred to Capital projects in development in 2018. These costs were related to the net realizable value of Keystone XL assets after an impairment charge was recorded in 2015. As a result, at December 31, 2018, Capital projects in development for this project were $0.8 billion (2017 – nil ). Reimbursement of Coastal GasLink pipeline costs In accordance with provisions in the agreements with the LNG Canada joint venture participants, all five parties elected to reimburse TransCanada for their share of costs incurred prior to receiving the Final Investment Decision (FID) on the Coastal GasLink pipeline project. In November 2018, the Company received payments totaling $470 million which were recorded as a reduction of the carrying value of Coastal GasLink. 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 TransCanada 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, were 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 Impairment In March 2016 , TransCanada terminated 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. 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. In December 2016, TransCanada 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. |
NOTES PAYABLE
NOTES PAYABLE | 12 Months Ended |
Dec. 31, 2018 | |
Short-term Debt [Abstract] | |
NOTES PAYABLE | NOTES PAYABLE 2018 2017 (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 Canada 2,117 2.5 % 884 1.6 % U.S. (2018 – US$448; 2017 – US$688) 611 3.1 % 862 2.2 % Mexico (2018 – US$25; 2017 – MXN$275) 34 3.3 % 17 8.0 % 2,762 1,763 At December 31, 2018 , Notes payable consists of short-term borrowings in Canada by TransCanada PipeLines Limited (TCPL), in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA) and TransCanada American Investments Ltd. (TAIL), and in Mexico by a Mexican subsidiary. At December 31, 2018 , total committed revolving and demand credit facilities were $ 12.9 billion ( 2017 – $11.0 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) 2018 2017 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 2023 3.0 3.0 3.0 TCPL/TCPL USA/Columbia/TAIL Supports TCPL, TCPL USA and TAIL's U.S. dollar commercial paper programs and is used for general corporate purposes of the borrowers, guaranteed by TCPL December 2019 US 4.5 US 4.5 — TCPL/TCPL USA/Columbia/TAIL Used for general corporate purposes of the borrowers, guaranteed by TCPL December 2021 US 1.0 US 1.0 — TCPL Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes — — US 2.0 TCPL USA Used for TCPL USA general corporate purposes, guaranteed by TCPL — — US 1.0 Columbia Used for Columbia general corporate purposes, guaranteed by TCPL — — US 1.0 TAIL Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL — — 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 2.1 1.0 1.9 Mexico subsidiary Used for Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 MXN 4.5 MXN 5.0 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, 2018, the Company was in compliance with all debt covenants. For the year ended December 31, 2018, the cost to maintain the above facilities was $ 12 million (2017 – $ 7 million ; 2016 – $ 10 million ). At December 31, 2018, the Company's operated affiliates had an additional $ 0.8 billion (2017 – $ 0.4 billion ) of undrawn capacity on committed credit facilities. |
ACCOUNTS PAYABLE AND OTHER
ACCOUNTS PAYABLE AND OTHER | 12 Months Ended |
Dec. 31, 2018 | |
Payables and Accruals [Abstract] | |
ACCOUNTS PAYABLE AND OTHER | ACCOUNTS PAYABLE AND OTHER at December 31 2018 2017 (millions of Canadian $) Trade payables 3,224 2,847 Fair value of derivative contracts (Note 24) 922 387 Unredeemed shares of Columbia 357 312 Regulatory liabilities (Note 10) 591 263 Other 314 248 5,408 4,057 |
OTHER LONG-TERM LIABILITIES
OTHER LONG-TERM LIABILITIES | 12 Months Ended |
Dec. 31, 2018 | |
Deferred Costs, Noncurrent [Abstract] | |
OTHER LONG-TERM LIABILITIES | OTHER LONG-TERM LIABILITIES at December 31 2018 2017 (millions of Canadian $) Employee post-retirement benefits (Note 23) 569 389 Asset retirement obligations 90 98 Fair value of derivative contracts (Note 24) 42 72 Guarantees (Note 27) 12 16 Other 295 152 1,008 727 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2018 | |
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, among other things, 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 a deferred income tax recovery of $816 million in 2017. 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 of $1,686 million on the Consolidated balance sheet at December 31, 2017. Net deferred income tax liabilities related to the cumulative remeasurements of employee post-retirement benefits included in AOCI were also adjusted with a corresponding increase in deferred income tax expense of $12 million in 2017. Given the significance of the legislation, the U.S. Securities and Exchange Commission (SEC) staff issued guidance which allowed registrants to record provisional amounts at December 31, 2017 which may be adjusted as information becomes available, prepared or analyzed during a measurement period not to exceed one year. The SEC guidance summarized 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 considered amounts recorded related to U.S. Tax Reform to be reasonable estimates, however, certain amounts were provisional as the Company’s interpretation, assessment and presentation of the impact of the tax law change were further clarified with additional guidance from regulatory, tax and accounting authorities received in 2018. With additional guidance provided during the one-year measurement period and u pon finalizing its 2017 annual tax return for its U.S. businesses, in fourth quarter 2018 the Company recognized further adjustments to its deferred income tax liability and net regulatory liability balances as well as a deferred income tax recovery of $52 million in fourth quarter 2018. In addition, the 2018 FERC Actions established that, to the extent an entity’s income tax allowance should be eliminated from rates, it must also eliminate its existing ADIT balance from its rate base. In accordance with the FERC Form 501-G and uncontested rate settlement filings, the ADIT balances for all pipelines held wholly or in part by TC PipeLines, LP were eliminated from their respective rate bases. As a result, net regulatory liabilities recorded for these assets pursuant to U.S. Tax Reform were written off, resulting in a further deferred income tax recovery of $115 million in fourth quarter 2018. Commencing January 1, 2018, the Company amortized the net regulatory liabilities, recorded per U.S. Tax Reform, using the Reverse South Georgia methodology. Under this methodology, rate-regulated entities determine and immediately begin recording amortization based on their composite depreciation rates. In 2018, amortization of these net regulatory liabilities in the amount of $58 million was recorded and included in Revenues in the Consolidated statement of income. The net regulatory liability related to U.S. Tax Reform at December 31, 2018 was $1,394 million (2017 – $1,686 million ). Further to U.S. Tax Reform, the U.S. Treasury and the U.S. Internal Revenue Service issued proposed regulations in November and December of 2018 which provided administrative guidance and clarified certain aspects of the new laws with respect to interest deductibility, base erosion and anti-abuse tax, the new dividend received deduction and anti-hybrid rules. Based on the Company's review and analysis of these proposed regulations, no material adjustments were recorded in the 2018 Consolidated financial statements. The proposed regulations are complex and comprehensive, and considerable uncertainty continues to exist until the final regulations are released, which is expected to occur later in 2019. TransCanada continues to review and analyze these proposed regulations as well as assess their potential impact on the Company. Provision for Income Taxes year ended December 31 2018 2017 2016 (millions of Canadian $) Current Canada 65 113 116 Foreign 250 36 40 315 149 156 Deferred Canada 49 (185 ) 101 Foreign 235 751 95 Foreign – U.S. Tax Reform and 2018 FERC Actions (167 ) (804 ) — 117 (238 ) 196 Income Tax Expense/(Recovery) 432 (89 ) 352 Geographic Components of Income before Income Taxes year ended December 31 2018 2017 2016 (millions of Canadian $) Canada 433 (339 ) 219 Foreign 3,516 3,645 618 Income before Income Taxes 3,949 3,306 837 Reconciliation of Income Tax Expense/(Recovery) year ended December 31 2018 2017 2016 (millions of Canadian $) Income before income taxes 3,949 3,306 837 Federal and provincial statutory tax rate 27 % 27 % 27 % Expected income tax expense 1,066 893 226 U.S. Tax Reform and 2018 FERC Actions (167 ) (804 ) — Foreign income tax rate differentials (432 ) (81 ) (196 ) Loss/(income) from equity investments and non-controlling interests 50 (64 ) (68 ) Income tax differential related to regulated operations (54 ) (42 ) 81 Non-taxable portion of capital gains (11 ) (42 ) — Asset impairment charges 1 — 34 242 Non-deductible amounts — 4 46 Other (20 ) 13 21 Income Tax Expense/(Recovery) 432 (89 ) 352 1 Net of nil (2017 – nil , 2016 – $112 million ) attributed to higher foreign tax rates. Deferred Income Tax Assets and Liabilities at December 31 2018 2017 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,238 1,379 Difference in accounting and tax bases of impaired assets and assets held for sale 574 651 Regulatory and other deferred amounts 858 512 Unrealized foreign exchange losses on long-term debt 491 216 Financial instruments — 10 Other 292 227 3,453 2,995 Less: valuation allowance 1,159 832 2,294 2,163 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 6,449 6,240 Equity investments 1,069 632 Taxes on future revenue requirement 300 238 Other 180 140 7,998 7,250 Net Deferred Income Tax Liabilities 5,704 5,087 The above deferred tax amounts have been classified in the Consolidated balance sheet as follows: at December 31 2018 2017 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 12) 322 316 Deferred Income Tax Liabilities Deferred income tax liabilities 6,026 5,403 Net Deferred Income Tax Liabilities 5,704 5,087 At December 31, 2018 , the Company has recognized the benefit of unused non-capital loss carryforwards of $1,867 million ( 2017 – $1,280 million ) for federal and provincial purposes in Canada, which expire from 2030 to 2038. The Company has no t recognized the benefit of capital loss carry forwards of $821 million ( 2017 – $668 million ) for federal and provincial purposes in Canada. The Company also has recognized the benefit of Ontario minimum tax credits of $91 million ( 2017 – $82 million ), which expire from 2026 to 2038. At December 31, 2018 , the Company has recognized the benefit of unused net operating loss carryforwards of US$889 million ( 2017 – US$1,800 million ) for federal purposes in the U.S., which expire from 2029 to 2037. The Company has no t recognized the benefit of unused net operating loss carryforwards of US$706 million ( 2017 – US$710 million ) for federal purposes in the U.S. The Company also has recognized the benefit of alternative minimum tax credits of US$1 million ( 2017 – US$56 million ). At December 31, 2018 , the Company has recognized the benefit of unused net operating loss carryforwards of US$3 million ( 2017 – US$7 million ) in Mexico, which expire from 2024 to 2028. 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, 2018 by approximately $619 million ( 2017 – $569 million ) if there had been a provision for these taxes. Income Tax Payments Income tax payments of $338 million , net of refunds, were made in 2018 ( 2017 – payments, net of refunds, of $247 million ; 2016 – payments, net of refunds, of $105 million ). Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2018 2017 2016 (millions of Canadian $) Unrecognized tax benefit at beginning of year 15 18 17 Gross increases – tax positions in prior years 13 — 3 Gross decreases – tax positions in prior years (5 ) (1 ) — Gross increases – tax positions in current year — 2 2 Settlement — — (1 ) Lapse of statutes of limitations (4 ) (4 ) (3 ) Unrecognized Tax Benefit at End of Year 19 15 18 Subject to the results of audit examinations by taxing authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on its financial statements. TransCanada and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2010. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2011. TransCanada's practice is to recognize interest and penalties related to income tax uncertainties in Income tax expense. Income tax expense for the year ended December 31, 2018 reflects $1 million of interest recovery and nil for penalties ( 2017 – nil of interest expense and nil for penalties; 2016 – nil of interest expense and nil for penalties). At December 31, 2018 , the Company had $ 3 million accrued for interest expense and nil accrued for penalties ( December 31, 2017 – $ 4 million accrued for interest expense and nil accrued for penalties). |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT 2018 2017 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 2019 to 2020 350 11.4 % 500 10.8 % U.S. (2018 and 2017 – US$400) 2021 546 9.9 % 501 9.9 % Medium Term Notes Canadian 2019 to 2048 7,504 4.8 % 6,504 4.9 % Senior Unsecured Notes U.S. (2018 – US$17,192; 2017 – US$14,892) 2019 to 2049 23,456 5.1 % 18,644 5.1 % 31,856 26,149 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2018 and 2017 – US$200) 2023 273 7.9 % 250 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2018 and 2017 – US$33) 2026 44 7.5 % 41 7.5 % 921 895 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2018 – US$2,250; 2017 – US$2,750) 2 2020 to 2045 3,070 4.4 % 3,443 4.0 % TC PIPELINES, LP Unsecured Loan Facility U.S. (2018 – US$40; 2017 – US$185) 2021 55 3.8 % 232 2.7 % Unsecured Term Loan U.S. (2018 – US$500; 2017 – US$670) 3 2022 682 3.6 % 839 2.7 % Senior Unsecured Notes U.S. (2018 and 2017 – US$1,200) 2021 to 2027 1,637 4.4 % 1,502 4.4 % 2,374 2,573 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2018 and 2017 – US$672) 2021 to 2026 918 7.2 % 842 7.2 % GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2018 – US$35; 2017 – US$55) 2019 48 3.3 % 69 1.1 % Senior Unsecured Notes U.S. (2018 and 2017 – US$250) 2020 to 2035 341 5.6 % 313 5.6 % 389 382 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2018 – US$240; 2017 – US$259) 2021 to 2030 327 7.7 % 324 7.7 % 2018 2017 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 Unsecured Loan Facility U.S. (2018 – US$19; 2017 – nil) 2023 26 3.6 % — — Senior Secured Notes 4 U.S. (2018 – nil; 2017 – US$30) — — 38 6.0 % 26 38 TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2018 – US$24; 2017 – US$25) 2020 33 3.5 % 31 1.1 % NORTH BAJA PIPELINE, LLC Unsecured Term Loan U.S. (2018 – US$50; 2017 – nil) 2021 68 3.5 % — — 39,982 34,677 Current portion of long-term debt (3,462 ) (2,866 ) Unamortized debt discount and issue costs (241 ) (174 ) Fair value adjustments 5 230 238 36,509 31,875 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. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premium and discounts. 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$500 million term loan facility was amended in September 2017 to extend the maturity dates from 2018 to 2022. 4 These notes were secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements. 5 The fair value adjustments include $ 232 million (2017 – $ 242 million) related to the acquisition of Columbia. The fair value adjustments also include a decrease of $ 2 million (2017 – $ 4 million) related to hedged interest rate risk. Refer to Note 24, Risk management and financial instruments, for further information. Principal Repayments At December 31, 2018, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2019 2020 2021 2022 2023 Principal repayments on long-term debt 3,465 2,834 2,098 2,100 1,930 Long-Term Debt Issued The Company issued long-term debt over the three years ended December 31, 2018 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED October 2018 Senior Unsecured Notes March 2049 US 1,000 5.10 % October 2018 Senior Unsecured Notes May 2028 US 400 4.25 % 1 July 2018 Medium Term Notes July 2048 800 4.18 % July 2018 Medium Term Notes March 2028 200 3.39 % 2 May 2018 Senior Unsecured Notes May 2028 US 1,000 4.25 % May 2018 Senior Unsecured Notes May 2048 US 1,000 4.875 % May 2018 Senior Unsecured Notes May 2038 US 500 4.75 % 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 3 June 2018 US 5,213 Floating June 2016 Medium Term Notes July 2023 300 3.69 % 4 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 % NORTH BAJA PIPELINE, LLC December 2018 Unsecured Term Loan December 2021 US 50 Floating PORTLAND NATURAL GAS TRANSMISSION SYSTEM April 2018 Unsecured Loan Facility April 2023 US 19 Floating TUSCARORA GAS TRANSMISSION COMPANY August 2017 Unsecured Term Loan August 2020 US 25 Floating April 2016 Unsecured Term Loan April 2019 US 10 Floating TC PIPELINES, LP May 2017 Senior Unsecured Notes May 2027 US 500 3.90 % TRANSCANADA PIPELINE USA LTD. June 2016 Acquisition Bridge Facility 3 June 2018 US 1,700 Floating ANR PIPELINE COMPANY June 2016 Senior Unsecured Notes June 2026 US 240 4.14 % 1 Reflects coupon rate on re-opening of a pre-existing senior unsecured notes issue. The notes were issued at a discount to par, resulting in a re-issuance yield of 4.439 per cent . 2 Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at a discount to par, resulting in a re-issuance yield of 3.41 per cent . 3 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 second quarter 2017. 4 Reflects coupon rate on re-opening of a pre-existing 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, 2018 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED August 2018 Senior Unsecured Notes US 850 6.50 % March 2018 Debentures 150 9.45 % January 2018 Senior Unsecured Notes US 500 1.875 % January 2018 Senior Unsecured Notes US 250 Floating 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 % TC PIPELINES, LP December 2018 Unsecured Term Loan US 170 Floating COLUMBIA PIPELINE GROUP, INC. June 2018 Senior Unsecured Notes US 500 2.45 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM May 2018 Senior Secured Notes US 18 5.90 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP March 2018 Senior Unsecured Notes US 9 6.73 % 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 % 1 These facilities were put in place to finance a portion of the Columbia acquisition and were fully retired in second quarter 2017. Interest Expense Interest expense in the three years ended December 31 was as follows: year ended December 31 2018 2017 2016 (millions of Canadian $) Interest on long-term debt 1,877 1,794 1,765 Interest on junior subordinated notes 391 348 180 Interest on short-term debt 73 33 18 Capitalized interest (124 ) (173 ) (176 ) Amortization and other financial charges 1 48 67 211 2,265 2,069 1,998 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. In 2016, this amount includes dividend equivalent payments of $109 million on the subscription receipts issued to partially fund the Columbia acquisition. Refer to Note 20, Common shares, for further information. The Company made interest payments of $ 2,156 million in 2018 ( 2017 – $ 1,987 million ; 2016 – $ 1,721 million ) on long-term debt, junior subordinated notes and short-term debt, net of interest capitalized. |
JUNIOR SUBORDINATED NOTES
JUNIOR SUBORDINATED NOTES | 12 Months Ended |
Dec. 31, 2018 | |
Junior Subordinated Notes [Abstract] | |
JUNIOR SUBORDINATED NOTES | JUNIOR SUBORDINATED NOTES 2018 2017 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate 1 Outstanding at December 31 Effective Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED 2 US$1,000 notes issued 2007 at 6.35% 3 2067 1,364 5.6 % 1,252 5.0 % US$750 notes issued 2015 at 5.875% 4,5 2075 1,024 6.5 % 939 5.9 % US$1,200 notes issued 2016 at 6.125% 4,5 2076 1,637 7.2 % 1,502 6.6 % US$1,500 notes issued 2017 at 5.55% 4,5 2077 2,047 6.2 % 1,878 5.6 % $1,500 notes issued 2017 at 4.90% 4,5 2077 1,500 5.5 % 1,500 5.1 % 7,572 7,071 Unamortized debt discount and issue costs (64 ) (64 ) 7,508 7,007 1 The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for loan fees and discounts. 2 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 3 In May 2017, Junior subordinated notes of US $1 billion converted from a fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three month LIBOR plus 2.21 per cent . 4 The Junior subordinated notes were issued to TransCanada Trust, a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. 5 The coupon rate is initially a fixed interest rate for the first ten years and converts to a floating rate thereafter. In March 2017, TransCanada Trust (the Trust) issued US$ 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 then three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the then 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, 2018 | |
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 2018 2017 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,655 1,852 The Company's Net (loss)/income attributable to non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2018 2017 2016 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP (185 ) 220 215 Non-controlling interest in Portland Natural Gas Transmission System 1 — 9 20 Non-controlling interest in Columbia Pipeline Partners LP 2 — 9 17 (185 ) 238 252 1 Non-controlling interest in 2017 for the period January 1 to May 31 when TransCanada sold its remaining interest in Portland to TC PipeLines, LP. Refer to Note 26, Acquisitions and dispositions for further information. 2 Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of Columbia Pipeline Partners LP. TC PipeLines, LP During 2018 , the non-controlling interest in TC PipeLines, LP increased from 74.3 per cent to 74.5 per cent due to periodic issuances of common units in TC PipeLines, LP to third parties under an at-the-market issuance program. In 2017 , the non-controlling interest in TC PipeLines, LP ranged between 73.2 per cent and 74.3 per cent , and in 2016 , between 72.0 per cent and 73.2 per cent. Portland Natural Gas Transmission System On June 1, 2017, TransCanada sold its remaining 11.81 per cent directly held interest in Portland to TC PipeLines, LP and, as a result, at December 31, 2017 and 2018, non-controlling interest in Portland was nil . On January 1, 2016, TransCanada sold 49.9 per cent of Portland to TC PipeLines, LP. Refer to Note 26, Acquisitions and dispositions for further information. Columbia Pipeline Partners LP On July 1, 2016, TransCanada acquired Columbia, which included a 53.5 per cent non-controlling interest in Columbia Pipeline Partners LP (CPPL). On February 17, 2017, TransCanada 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 TransCanada'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 at-the-market issuance 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 had 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, 2018 | |
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, 2016 702,614 12,102 Issued under public offerings 1 156,825 7,752 Dividend reinvestment and share purchase plan 2,942 177 Exercise of options 1,683 74 Repurchase of shares (305 ) (6 ) Outstanding at December 31, 2016 863,759 20,099 Dividend reinvestment and share purchase plan 12,824 790 At-the-market equity issuance program 1 3,462 216 Exercise of options 1,331 62 Outstanding at December 31, 2017 881,376 21,167 At-the-market equity issuance program 1 20,050 1,118 Dividend reinvestment and share purchase plan 15,937 855 Exercise of options 734 34 Outstanding at December 31, 2018 918,097 23,174 1 Net of issue costs and deferred income taxes. Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares without par value. Dividend Reinvestment and Share Purchase Plan Effective July 1, 2016, the Company re-initiated the issuance of common shares from treasury under its Dividend Reinvestment Plan (DRP) and Share Purchase Plan. Under these plans, eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Under the DRP, common shares were issued from treasury at a discount of two per cent. TransCanada Corporation At-the-Market Equity Issuance Program In June 2017, the Company established an At-the-Market Equity Issuance Program (ATM program) that allows, from time to time, for the issuance of common shares from treasury at the prevailing market price when sold through the Toronto Stock Exchange (TSX), the New York Stock Exchange (NYSE) or any other existing trading market for TransCanada common shares in Canada or the United States. The ATM program, which is effective for a 25 -month period, is utilized as appropriate in order to manage the Company's capital structure over time. Under the original ATM program, the Company could issue up to $1.0 billion in common shares or the U.S. dollar equivalent. In 2017, 3.5 million common shares were issued under the ATM program at an average price of $63.03 per share for proceeds of $216 million , net of approximately $2 million of related commissions and fees. In June 2018, the Company replenished the capacity available under its existing ATM program. This allows for the issuance of additional common shares from treasury for an aggregate gross sales price of up to $1.0 billion , for a revised total of $2.0 billion or its U.S. dollar equivalent. The ATM program, as amended, is effective to July 23, 2019. In 2018, 20 million common shares were issued under the ATM program at an average price of $56.13 per share for proceeds of $1.1 billion , net of approximately $10 million of related commissions and fees. Common Share Public Offering and Subscription Receipts To partially fund the Columbia acquisition, in April 2016, the Company issued 96.6 million subscription receipts at a price of $45.75 each for gross proceeds of approximately $4.4 billion . Holders of subscription receipts received one common share in exchange for each subscription receipt on July 1, 2016 upon closing of the acquisition. Holders of record at close of business on April 15, 2016 and June 30, 2016 received a cash payment per subscription receipt that was equal in amount to dividends declared on each common share. For the year ended December 31, 2016, $109 million of dividend equivalent payments on these subscription receipts were recorded as Interest expense. In November 2016, the Company issued 60.2 million common shares at a price of $58.50 each for gross proceeds of approximately $3.5 billion . Proceeds from this offering were used to repay a portion of the US$6.9 billion acquisition bridge facilities which were used to partially fund the Columbia acquisition. Common Shares Repurchased In November 2015, the Company received approval from the TSX for a normal course issuer bid (NCIB) allowing it to repurchase, for cancellation, up to 21 million of its common shares representing three per cent of its then issued and outstanding common shares. Under the NCIB, which expired in November 2016, the Company purchased these common shares through the facilities of the TSX and other designated exchanges and published markets in Canada, or through off-exchange block purchases by way of private agreement. In January 2016, the Company repurchased 305,407 of its common shares at an average price of $44.90 for a total of $14 million . These shares had a weighted average cost of $6 million with the difference of $8 million between the total price paid and the weighted average cost recorded in Additional paid-in capital. Basic and Diluted Net Income per Common Share Net income per common share is calculated by dividing Net income attributable to common shares by the weighted average number of common shares outstanding. The higher weighted average number of shares for the diluted earnings per share calculation is due to options exercisable under TransCanada's Stock Option Plan and shares issuable under the DRP. Weighted Average Common Shares Outstanding (millions) 2018 2017 2016 Basic 902 872 759 Diluted 903 874 760 Stock Options Number of (thousands) Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (years) Options outstanding at January 1, 2018 11,026 $51.38 Options granted 2,250 $56.89 Options exercised (734 ) $42.65 Options forfeited/expired (138 ) $57.23 Options Outstanding at December 31, 2018 12,404 $52.83 3.6 Options Exercisable at December 31, 2018 8,189 $50.72 2.6 At December 31, 2018 , an additional 9,790,373 common shares were reserved for future issuance from treasury under TransCanada's Stock Option Plan. 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. The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions: year ended December 31 2018 2017 2016 Weighted average fair value $5.80 $7.22 $5.67 Expected life (years) 1 5.7 5.7 5.8 Interest rate 2.1 % 1.2 % 0.7 % Volatility 2 16 % 18 % 21 % Dividend yield 4.2 % 3.6 % 4.9 % Forfeiture rate 3 — — 5 % 1 Expected life is based on historical exercise activity. 2 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. 3 On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance. The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $13 million in 2018 ( 2017 – $12 million ; 2016 – $15 million ). At December 31, 2018 , unrecognized compensation costs related to non-vested stock options was $16 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 2018 2017 2016 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 10 28 31 Fair value of options that have vested 101 140 126 Total options vested 2.1 million 2.3 million 2.1 million As at December 31, 2018 , the aggregate intrinsic value of the total options exercisable was $8 million and the total intrinsic value of options outstanding was $9 million . Shareholder Rights Plan TransCanada's Shareholder Rights Plan is designed to provide the Board of Directors with sufficient time to explore and develop alternatives for maximizing shareholder value in the event of a takeover offer for the Company and to encourage the fair treatment of shareholders in connection with any such offer. Attached to each common share is one right that, under certain circumstances, entitles certain holders to purchase an additional common share of the Company for half the then current market price of one common share. |
PREFERRED SHARES
PREFERRED SHARES | 12 Months Ended |
Dec. 31, 2018 | |
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |
PREFERRED SHARES | PREFERRED SHARES at December 31 Number of Shares Outstanding Current Yield Annual Dividend Per Share Redemption Price Per Share Redemption and Conversion Option Date Right to Convert Into 1,2 2018 2017 2016 (thousands) (millions of Canadian $) 3 Cumulative First Preferred Shares Series 1 9,498 3.266 % $0.8165 $25.00 December 31, 2019 Series 2 233 233 233 Series 2 12,502 Floating 4 Floating $25.00 December 31, 2019 Series 1 306 306 306 Series 3 8,533 2.152 % $0.538 $25.00 June 30, 2020 Series 4 209 209 209 Series 4 5,467 Floating 4 Floating $25.00 June 30, 2020 Series 3 134 134 134 Series 5 12,714 2.263 % $0.56575 $25.00 January 30, 2021 Series 6 310 310 310 Series 6 1,286 Floating 4 Floating $25.00 January 30, 2021 Series 5 32 32 32 Series 7 24,000 4.00 % $1.00 $25.00 April 30, 2019 Series 8 589 589 589 Series 9 18,000 4.25 % $1.0625 $25.00 October 30, 2019 Series 10 442 442 442 Series 11 10,000 3.80 % $0.95 $25.00 November 30, 2020 Series 12 244 244 244 Series 13 20,000 5.50 % $1.375 $25.00 May 31, 2021 Series 14 493 493 493 Series 15 40,000 4.90 % $1.225 $25.00 May 31, 2022 Series 16 988 988 988 Carrying value 3,980 3,980 3,980 1 Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90 -day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), 2.96 per cent (Series 12), 4.69 per cent (Series 14) and 3.85 per cent (Series 16). These rates reset quarterly with the then current T-Bill rate. 2 The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then five -year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), 2.96 per cent (Series 11), 4.69 per cent , subject to a minimum of 5.50 per cent (Series 13) and 3.85 per cent , subject to a minimum of 4.90 per cent (Series 15). 3 Net of underwriting commissions and deferred income taxes. 4 The floating quarterly dividend rate for the Series 2 preferred shares is 3.633 per cent and for the Series 4 preferred shares is 2.993 per cent for the period starting December 31, 2018 to, but excluding, March 29, 2019. The floating quarterly dividend rate for the Series 6 preferred shares is 3.086 per cent for the period starting October 30, 2018 to, but excluding, January 30, 2019. These rates will reset each quarter going forward. In February 2016, holders of 1,285,739 Series 5 cumulative redeemable first preferred shares exercised their option to convert to Series 6 cumulative redeemable first preferred shares. In April 2016, the Company completed a public offering of 20 million Series 13 cumulative redeemable minimum rate reset first preferred shares at $25 per share, resulting in gross proceeds of $ 500 million . In November 2016, the Company completed a public offering of 40 million Series 15 cumulative redeemable minimum rate reset first preferred shares at $25 per share, resulting in gross proceeds of $ 1.0 billion . The holders of preferred shares are entitled to receive a fixed cumulative quarterly preferential dividend as and when declared by the Board with the exception of Series 2, Series 4 and Series 6 preferred shares. The holders of Series 2, Series 4 and Series 6 preferred shares are entitled to receive quarterly floating rate cumulative preferential dividends as and when declared by the Board. The holders will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter. TransCanada may, at its option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. In addition, Series 2, Series 4 and Series 6 preferred shares are redeemable by TransCanada at any time other than on a designated date for $25.50 per share plus all accrued and unpaid dividends on such redemption date. |
OTHER COMPREHENSIVE INCOME_(LOS
OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS | 12 Months Ended |
Dec. 31, 2018 | |
Equity [Abstract] | |
OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS | OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS Components of OCI, including the portion attributable to non-controlling interests and related tax effects, are as follows: year ended December 31, 2018 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 1,323 35 1,358 Change in fair value of net investment hedges (57 ) 15 (42 ) Change in fair value of cash flow hedges (14 ) 4 (10 ) Reclassification to net income of gains and losses on cash flow hedges 27 (6 ) 21 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (153 ) 39 (114 ) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 20 (5 ) 15 Other comprehensive income on equity investments 113 (27 ) 86 Other Comprehensive Income 1,259 55 1,314 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 disposal of foreign operations (77 ) — (77 ) 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 ) 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, 2016 (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 (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 ) Other comprehensive income/(loss) before reclassifications 2 1,150 (9 ) (114 ) 72 1,099 Amounts reclassified from AOCI 4,5 — 16 15 12 43 Net current period other comprehensive income/(loss) 1,150 7 (99 ) 84 1,142 Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform — 1 (12 ) (6 ) (17 ) AOCI balance at December 31, 2018 107 (23 ) (314 ) (376 ) (606 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 In 2018 , other comprehensive income before reclassifications on currency translation adjustments and cash flow hedges are net of non-controlling interest gains of $166 million ( 2017 – $159 million losses; 2016 – $14 million losses) and losses of $1 million ( 2017 – $4 million gains and 2016 – $3 million gains), 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 $15 million ( $11 million , net of tax) at December 31, 2018 . 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. 5 Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million and $2 million , respectively. Details about reclassifications out of AOCI into the Consolidated statement of income are as follows: Amounts Reclas s ified 1 Affected Line Item year ended December 31 2018 2017 2016 (millions of Canadian $) Cash flow hedges Commodities (4 ) 20 (57 ) Revenues (Energy) Interest (18 ) (17 ) (14 ) Interest expense (22 ) 3 (71 ) Total before tax 6 (1 ) 29 Income tax expense (16 ) 2 (42 ) Net of tax 1,3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial gains and losses (16 ) (15 ) (22 ) Plant operating costs and other 2 Settlement charge (4 ) (2 ) — Plant operating costs and other 2 (20 ) (17 ) (22 ) Total before tax 5 5 6 Income tax expense (15 ) (12 ) (16 ) Net of tax 1 Equity investments Equity income (16 ) (15 ) (19 ) Income from equity investments 4 4 5 Income tax expense (12 ) (11 ) (14 ) Net of tax 1,3 Currency translation adjustments Realization of foreign currency translation gains on disposal of foreign operations — 77 — Gain/(loss) on assets held for sale/sold — — — Income tax expense — 77 — Net of tax 1 1 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 23, Employee post-retirement benefits for further information. 3 Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million (2017 – nil , 2016 – nil ) and $2 million (2017 – nil , 2016 – nil ), respectively. |
EMPLOYEE POST-RETIREMENT BENEFI
EMPLOYEE POST-RETIREMENT BENEFITS | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 ( 2017 and 2016 – nine years ). On December 31, 2017 , the Columbia DB Plan merged with TransCanada'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 U.S. DC plan. In addition, on January 1, 2018, the Columbia other post-retirement benefit plan merged with TransCanada's U.S. other post-retirement benefit plan. 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 for the plans are amortized out of AOCI over the expected average remaining service life of employees, which was approximately 12 years at December 31, 2018 ( 2017 and 2016 – 12 years ). In 2018 , the Company expensed $59 million ( 2017 – $42 million ; 2016 – $52 million ) for the savings and DC Plans. 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. Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2018 2017 2016 (millions of Canadian $) DB Plans 103 163 111 Other post-retirement benefit plans 23 7 8 Savings and DC Plans 59 42 52 185 212 171 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 $17 million letter of credit to the Canadian DB Plan in 2018 ( 2017 – $27 million ; 2016 – $20 million ), resulting in a total of $277 million provided to the Canadian DB Plan under letters of credit at December 31, 2018 . The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2018 and the next required valuation will be as at January 1, 2019. In December 2018, the Company recorded a settlement resulting from lump sum payments made in 2018 to certain terminated non-union vested participants in the Company's U.S. DB Plan related to voluntary cash settlement options available to these participants. The impact of the settlement was determined using assumptions consistent with those employed at December 31, 2017. The settlement reduced the Company's U.S. DB Plan's unrealized actuarial losses by $4 million which was included in OCI and resulted in a settlement charge of $4 million which was recorded in net benefit costs in 2018. Effective December 1, 2018, the plan was amended to include this unlimited lump sum payment option for certain union employees who were not previously eligible. In 2017, 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 on TransCanada’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 OCI, 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. Also 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 . 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 OCI. All other assumptions were consistent with those employed at December 31, 2016. The Company's funded status at December 31 is comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2018 2017 2018 2017 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,646 3,456 375 372 Service cost 121 113 4 4 Interest cost 134 135 14 14 Employee contributions 5 5 — 3 Benefits paid (177 ) (166 ) (23 ) (19 ) Actuarial (gain)/loss (92 ) 253 43 19 Curtailment — (14 ) — (2 ) Settlement (71 ) (66 ) — — Foreign exchange rate changes 87 (70 ) 17 (16 ) Benefit obligation – end of year 3,653 3,646 430 375 Change in Plan Assets Plan assets at fair value – beginning of year 3,451 3,208 365 354 Actual return on plan assets (73 ) 358 (15 ) 45 Employer contributions 2 103 163 23 7 Employee contributions 5 5 — 3 Benefits paid (176 ) (166 ) (27 ) (19 ) Settlement (71 ) (57 ) — — Foreign exchange rate changes 82 (60 ) 30 (25 ) Plan assets at fair value – end of year 3,321 3,451 376 365 Funded Status – Plan Deficit (332 ) (195 ) (54 ) (10 ) 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 a $17 million letter of credit provided to the Canadian DB Plan for funding purposes ( 2017 – $27 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 $) 2018 2017 2018 2017 Intangible and other assets (Note 12) — — 192 193 Accounts payable and other (1 ) (1 ) (8 ) (8 ) Other long-term liabilities (Note 15) (331 ) (194 ) (238 ) (195 ) (332 ) (195 ) (54 ) (10 ) 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 $) 2018 2017 2018 2017 Projected benefit obligation 1 (3,653 ) (3,646 ) (246 ) (203 ) Plan assets at fair value 3,321 3,451 — — Funded Status – Plan Deficit (332 ) (195 ) (246 ) (203 ) 1 The projected benefit obligation for the pension benefit plans differ 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 2018 2017 (millions of Canadian $) Accumulated benefit obligation (3,347 ) (3,372 ) Plan assets at fair value 3,321 3,451 Funded Status (26 ) 79 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 2018 2017 (millions of Canadian $) Accumulated benefit obligation (3,347 ) (944 ) Plan assets at fair value 3,321 925 Funded Status – Plan Deficit (26 ) (19 ) The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: Percentage of Target Allocations at December 31 2018 2017 2018 Debt securities 33 % 30 % 25% to 45% Equity securities 56 % 64 % 40% to 70% Alternatives 11 % 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 $) 2018 2017 2018 2017 Debt securities 8 7 0.3 % 0.2 % Equity securities 7 3 0.2 % 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 24, Risk management and financial instruments. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 Asset Category Cash and Cash Equivalents 48 44 — 17 — — 48 61 1 2 Equity Securities: Canadian 355 410 138 151 — — 493 561 13 15 U.S. 460 543 116 354 — — 576 897 16 24 International 40 45 281 322 — — 321 367 9 10 Global 116 — 268 301 — — 384 301 10 8 Emerging 8 8 138 147 — — 146 155 4 4 Fixed Income Securities: Canadian Bonds: Federal — — 186 193 — — 186 193 5 5 Provincial — — 198 194 — — 198 194 5 5 Municipal — — 8 8 — — 8 8 1 — Corporate — — 112 122 — — 112 122 3 3 U.S. Bonds: Federal 350 — — 244 — — 350 244 9 6 State — — — 41 — — — 41 — 1 Municipal — — — 4 — — — 4 — — Corporate 145 — 51 234 — — 196 234 5 6 International: Government 6 — 4 4 — — 10 4 1 — Corporate 19 — 18 5 — — 37 5 1 — Mortgage backed 128 — — 73 — — 128 73 3 2 Other Investments: Real estate — — — — 196 140 196 140 5 4 Infrastructure — — — — 163 70 163 70 4 2 Private equity funds — — — — 3 6 3 6 1 — Funds held on deposit 142 136 — — — — 142 136 4 3 1,817 1,186 1,518 2,414 362 216 3,697 3,816 100 100 The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2016 199 Purchases and sales 11 Realized and unrealized gains 6 Balance at December 31, 2017 216 Purchases and sales 127 Realized and unrealized gains 19 Balance at December 31, 2018 362 The Company's expected funding contributions in 2019 are approximately $113 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $61 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $17 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 2019 190 24 2020 193 23 2021 198 23 2022 203 23 2023 207 23 2024 to 2028 1,081 114 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, 2018 . 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 2018 2017 2018 2017 Discount rate 3.90 % 3.60 % 4.10 % 3.70 % Rate of compensation increase 3.00 % 3.00 % — — 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 2018 2017 2016 2018 2017 2016 Discount rate 3.60 % 3.95 % 4.20 % 3.70 % 4.15 % 4.30 % Expected long-term rate of return on plan assets 6.70 % 6.50 % 6.70 % 4.00 % 6.05 % 5.95 % Rate of compensation increase 3.00 % 1.20 % 0.80 % — — — 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 six per cent weighted average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019 measurement purposes. The rate was assumed to decrease gradually to 4.50 % by 2028 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 25 (21 ) The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2018 2017 2016 2018 2017 2016 Service cost 1 121 108 107 4 4 3 Other components of net benefit cost 1 Interest cost 134 122 127 14 14 13 Expected return on plan assets (221 ) (178 ) (175 ) (16 ) (21 ) (11 ) Amortization of actuarial loss 15 14 20 1 1 2 Amortization of regulatory asset 18 37 27 — 1 1 Amortization of transitional obligation related to regulated business — — — — — 2 Settlement charge – regulatory asset — 2 — — — — Settlement charge – AOCI 4 2 — — — — (50 ) (1 ) (1 ) (1 ) (5 ) 7 Net Benefit Cost Recognized 71 107 106 3 (1 ) 10 1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income. Pre-tax amounts recognized in AOCI were as follows: 2018 2017 2016 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 364 53 273 11 270 21 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 2019 is $12 million and $2 million , respectively. Pre-tax amounts recognized in OCI were as follows: 2018 2017 2016 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 net income (15 ) (1 ) (18 ) (1 ) (20 ) (2 ) Curtailment — — (14 ) (2 ) — — Settlement (4 ) — (11 ) — — — Funded status adjustment 110 43 46 (7 ) 43 (5 ) 91 42 3 (10 ) 23 (7 ) |
RISK MANAGEMENT AND FINANCIAL I
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS | 12 Months Ended |
Dec. 31, 2018 | |
Risk Management and Financial Instruments [Abstract] | |
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS | RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and shareholder value. Risk management strategies, policies and limits are designed to ensure TransCanada's risks and related exposures are in line with the Company's business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits 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. Commodity price risk The following strategies may be used to manage exposure to commodity price risk in the Company's non-regulated businesses: • In the Company's power generation business, TransCanada manages the exposure to fluctuating commodity prices through long-term contracts and hedging activities including selling and purchasing power and natural gas in forward markets • In the Company's non-regulated natural gas storage business, TransCanada's exposure to seasonal natural gas price spreads is managed with a portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in forward markets to lock in future positive margins • In the Company's liquids marketing business, TransCanada enters into pipeline and storage terminal capacity contracts. TransCanada 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. The Company's exposure to electricity price risk has been greatly reduced following the sales of its U.S. Northeast power generation assets in 2017 and its U.S. Northeast power retail contracts on March 1, 2018 as well as the continued wind-down of its remaining U.S. Power marketing contracts. Interest rate risk TransCanada utilizes short-term and long-term debt to finance its operations which exposes the Company to interest rate risk. TransCanada typically pays fixed rates of interest on its long-term debt and floating rates on its commercial paper programs and amounts drawn on its credit facilities. A small portion of TransCanada's long-term debt is at floating interest rates. In addition, the Company is exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. The Company manages its interest rate risk using a combination of interest rate swaps and option derivatives. Foreign exchange risk TransCanada 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 exposed to currency fluctuations. A portion of TransCanada's businesses generate 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 its net income. As the Company's U.S. dollar-denominated operations continue to grow, this exposure increases. A portion of this risk is offset by interest expense on U.S. dollar-denominated debt. The balance of the exposure is hedged on a rolling one-year basis using foreign exchange derivatives, but the exposure remains beyond that period. Net investment hedges The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency swaps and foreign exchange options. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows: 2018 2017 at December 31 Fair 1,2 Notional Fair 1,2 Notional (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2019) 3 (43 ) US 300 (199 ) US 1,200 U.S. dollar foreign exchange options (maturing 2019 to 2020) (47 ) US 2,500 5 US 500 (90 ) US 2,800 (194 ) US 1,700 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2018 , Net income includes net realized gains of $2 million ( 2017 – gains of $4 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 2018 2017 (millions of Canadian $, unless otherwise noted) Notional amount 31,000 (US 22,700) 25,400 (US 20,200) Fair value 31,700 (US 23,200) 28,900 (US 23,100) Counterparty Credit Risk TransCanada's maximum counterparty credit exposure with respect to financial instruments at December 31, 2018 , without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available-for-sale assets, derivative assets and a loan receivable. 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 dealing with creditworthy counterparties, obtaining financial assurances such as guarantees, letters of credit or cash where considered necessary, and setting limits on the amount TransCanada can transact with any one counterparty. There is no guarantee that these techniques will protect the Company from material losses. The Company monitors its counterparties and regularly reviews its accounts receivable. The Company records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2018 and 2017, there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the year. TransCanada has significant credit and performance exposures to financial institutions as they hold cash deposits and provide committed credit lines and letters of credit that help manage the Company's exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. Fair Value of Non-Derivative Financial Instruments Available-for-sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy. Credit risk has been taken into consideration when calculating the fair value of non-derivative 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: 2018 2017 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Long-term debt, including current portion 1,2 (Note 17) (39,971 ) (42,284 ) (34,741 ) (40,180 ) Junior subordinated notes (Note 18) (7,508 ) (6,665 ) (7,007 ) (7,233 ) (47,479 ) (48,949 ) (41,748 ) (47,413 ) 1 Long-term debt is recorded at amortized cost, except for US$750 million ( 2017 – US$1.1 billion ) that is attributed to hedged risk and recorded at fair value. 2 Net income in 2018 included unrealized losses of $2 million ( 2017 – gains of $4 million ) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$750 million of long-term debt at December 31, 2018 ( 2017 – US$1.1 billion ). 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: 2018 2017 at December 31 LMCI Restricted Investments Other Restricted Investments 1 LMCI Restricted Investments Other Restricted Investments 1 (millions of Canadian $) Fair value of fixed income securities 2 Fixed income securities (maturing within 1 year) — 22 — 23 Fixed income securities (maturing within 1-5 years) — 110 — 107 Fixed income securities (maturing within 5-10 years) 140 — 14 — Fixed income securities (maturing after 10 years) 952 — 790 — 1,092 132 804 130 1 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. 2 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. 2018 2017 2016 year ended December 31 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments LMCI restricted investments 1 Other restricted investments LMCI restricted investments 1 Other restricted investments Net unrealized gains/(losses) 11 — (3 ) 1 (28 ) (1 ) Net realized losses 2 (4 ) — (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 The realized gains and 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. Unrealized gains and losses on derivative instruments are not necessarily representative of the amounts that will be realized on settlement. 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, 2018 is as follows: at December 31, 2018 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 — — 716 717 Foreign exchange — — 16 1 17 Interest rate 3 — — — 3 4 — 16 717 737 Intangible and other assets (Note 12) Commodities 2 1 — — 50 51 Foreign exchange — — 1 — 1 Interest rate 8 1 — — 9 9 1 1 50 61 Total Derivative Assets 13 1 17 767 798 Accounts payable and other (Note 14) Commodities 2 (4 ) — — (622 ) (626 ) Foreign exchange — — (105 ) (188 ) (293 ) Interest rate — (3 ) — — (3 ) (4 ) (3 ) (105 ) (810 ) (922 ) Other long-term liabilities (Note 15) Commodities 2 — — — (28 ) (28 ) Foreign exchange — — (2 ) — (2 ) Interest rate (11 ) (1 ) — — (12 ) (11 ) (1 ) (2 ) (28 ) (42 ) Total Derivative Liabilities (15 ) (4 ) (107 ) (838 ) (964 ) Total Derivatives (2 ) (3 ) (90 ) (71 ) (166 ) 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, 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 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. Derivatives in fair value hedging relationships The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities: at December 31 Carrying amount Fair value hedging adjustments 1 (millions of Canadian $) 2018 2017 2018 2017 Current portion of long-term debt (748 ) (688 ) 3 1 Long-term debt (273 ) (685 ) — 4 (1,021 ) (1,373 ) 3 5 1 At December 31, 2018 and 2017, adjustments for discontinued hedging relationships included in these balances were nil . Notional and Maturity Summary The maturity and notional amount 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, 2018 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 23,865 44 59 — — Sales 1 17,689 56 79 — — Millions of U.S. dollars — — — 3,862 1,650 Maturity dates 2019-2023 2019-2027 2019 2019 2019-2030 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. 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 — — — 2,931 2,300 Millions of Mexican pesos — — — 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 . 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 2018 2017 2016 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 2 28 62 123 Foreign exchange (248 ) 88 25 Interest rate — (1 ) — Amount of realized gains/(losses) in the year Commodities 351 (107 ) (204 ) Foreign exchange (24 ) 18 62 Interest rate — 1 — Derivative instruments in hedging relationships Amount of realized (losses)/gains in the year Commodities (1 ) 23 (167 ) Foreign exchange — 5 (101 ) Interest rate (1 ) 1 4 1 Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively. 2 In 2018 and 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 22) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: year ended December 31 2018 2017 2016 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI 1 Commodities (1 ) (1 ) 39 Interest rate (13 ) 4 5 (14 ) 3 44 1 No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI. Effect of fair value and cash flow hedging relationships The following table details amounts presented on the Consolidated statement of income in which the effects of fair value or cash flow hedging relationships are recorded. year ended December 31 Revenues (Energy) Interest Expense (millions of Canadian $) 2018 2017 2016 2018 2017 2016 Total Amount Presented in the Consolidated Statement of Income 2,124 3,593 4,206 (2,265 ) (2,069 ) (1,998 ) Fair Value Hedges Interest rate contracts Hedged items — — — (71 ) (74 ) (74 ) Derivatives designated as hedging instruments — — — (4 ) 1 8 Cash Flow Hedges Reclassification of gains/(losses) on derivative instruments from AOCI to net income 1,2 Interest rate contracts — — — 22 17 14 Commodity contracts 5 (20 ) 57 — — — 1 Refer to Note 22, Other comprehensive income/(loss) and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests. 2 There are no amounts recognized in earnings that were excluded from effectiveness testing. Offsetting of derivative instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the Consolidated balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2018 : at December 31, 2018 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 768 (626 ) 142 Foreign exchange 18 (18 ) — Interest rate 12 (4 ) 8 798 (648 ) 150 Derivative – Liability Commodities (654 ) 626 (28 ) Foreign exchange (295 ) 18 (277 ) Interest rate (15 ) 4 (11 ) (964 ) 648 (316 ) 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, 2017 : at December 31, 2017 Gross Derivative Instruments 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. With respect to the derivative instruments presented above, the Company provided cash collateral of $143 million and letters of credit of $22 million ( 2017 – $165 million and $30 million ) to its counterparties. At December 31, 2018 , the Company held nil in cash collateral and $1 million in letters of credit ( 2017 – nil and $3 million ) from counterparties on asset exposures. 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. The company may also need to provide collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits. Based on contracts in place and market prices at December 31, 2018 , the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $6 million ( 2017 – $2 million ), for which the Company has provided no collateral in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on December 31, 2018 , the Company would have been required to provide collateral of $6 million ( 2017 – $2 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 2018 , are categorized as follows: at December 31, 2018 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 581 187 — 768 Foreign exchange — 18 — 18 Interest rate — 12 — 12 Derivative Instrument Liabilities: Commodities (555 ) (95 ) (4 ) (654 ) Foreign exchange — (295 ) — (295 ) Interest rate — (15 ) — (15 ) 26 (188 ) (4 ) (166 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2018 . 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 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) 2018 2017 Balance at beginning of year (7 ) 16 Transfers out of Level III 5 (19 ) Total gains/(losses) included in Net income 8 (17 ) Settlements (9 ) 18 Sales — (5 ) Foreign exchange (1 ) — Balance at end of year 1 (4 ) (7 ) 1 Revenues include unrealized losses of $5 million attributed to derivatives in the Level III category that were still held at December 31, 2018 ( 2017 – unrealized losses 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 decrease or increase , respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2018 . |
CHANGES IN OPERATING WORKING CA
CHANGES IN OPERATING WORKING CAPITAL | 12 Months Ended |
Dec. 31, 2018 | |
CHANGES IN OPERATING WORKING CAPITAL | |
CHANGES IN OPERATING WORKING CAPITAL | CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2018 2017 2016 (millions of Canadian $) Increase in Accounts receivable (69 ) (576 ) (482 ) Increase in Inventories (49 ) (38 ) (87 ) Decrease/(increase) in Assets held for sale — 14 (13 ) Decrease in Other current assets 45 189 328 (Decrease)/increase in Accounts payable and other (70 ) 151 424 Increase in Accrued interest 41 12 62 (Decrease)/increase in Liabilities related to assets held for sale — (25 ) 16 (Increase)/decrease in Operating Working Capital (102 ) (273 ) 248 |
ACQUISITIONS AND DISPOSITIONS
ACQUISITIONS AND DISPOSITIONS | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
ACQUISITIONS AND DISPOSITIONS | ACQUISITIONS AND DISPOSITIONS U.S. Natural Gas Pipelines Iroquois Gas Transmission System and Portland Natural Gas Transmission System On June 1, 2017, TransCanada 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, TransCanada closed the sale of its remaining 11.81 per cent interest in Portland to TC PipeLines, LP. Proceeds from these transactions were US$765 million , before post-closing adjustments, and were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and Portland debt. In January 2016 , TransCanada closed the sale of a 49.9 per cent interest in Portland 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 Portland debt. In March 2016 , TransCanada acquired a 4.87 per cent interest in Iroquois for an aggregate purchase price of US$54 million , increasing TransCanada’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 TransCanada’s interest in Iroquois to 50 per cent . Acquisition of Columbia On July 1, 2016 , TransCanada acquired 100 per cent ownership of 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 proceeds of approximately $4.4 billion from the sale of subscription receipts, draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and, upon closing of the acquisition, were exchanged into approximately 96.6 million common shares of TransCanada. Refer to Note 20, Common shares for further information on the subscription receipts. 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. TransCanada 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 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 ) to a total of US$7,802 million (2016 – US$7,747 million ) at December 31, 2017. This adjustment did not impact the Company's net income. 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 TransCanada. (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 then U.S. effective tax rate of 39 per cent . The fair value of Columbia’s non-controlling interests was based on the approximately 53.8 million 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, TransCanada 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 TransCanada’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) 627 (820 ) Net Income/(Loss) Attributable to Common Shares 234 (971 ) Energy Cartier Wind On October 24, 2018 , the Company completed the sale of its 62 per cent interest in the Cartier Wind power facilities to Innergex Renewable Energy Inc for proceeds of $630 million , before post-closing adjustments. As a result, the Company recorded a gain on sale of $170 million ( $143 million after tax) which is included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income. Ontario Solar Assets On December 19, 2017, the Company completed the sale of its Ontario solar assets to a third party for proceeds of $541 million , before post-closing adjustments. As a result, the Company recorded a gain on sale of $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 In 2018, u pon finalizing its 2017 annual tax return for its U.S. operations, the Company recorded a $27 million income tax recovery related to the sale of its U.S. Northeast power generation 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 $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 , TransCanada 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 $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, TransCanada 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. |
COMMITMENTS, CONTINGENCIES AND
COMMITMENTS, CONTINGENCIES AND GUARANTEES | 12 Months Ended |
Dec. 31, 2018 | |
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 $) 2019 81 7 74 2020 78 7 71 2021 76 4 72 2022 69 3 66 2023 67 3 64 2024 and thereafter 390 8 382 761 32 729 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 2018 was $84 million ( 2017 – $93 million ; 2016 – $145 million ). Other commitments TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business. 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, 2018 , TransCanada had the following capital expenditure commitments: • approximately $4.6 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with the construction of the Coastal GasLink and NGTL System pipeline projects • approximately $0.1 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with Columbia Gas and Columbia Gulf growth projects • approximately $0.3 billion for its Mexico natural gas pipelines, primarily related to construction of the Sur de Texas, Villa de Reyes and Tula pipeline projects • approximately $0.4 billion for its Liquids pipelines, primarily related to the development of Keystone XL and construction of White Spruce • approximately $0.7 billion for its Energy business, primarily related to its proportionate share of commitments for Bruce Power's life extension program • approximately $0.1 billion for its Corporate segment related to various information technology services agreements. Contingencies TransCanada is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2018 , the Company had accrued approximately $40 million ( 2017 – $34 million ) related to operating facilities, which represents the present value of the estimated future amount it expects to spend to remediate the sites. However, additional liabilities may be incurred as assessments take place and remediation efforts continue. TransCanada 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. Guarantees TransCanada and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of this entity. Such agreements include a guarantee and a letter of credit which are primarily related to construction services and the delivery of natural gas. TransCanada 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 TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners. The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees is as follows: 2018 2017 at December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas ranging to 2020 183 1 315 2 Bruce Power ranging to 2021 88 — 88 1 Other jointly owned entities ranging to 2059 104 11 104 13 375 12 507 16 1 TransCanada's share of the potential estimated current or contingent exposure. |
CORPORATE RESTRUCTURING COSTS
CORPORATE RESTRUCTURING COSTS | 12 Months Ended |
Dec. 31, 2018 | |
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. The Company incurred corporate restructuring costs and recorded a provision to allow for planned severance costs in future years, as well as expected future losses under lease commitments. Cumulatively to December 31, 2018, the Company has incurred costs of $ 86 million for employee severance and $ 60 million for lease commitments, net of $ 157 million related to costs that were recoverable through regulatory and tolling structures. The Company recorded additional provisions in 2018 to reflect the changes in expected future losses under lease commitments. The remaining lease commitments provision at December 31, 2018 is expected to be fully realized by 2027. Changes in the restructuring liability were as follows: (millions of Canadian $) Employee Severance Lease Commitments Total Restructuring liability as at December 31, 2016 36 63 99 Restructuring charges 1 — 6 6 Accretion expense — 1 1 Cash payments (27 ) (17 ) (44 ) Restructuring liability as at December 31, 2017 9 53 62 Restructuring charges 1 — 42 42 Accretion expense — 1 1 Cash payments (9 ) (15 ) (24 ) Restructuring Liability as at December 31, 2018 — 81 81 1 At December 31, 2018, the Company recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million as a regulatory asset on the Consolidated balance sheet related to costs that are recoverable through regulatory and tolling structures in future periods (2017 – $3 million and $3 million , respectively). |
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES | 12 Months Ended |
Dec. 31, 2018 | |
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 $) 2018 2017 ASSETS Current Assets Cash and cash equivalents 45 41 Accounts receivable 79 63 Inventories 24 23 Other 13 11 161 138 Plant, Property and Equipment 3,026 3,535 Equity Investments 965 917 Goodwill 453 490 Intangible and Other Assets 8 3 4,613 5,083 LIABILITIES Current Liabilities Accounts payable and other 88 137 Dividends payable — 1 Accrued interest 24 23 Current portion of long-term debt 79 88 191 249 Regulatory Liabilities 43 34 Other Long-Term Liabilities 3 3 Deferred Income Tax Liabilities 13 13 Long-Term Debt 3,125 3,244 3,375 3,543 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 $) 2018 2017 Balance sheet Equity investments 4,575 4,372 Off-balance sheet Potential exposure to guarantees 170 171 Maximum exposure to loss 4,745 4,543 |
ACCOUNTING POLICIES (Policies)
ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation These consolidated financial statements include the accounts of TransCanada 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. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation. |
Use of Estimates and Judgments | Use of Estimates and Judgments In preparing these consolidated financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but they do not involve significant subjectivity or uncertainty. Others also have a material impact but the assumptions underlying these accounting estimates also relate to matters that are highly uncertain at the time the estimate or judgment is made or are subjective. Significant estimates and judgments used in the preparation of the consolidated financial statements that involve assumptions that are highly uncertain or subjective include, but are not limited to: • fair value of plant, property and equipment and equity investments (Notes 8 and 9) • fair value of goodwill (Note 11) • fair value of intangible assets (Note 12) and • fair value of assets and liabilities acquired in a business combination (Note 26). Significant estimates and judgments used in the preparation of the consolidated financial statements that are provided by an independent expert or do not involve assumptions that are highly uncertain or subjective include, but are not limited to: • depreciation rates of plant, property and equipment (Note 8) • carrying value of regulatory assets and liabilities (Note 10) • 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 23) • fair value of financial instruments (Note 24) and • provisions for commitments, contingencies, guarantees (Note 27) and restructuring costs (Note 28). 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), the Alberta Energy Regulator (AER) or the B.C. Oil and Gas Commission (OGC). 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 TransCanada'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. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An asset qualifies for the use of RRA when it meets three criteria: • a regulator must establish or approve the rates for the regulated services or activities • the regulated rates must be designed to recover the cost of providing the services or products and • it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers because of the demand for services or products and the level of direct or indirect competition. TransCanada'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 the Company's 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 Canadian Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Canadian natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. Revenues from the Company's Canadian natural gas pipelines are subject to regulatory decisions by the NEB. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural gas capacity for transportation services, which includes a return of and on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are generally 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 tolls. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved return on equity (ROE) assumptions. Adjustments to revenues are recorded when the NEB decision is received. Canadian natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. U.S. Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. 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. U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Natural Gas Storage and Other Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage including specifications with regards to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores for customers. 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 term of the contract. The Company also owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas and associated liquids are produced. Midstream natural gas service revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas for which it provides midstream services. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Liquids Pipelines Capacity Arrangements and Transportation Revenues from the Company's liquids pipelines are generated mainly from providing customers with firm capacity arrangements to transport crude oil. The performance obligation in these contracts is the reservation of a specified amount of capacity together with the transportation of crude oil on a monthly basis. Revenues earned from these arrangements are recognized ratably over the term of the contract regardless of the amount of crude oil that is transported. Revenues for interruptible or volumetric-based services are recognized when the service is performed. Liquids pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the crude oil that it transports for customers. Energy Power Generation Revenues from the Company's Energy business are primarily derived from long-term contractual commitments to provide power capacity to meet the demands of the market, and from the sale of electricity to both centralized markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are invoiced and received on a monthly basis. Natural Gas Storage and Other Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Revenues are recognized as the services are provided. Term storage revenues are invoiced and received on a monthly basis. Revenues earned from the sale of proprietary natural gas are recognized in the month of delivery. Revenues from ancillary services are recognized as the service is provided. The Company does not take ownership of the natural gas that it stores for customers. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. |
Inventories | Inventories Inventories primarily consist of materials and supplies including spare parts and fuel, crude oil in transit and natural gas inventory in storage. 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. Once an asset is classified as held for sale, depreciation expense is no longer recorded. |
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 seven 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 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. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets The Company reviews long-lived assets such as plant, property and equipment, equity investments and capital projects in development 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 that are estimated for an asset within Plant, property and equipment, or the estimated selling price of any long-lived asset 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 and 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 Company will then perform the quantitative goodwill impairment test. The Company can elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Company compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. |
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. TransCanada has PPAs for the sale of power that are accounted for as operating leases where TransCanada 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 TransCanada 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 was subleased to third parties under terms and conditions similar to the PPAs, and was 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), TransCanada 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 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. For those AROs that the Company records, the following assumptions are used: • when the asset is expected to be retired • the scope and cost of abandonment and reclamation activities that are required and • appropriate inflation and discount rates. 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 because the Company intends to operate them as long as there is supply and demand. 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, and 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 or cancelled/retired by government agencies. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TransCanada are not attributed a value for accounting purposes. When required, TransCanada accrues emission liabilities on the Consolidated balance sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues. |
Stock Options and Other Compensation Programs | Stock Options and Other Compensation Programs TransCanada's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period with an offset to Additional paid-in capital. Upon exercise of stock options, amounts originally recorded against Additional paid-in capital are reclassified to Common shares on the Consolidated balance sheet. 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 (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 (AOCI) and into net income over the expected 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 change in the fair value of the hedging derivative is recognized in OCI. 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 foreign exchange gains and losses on the hedging instruments are recognized in OCI. 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 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 a 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 or Plant, property and equipment 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 2018 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 from these contracts in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in amounts that reflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as the Company's "performance obligations." The total consideration to which the Company expects to be entitled can include fixed and variable amounts. The Company has variable revenue that is subject to factors outside the Company’s influence, such as market prices, actions of third parties and weather conditions. The Company considers this variable revenue to be "constrained" as it cannot be reliably estimated, and therefore recognizes variable revenue when the service is provided. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and related cash flows. The Company’s accounting policies related to revenue recognition have not substantially changed as a result of adopting the new guidance on revenue from contracts with customers. Results reported for 2018 reflect the application of the new guidance, while the 2017 and 2016 comparative results were prepared and reported under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP." Under legacy U.S. GAAP, revenues were recognized when the risk, rewards, and benefits were transferred to the customer by the Company providing the goods or services under the contract, in an amount the Company expected to collect from the customer. Under the new guidance applied in 2018, revenues are recognized when the Company satisfies its performance obligations by transferring control of the promised goods or services to its customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company has elected to utilize a practical expedient to recognize revenues from its U.S. and certain Mexico natural gas pipelines contracts as customers are invoiced. The new guidance was effective January 1, 2018, was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition. Refer to Note 5, Revenues, for further information related to the impact of adopting 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 changes 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 was effective January 1, 2018 and did not have a material impact on the Company's 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 intra-entity asset transfers when the transfer occurs. The new guidance was effective January 1, 2018, was applied using a modified retrospective approach, and resulted in an adjustment to retained earnings of $95 million . In February 2018, the FASB issued new guidance that allows a reclassification from AOCI to retained earnings for stranded tax effects resulting from U.S. Tax Reform. This guidance can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change is recognized. This new guidance is effective January 1, 2019, however, early adoption is permitted. The Company elected to early adopt this guidance effective fourth quarter 2018 and used a portfolio approach for releasing the income tax effects from AOCI to retained earnings. The Company applied this guidance retrospectively, at the beginning of the period of adoption, resulting in an adjustment to retained earnings of $17 million . 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 period and end of period total amounts on the statement of cash flows. This new guidance was effective January 1, 2018, was applied retrospectively, and did not have an impact on the Company's consolidated financial statements. Employee post-retirement benefits In March 2017, the FASB issued new guidance that requires 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 was effective January 1, 2018 and did not have a material impact on the Company's consolidated financial statements. Hedge accounting In August 2017, the FASB issued new guidance 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 requires additional disclosures including cumulative basis adjustments for fair value hedges and the effect of hedging on individual line items in the statement of income. This new guidance is effective January 1, 2019 with early adoption permitted. This new guidance, which the Company elected to adopt effective January 1, 2018, was applied prospectively and did not have a material impact on the Company's consolidated financial statements. Derecognition of Nonfinancial Assets In February 2017, the FASB issued new guidance that clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset. The FASB also amended the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. This new guidance was effective January 1, 2018, was applied using the modified retrospective transition method and did not have a material impact on the Company's consolidated financial statements. 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 with early adoption permitted. The Company elected to adopt this guidance effective fourth quarter 2018 as it simplified goodwill impairment testing. The guidance was applied prospectively and used in the 2018 annual goodwill impairment test. Future Accounting Changes Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required 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. 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. Lessees will classify leases as finance or operating, with classification affecting the pattern of expense recognition in the statement of income. The new guidance does not make extensive changes to lessor accounting. The Company currently expects that substantially all of its leases where the Company is the lessor will continue to be classified as operating leases under the new standard. In January 2018, the FASB issued an optional practical expedient, to be applied upon transition, to omit the evaluation of land easements not previously accounted for as leases that existed or expired prior to the entity's adoption of the new lease guidance. An entity that elects this practical expedient is required to apply it consistently to all of its existing or expired land easements not previously accounted for as leases. The Company will apply this practical expedient upon transition to the new standard. The new guidance is effective January 1, 2019, with early adoption permitted. The Company will adopt the new standard on its effective date. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application being January 1, 2019. In July 2018, the FASB issued a transition option allowing entities to not apply the new guidance, including disclosure requirements, to the comparative periods they present in their financial statements in the year of adoption. The Company will apply this transition option and use the effective date as the date of initial application. Consequently, financial information will not be updated and disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. The Company will elect the package of practical expedients which permits entities not to reassess prior conclusions about lease identification, lease classification and initial direct costs under the rules of the new standard. The Company believes that the most significant effects of adoption will relate to the recognition of new ROU assets and lease liabilities on the Company's balance sheet for its operating leases and providing significant new disclosures about the Company's leasing activities. The guidance will not impact the Company's income statement. On adoption, the Company will recognize ROU assets of approximately $606 million and additional operating lease liabilities of approximately $600 million based on the present value of the remaining minimum lease payments for existing operating leases. The new standard also provides practical expedients for a Company’s ongoing accounting. The Company will elect the short-term lease recognition exemption for all eligible leases. This means, for those leases that qualify, the Company will not recognize ROU assets or lease liabilities. The Company will also elect the practical expedient to not separate lease and non-lease components for all leases for which the Company is the lessee and for facility and liquids tank terminals for which the Company is the lessor. 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 as 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. Fair value measurement In August 2018, the FASB issued new guidance that amends certain disclosure requirements for fair value measurements. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Defined benefit plans In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to DB pension and other post retirement benefit plans. This new guidance is effective January 1, 2021, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Implementation costs of cloud computing arrangements In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting arrangement over the term of the arrangement. This guidance is effective January 1, 2020, however, early adoption is permitted. This guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Consolidation In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. |
SEGMENTED INFORMATION (Tables)
SEGMENTED INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment | year ended December 31, 2018 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Energy Corporate 1 Total (millions of Canadian $) Revenues 4,038 4,314 619 2,584 2,124 — 13,679 Intersegment revenues — 162 — — 56 (218 ) 2 — 4,038 4,476 619 2,584 2,180 (218 ) 13,679 Income from equity investments 12 256 22 64 355 5 3 714 Plant operating costs and other (1,405 ) (1,368 ) (34 ) (630 ) (313 ) 159 2 (3,591 ) Commodity purchases resold — — — — (1,488 ) — (1,488 ) Property taxes (266 ) (199 ) — (98 ) (6 ) — (569 ) Depreciation and amortization (1,129 ) (664 ) (97 ) (341 ) (119 ) — (2,350 ) Goodwill and other asset impairment charges — (801 ) — — — — (801 ) Gain on sale of assets — — — — 170 — 170 Segmented earnings/(losses) 1,250 1,700 510 1,579 779 (54 ) 5,764 Interest expense (2,265 ) Allowance for funds used during construction 526 Interest income and other 3 (76 ) Income before income taxes 3,949 Income tax expense (432 ) Net income 3,517 Net loss attributable to non-controlling interests 185 Net income attributable to controlling interests 3,702 Preferred share dividends (163 ) Net income attributable to common shares 3,539 Capital spending Capital expenditures 2,442 5,591 463 110 767 45 9,418 Capital projects in development 36 1 — 459 — — 496 Contributions to equity investments — 179 334 12 490 — 1,015 2,478 5,771 797 581 1,257 45 10,929 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. Refer to Note 9, Equity investments, for further 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 ) 2 — 3,693 3,635 570 2,009 3,593 (51 ) 13,449 Income/(loss) from equity investments 11 240 (9 ) (3 ) 471 63 3 773 Plant operating costs and other (1,300 ) (1,340 ) (42 ) (623 ) (550 ) (51 ) 2 (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 sale of assets — — — — 631 — 631 Segmented earnings/(losses) 1,236 1,760 426 (251 ) 1,552 (39 ) 4,684 Interest expense (2,069 ) Allowance for funds used during construction 507 Interest income and other 3 184 Income before income taxes 3,306 Income tax recovery 89 Net income 3,395 Net income attributable to non-controlling interests (238 ) Net income attributable to controlling interests 3,157 Preferred share dividends (160 ) Net income attributable to common shares 2,997 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 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income/(loss) from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term 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 ) 2 — 3,682 2,582 378 1,755 4,206 (56 ) 12,547 Income/(loss) from equity investments 12 214 (3 ) (1 ) 292 — 514 Plant operating costs and other (1,245 ) (1,057 ) (43 ) (568 ) (884 ) (64 ) 2 (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 (1,998 ) Allowance for funds used during construction 419 Interest income and other 103 Income before income taxes 837 Income tax expense (352 ) Net income 485 Net income attributable to non-controlling interests (252 ) Net income attributable to controlling interests 233 Preferred share dividends (109 ) Net income attributable to common shares 124 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 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. at December 31 2018 2017 (millions of Canadian $) Total Assets by segment Canadian Natural Gas Pipelines 18,407 16,904 U.S. Natural Gas Pipelines 44,115 35,898 Mexico Natural Gas Pipelines 7,058 5,716 Liquids Pipelines 17,352 15,438 Energy 8,475 8,503 Corporate 3,513 3,642 98,920 86,101 |
Revenue from External Customers by Geographic Areas | year ended December 31 2018 2017 2016 (millions of Canadian $) Revenues Canada – domestic 4,187 3,618 3,697 Canada – export 1,075 1,255 1,177 United States 7,798 8,006 7,295 Mexico 619 570 378 13,679 13,449 12,547 |
Schedule of Long-Lived Assets by Country | at December 31 2018 2017 (millions of Canadian $) Plant, Property and Equipment Canada 23,226 21,632 United States 37,385 30,693 Mexico 5,892 4,952 66,503 57,277 |
REVENUES (Tables)
REVENUES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenues | The following tables summarizes total Revenues for the year ended December 31, 2018 . (millions of Canadian $) Canadian U.S. Mexico Liquids Pipelines Energy Total Revenues from contracts with customers Capacity arrangements and transportation 4,038 3,549 614 2,079 — 10,280 Power generation — — — — 1,771 1,771 Natural gas storage and other — 654 5 3 81 743 4,038 4,203 619 2,082 1,852 12,794 Other revenues 1,2 — 111 — 502 272 885 4,038 4,314 619 2,584 2,124 13,679 1 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 24, Risk management and financial instruments, for further information on income from financial instruments. 2 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 16, Income taxes, for further information. |
Impact of New Revenue Recognition Guidance | Impact of New Revenue Recognition Guidance on Date of Adoption The following table illustrates the impact of the adoption of the new revenue recognition guidance on the Company's previously reported consolidated balance sheet line items: As reported Adjustment (millions of Canadian $) December 31, 2017 January 1, 2018 Current Assets Accounts receivable 2,522 (62 ) 2,460 Other 1 691 79 770 Current Liabilities Accounts payable and other 2 4,057 17 4,074 1 Adjustment relates to contract assets previously included in Accounts receivable. 2 Adjustment relates to contract liabilities previously included in Accounts receivable. Pro-forma Financial Statements under Legacy U.S. GAAP As required by the new revenue recognition guidance, the following tables illustrate the pro-forma impact on the affected line items on the Consolidated balance sheet, as at December 31, 2018 , using legacy U.S. GAAP: December 31, 2018 As reported Pro-forma using legacy U.S. GAAP (millions of Canadian $) Current Assets Accounts receivable 2,535 2,694 Other 1,180 1,021 |
Contract Balances | Contract Balances (millions of Canadian $) December 31, 2018 January 1, 2018 Receivables from contracts with customers 1,684 1,736 Contract assets 1 159 79 Long-term contract assets 2 21 — Contract liabilities 3 11 17 Long-term contract liabilities 4 121 — 1 Recorded as part of Other current assets on the Consolidated balance sheet. 2 Recorded as part of Intangibles and other assets on the Consolidated balance sheet. 3 Comprised of deferred revenue recorded in Accounts payable and other on the Consolidated balance sheet. During the year ended December 31, 2018 , $17 million of revenue was recognized that was included in the contract liability at the beginning of the year. 4 Comprised of deferred revenue recorded in Other long-term liabilities on the Consolidated balance sheet. |
ASSETS HELD FOR SALE (Tables)
ASSETS HELD FOR SALE (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Assets and Liabilities Classified as Held for Sale | At December 31, 2018, the related assets and liabilities were classified as held for sale in the Energy segment as follows: (millions of Canadian $) Assets held for sale Accounts receivable 6 Plant, property and equipment 537 Total assets held for sale 543 Liabilities related to assets held for sale Other long-term liabilities (3 ) Total liabilities related to assets held for sale 1 (3 ) 1 Included in Accounts payable and other on the Consolidated balance sheet. |
OTHER CURRENT ASSETS (Tables)
OTHER CURRENT ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Assets [Abstract] | |
Schedule of Other Current Assets | at December 31 2018 2017 (millions of Canadian $) Fair value of derivative contracts (Note 24) 737 332 Contract assets (Note 5) 159 — Regulatory assets (Note 10) 83 23 Cash provided as collateral 55 99 Prepaid expenses 41 109 Other 105 128 1,180 691 |
PLANT, PROPERTY AND EQUIPMENT (
PLANT, PROPERTY AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Plant, Property and Equipment | 2018 2017 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 10,764 4,500 6,264 10,153 4,190 5,963 Compression 3,289 1,677 1,612 3,021 1,593 1,428 Metering and other 1,247 613 634 1,188 569 619 15,300 6,790 8,510 14,362 6,352 8,010 Under construction 2,111 — 2,111 940 — 940 17,411 6,790 10,621 15,302 6,352 8,950 Canadian Mainline Pipeline 10,077 6,777 3,300 9,763 6,455 3,308 Compression 3,642 2,656 986 3,605 2,499 1,106 Metering and other 652 241 411 655 207 448 14,371 9,674 4,697 14,023 9,161 4,862 Under construction 149 — 149 156 — 156 14,520 9,674 4,846 14,179 9,161 5,018 Other Canadian Natural Gas Pipelines 1 Other 1,842 1,420 422 1,815 1,363 452 Under construction 124 — 124 4 — 4 1,966 1,420 546 1,819 1,363 456 33,897 17,884 16,013 31,300 16,876 14,424 U.S. Natural Gas Pipelines Columbia Gas Pipeline 6,711 251 6,460 3,550 125 3,425 Compression 2,932 132 2,800 1,547 64 1,483 Metering and other 2,884 75 2,809 2,306 37 2,269 12,527 458 12,069 7,403 226 7,177 Under construction 4,347 — 4,347 3,332 — 3,332 16,874 458 16,416 10,735 226 10,509 ANR Pipeline 1,600 443 1,157 1,427 365 1,062 Compression 1,978 388 1,590 1,582 286 1,296 Metering and other 1,217 324 893 961 268 693 4,795 1,155 3,640 3,970 919 3,051 Under construction 272 — 272 358 — 358 5,067 1,155 3,912 4,328 919 3,409 2018 2017 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,322 951 1,371 2,107 822 1,285 Great Lakes 2,180 1,251 929 1,988 1,113 875 Columbia Gulf 1,753 74 1,679 1,115 37 1,078 Midstream 1,212 91 1,121 1,085 54 1,031 Other 2 1,190 474 716 1,950 574 1,376 8,657 2,841 5,816 8,245 2,600 5,645 Under construction 846 — 846 699 — 699 9,503 2,841 6,662 8,944 2,600 6,344 31,444 4,454 26,990 24,007 3,745 20,262 Mexico Natural Gas Pipelines Pipeline 3,172 301 2,871 2,872 214 2,658 Compression 506 41 465 448 30 418 Metering and other 640 91 549 573 65 508 4,318 433 3,885 3,893 309 3,584 Under construction 1,990 — 1,990 1,368 — 1,368 6,308 433 5,875 5,261 309 4,952 Liquids Pipelines Keystone Pipeline System Pipeline 9,780 1,271 8,509 9,002 992 8,010 Pumping equipment 1,065 184 881 1,022 152 870 Tanks and other 3 3,598 488 3,110 3,314 385 2,929 14,443 1,943 12,500 13,338 1,529 11,809 Under construction 4 18 — 18 456 — 456 14,461 1,943 12,518 13,794 1,529 12,265 Intra-Alberta Pipelines 5 Pipeline 762 22 740 748 3 745 Pumping equipment 104 3 101 104 — 104 Tanks and other 291 8 283 259 1 258 1,157 33 1,124 1,111 4 1,107 Under construction 84 — 84 47 — 47 1,241 33 1,208 1,158 4 1,154 15,702 1,976 13,726 14,952 1,533 13,419 Energy Natural Gas 6 2,062 708 1,354 2,645 743 1,902 Wind 7 — — — 673 204 469 Natural Gas Storage and Other 741 169 572 734 156 578 2,803 877 1,926 4,052 1,103 2,949 Under construction 1,735 — 1,735 1,028 — 1,028 4,538 877 3,661 5,080 1,103 3,977 Corporate 448 210 238 411 168 243 92,337 25,834 66,503 81,011 23,734 57,277 1 Includes Foothills, Ventures LP, Great Lakes Canada and Coastal GasLink . 2 Includes Portland, North Baja, Tuscarora and Crossroads as well as Bison for 2017. Bison's remaining carrying value was fully impaired at December 31, 2018. 3 Includes tanks that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $ 194 million and $ 23 million , respectively, at December 31, 2018 (2017 – $ 184 million and $ 19 million , respectively), while revenues of $ 15 million were recognized in 2018 (2017 – $ 16 million ; 2016 – $ 16 million ). 4 Certain costs related to the Keystone XL project were recorded in Plant, property and equipment at December 31, 2017. In 2018, these costs were reclassified to Capital projects in development as the Company recommenced capitalizing Keystone XL development costs. 5 Includes Northern Courier and White Spruce. Northern Courier is accounted for as an operating lease and was placed in service on November 1, 2017. The cost and accumulated depreciation of this facility were $ 1,130 million and $ 32 million , respectively, at December 31, 2018 (2017 – $ 1,111 million and $ 4 million , respectively), while revenues of $ 142 million were recognized in 2018 (2017 – $ 20 million ). 6 Includes Coolidge, Grandview, Bécancour, Halton Hills and the Alberta cogeneration natural gas-fired facilities. Coolidge, Grandview and Bécancour have long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $ 655 million and $ 268 million , respectively, at December 31, 2018 ( 2017 – $ 1,264 million and $ 354 million , respectively). At December 31, 2018, the cost and accumulated depreciation of Coolidge were reclassified to Assets held for sale. Refer to Note 6, Assets held for sale, for further information. Revenues of $ 216 million were recognized in 2018 ( 2017 – $ 215 million ; 2016 – $ 212 million ) through the sale of electricity under the related PPAs for these assets. 7 The Company closed the sale of its Cartier Wind power assets on October 24, 2018. Refer to Note 26, Acquisitions and dispositions, for further information. |
EQUITY INVESTMENTS (Tables)
EQUITY INVESTMENTS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 2018 2017 2016 2018 2017 Canadian Natural Gas Pipelines TQM 50.0 % 12 11 12 71 68 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 87 87 92 677 641 Iroquois 2 50.0 % 60 59 54 291 280 Millennium 3 47.5 % 75 66 33 511 291 Pennant Midstream 3 47.0 % 17 11 6 256 228 Other Various 17 17 29 113 92 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % 27 66 (3 ) 627 399 TransGas nil — (12 ) — — — Liquids Pipelines Grand Rapids 5 50.0 % 65 17 (1 ) 1,028 996 Other 6 Various (1 ) (20 ) — 21 20 Energy Bruce Power 7 48.3 % 311 434 293 3,166 2,987 Portlands Energy 8 50.0 % 36 31 33 289 301 ASTC Power Partnership 50.0 % — — (37 ) — — Other Various 8 6 3 63 63 714 773 514 7,113 6,366 1 At December 31, 2018 , 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 ( 2017 – US$115 million ) due to the fair value assessment of assets at the time of acquisition. 2 At December 31, 2018 , the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million ( 2017 – US$41 million ) due mainly to the fair value assessment of the assets at the time of acquisition. 3 Acquired as part of Columbia Pipeline Group, Inc. (Columbia) on July 1, 2016. Income from Equity investments reflects equity earnings from the date of acquisition. 4 TransCanada 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 foreign exchange gains and losses recorded in the Corporate segment which are fully offset in Interest income and other in the Consolidated statement of income. 5 Grand Rapids was placed in service in August 2017. At December 31, 2018 , the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $102 million ( 2017 – $105 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, 2018 and 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil . 7 At December 31, 2018 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $870 million ( 2017 – $902 million ) due to the fair value assessment of assets at the time of acquisitions. 8 At December 31, 2018 , the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million ( 2017 – $73 million ) due mainly to interest capitalized during construction. |
Summarized Financial Information of Equity Investments | year ended December 31 2018 2017 2016 (millions of Canadian $) Income Revenues 4,836 4,913 4,336 Operating and other expenses (3,545 ) (2,993 ) (3,068 ) Net income 1,515 1,636 1,080 Net income attributable to TransCanada 714 773 514 at December 31 2018 2017 (millions of Canadian $) Balance Sheet Current assets 2,209 2,176 Non-current assets 20,647 17,869 Current liabilities (2,049 ) (1,577 ) Non-current liabilities (9,042 ) (8,217 ) |
RATE-REGULATED BUSINESSES (Tabl
RATE-REGULATED BUSINESSES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets and Liabilities | at December 31 2018 2017 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 1,051 940 n/a Operating and debt-service regulatory assets 2 12 — 1 Pensions and other post-retirement benefits 1,3 379 388 n/a Foreign exchange on long-term debt 1,4 46 — 1-11 Other 143 71 n/a 1,631 1,399 Less: Current portion included in Other current assets (Note 7) 83 23 1,548 1,376 Regulatory Liabilities Operating and debt-service regulatory liabilities 2 96 188 1 Pensions and other post-retirement benefits 3 53 164 n/a ANR related post-employment and retirement benefits other than pension 5 54 66 n/a Long term adjustment account 6 1,015 1,142 2-45 Bridging amortization account 6 305 202 12 Pipeline abandonment trust balance 1,113 825 n/a Cost of removal 7 261 216 n/a Deferred income taxes 165 75 n/a Deferred income taxes – U.S. Tax Reform 8 1,394 1,659 n/a Other 65 47 n/a 4,521 4,584 Less: Current portion included in Accounts payable and other (Note 14) 591 263 3,930 4,321 1 These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period. 2 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulator for inclusion in determining tolls for the following calendar year. 3 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates. 4 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. 5 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, $11 million ( US$8 million ) of the regulatory liability balance at December 31, 2018 ( 2017 – $26 million ; US$21 million ) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $43 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. 6 These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. The 2018 LTAA balance of $ 1,015 million consists of $ 932 million to be amortized over two years with the remaining balance to be amortized over 45 years . 7 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 operations for future costs to be incurred. 8 These balances represent the impact of U.S. Tax Reform. The regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax liabilities that gave rise to the regulatory liabilities. See Note 16, Income taxes, for further information on U.S. Tax Reform. |
GOODWILL (Tables)
GOODWILL (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill | The Company has recorded the following Goodwill on its acquisitions: (millions of Canadian $) U.S. Natural Gas Pipelines Balance at January 1, 2017 13,958 Columbia adjustment (Note 26) 71 Foreign exchange rate changes (945 ) Balance at December 31, 2017 13,084 Tuscarora impairment charge (79 ) Foreign exchange rate changes 1,173 Balance at December 31, 2018 14,178 |
INTANGIBLE AND OTHER ASSETS (Ta
INTANGIBLE AND OTHER ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |
Schedule of Other Assets | at December 31 2018 2017 (millions of Canadian $) Capital projects in development 1,051 596 Deferred income tax assets (Note 16) 322 316 Employee post-retirement benefits (Note 23) 192 193 Fair value of derivative contracts (Note 24) 61 73 Other 295 306 1,921 1,484 |
NOTES PAYABLE (Tables)
NOTES PAYABLE (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Short-term Debt [Abstract] | |
Schedule of Notes Payable | 2018 2017 (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 Canada 2,117 2.5 % 884 1.6 % U.S. (2018 – US$448; 2017 – US$688) 611 3.1 % 862 2.2 % Mexico (2018 – US$25; 2017 – MXN$275) 34 3.3 % 17 8.0 % 2,762 1,763 |
Schedule of Credit Facilities | These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2018 2017 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 2023 3.0 3.0 3.0 TCPL/TCPL USA/Columbia/TAIL Supports TCPL, TCPL USA and TAIL's U.S. dollar commercial paper programs and is used for general corporate purposes of the borrowers, guaranteed by TCPL December 2019 US 4.5 US 4.5 — TCPL/TCPL USA/Columbia/TAIL Used for general corporate purposes of the borrowers, guaranteed by TCPL December 2021 US 1.0 US 1.0 — TCPL Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes — — US 2.0 TCPL USA Used for TCPL USA general corporate purposes, guaranteed by TCPL — — US 1.0 Columbia Used for Columbia general corporate purposes, guaranteed by TCPL — — US 1.0 TAIL Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL — — 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 2.1 1.0 1.9 Mexico subsidiary Used for Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 MXN 4.5 MXN 5.0 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, 2018, the Company was in compliance with all debt covenants. |
ACCOUNTS PAYABLE AND OTHER (Tab
ACCOUNTS PAYABLE AND OTHER (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Payables and Accruals [Abstract] | |
Schedule of Accounts Payable and Other | at December 31 2018 2017 (millions of Canadian $) Trade payables 3,224 2,847 Fair value of derivative contracts (Note 24) 922 387 Unredeemed shares of Columbia 357 312 Regulatory liabilities (Note 10) 591 263 Other 314 248 5,408 4,057 |
OTHER LONG-TERM LIABILITIES (Ta
OTHER LONG-TERM LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Deferred Costs, Noncurrent [Abstract] | |
Schedule of Other Long-Term Liabilities | at December 31 2018 2017 (millions of Canadian $) Employee post-retirement benefits (Note 23) 569 389 Asset retirement obligations 90 98 Fair value of derivative contracts (Note 24) 42 72 Guarantees (Note 27) 12 16 Other 295 152 1,008 727 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Provision for Income Taxes | year ended December 31 2018 2017 2016 (millions of Canadian $) Current Canada 65 113 116 Foreign 250 36 40 315 149 156 Deferred Canada 49 (185 ) 101 Foreign 235 751 95 Foreign – U.S. Tax Reform and 2018 FERC Actions (167 ) (804 ) — 117 (238 ) 196 Income Tax Expense/(Recovery) 432 (89 ) 352 |
Schedule of Geographic Components of Income | year ended December 31 2018 2017 2016 (millions of Canadian $) Canada 433 (339 ) 219 Foreign 3,516 3,645 618 Income before Income Taxes 3,949 3,306 837 |
Reconciliation of Income Tax Expense | year ended December 31 2018 2017 2016 (millions of Canadian $) Income before income taxes 3,949 3,306 837 Federal and provincial statutory tax rate 27 % 27 % 27 % Expected income tax expense 1,066 893 226 U.S. Tax Reform and 2018 FERC Actions (167 ) (804 ) — Foreign income tax rate differentials (432 ) (81 ) (196 ) Loss/(income) from equity investments and non-controlling interests 50 (64 ) (68 ) Income tax differential related to regulated operations (54 ) (42 ) 81 Non-taxable portion of capital gains (11 ) (42 ) — Asset impairment charges 1 — 34 242 Non-deductible amounts — 4 46 Other (20 ) 13 21 Income Tax Expense/(Recovery) 432 (89 ) 352 1 Net of nil (2017 – nil , 2016 – $112 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 2018 2017 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,238 1,379 Difference in accounting and tax bases of impaired assets and assets held for sale 574 651 Regulatory and other deferred amounts 858 512 Unrealized foreign exchange losses on long-term debt 491 216 Financial instruments — 10 Other 292 227 3,453 2,995 Less: valuation allowance 1,159 832 2,294 2,163 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 6,449 6,240 Equity investments 1,069 632 Taxes on future revenue requirement 300 238 Other 180 140 7,998 7,250 Net Deferred Income Tax Liabilities 5,704 5,087 The above deferred tax amounts have been classified in the Consolidated balance sheet as follows: at December 31 2018 2017 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 12) 322 316 Deferred Income Tax Liabilities Deferred income tax liabilities 6,026 5,403 Net Deferred Income Tax Liabilities 5,704 5,087 |
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 2018 2017 2016 (millions of Canadian $) Unrecognized tax benefit at beginning of year 15 18 17 Gross increases – tax positions in prior years 13 — 3 Gross decreases – tax positions in prior years (5 ) (1 ) — Gross increases – tax positions in current year — 2 2 Settlement — — (1 ) Lapse of statutes of limitations (4 ) (4 ) (3 ) Unrecognized Tax Benefit at End of Year 19 15 18 |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Long-Term Debt | The Company issued long-term debt over the three years ended December 31, 2018 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED October 2018 Senior Unsecured Notes March 2049 US 1,000 5.10 % October 2018 Senior Unsecured Notes May 2028 US 400 4.25 % 1 July 2018 Medium Term Notes July 2048 800 4.18 % July 2018 Medium Term Notes March 2028 200 3.39 % 2 May 2018 Senior Unsecured Notes May 2028 US 1,000 4.25 % May 2018 Senior Unsecured Notes May 2048 US 1,000 4.875 % May 2018 Senior Unsecured Notes May 2038 US 500 4.75 % 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 3 June 2018 US 5,213 Floating June 2016 Medium Term Notes July 2023 300 3.69 % 4 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 % NORTH BAJA PIPELINE, LLC December 2018 Unsecured Term Loan December 2021 US 50 Floating PORTLAND NATURAL GAS TRANSMISSION SYSTEM April 2018 Unsecured Loan Facility April 2023 US 19 Floating TUSCARORA GAS TRANSMISSION COMPANY August 2017 Unsecured Term Loan August 2020 US 25 Floating April 2016 Unsecured Term Loan April 2019 US 10 Floating TC PIPELINES, LP May 2017 Senior Unsecured Notes May 2027 US 500 3.90 % TRANSCANADA PIPELINE USA LTD. June 2016 Acquisition Bridge Facility 3 June 2018 US 1,700 Floating ANR PIPELINE COMPANY June 2016 Senior Unsecured Notes June 2026 US 240 4.14 % 1 Reflects coupon rate on re-opening of a pre-existing senior unsecured notes issue. The notes were issued at a discount to par, resulting in a re-issuance yield of 4.439 per cent . 2 Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at a discount to par, resulting in a re-issuance yield of 3.41 per cent . 3 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 second quarter 2017. 4 Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent . 2018 2017 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 2019 to 2020 350 11.4 % 500 10.8 % U.S. (2018 and 2017 – US$400) 2021 546 9.9 % 501 9.9 % Medium Term Notes Canadian 2019 to 2048 7,504 4.8 % 6,504 4.9 % Senior Unsecured Notes U.S. (2018 – US$17,192; 2017 – US$14,892) 2019 to 2049 23,456 5.1 % 18,644 5.1 % 31,856 26,149 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2018 and 2017 – US$200) 2023 273 7.9 % 250 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2018 and 2017 – US$33) 2026 44 7.5 % 41 7.5 % 921 895 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2018 – US$2,250; 2017 – US$2,750) 2 2020 to 2045 3,070 4.4 % 3,443 4.0 % TC PIPELINES, LP Unsecured Loan Facility U.S. (2018 – US$40; 2017 – US$185) 2021 55 3.8 % 232 2.7 % Unsecured Term Loan U.S. (2018 – US$500; 2017 – US$670) 3 2022 682 3.6 % 839 2.7 % Senior Unsecured Notes U.S. (2018 and 2017 – US$1,200) 2021 to 2027 1,637 4.4 % 1,502 4.4 % 2,374 2,573 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2018 and 2017 – US$672) 2021 to 2026 918 7.2 % 842 7.2 % GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2018 – US$35; 2017 – US$55) 2019 48 3.3 % 69 1.1 % Senior Unsecured Notes U.S. (2018 and 2017 – US$250) 2020 to 2035 341 5.6 % 313 5.6 % 389 382 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2018 – US$240; 2017 – US$259) 2021 to 2030 327 7.7 % 324 7.7 % 2018 2017 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 Unsecured Loan Facility U.S. (2018 – US$19; 2017 – nil) 2023 26 3.6 % — — Senior Secured Notes 4 U.S. (2018 – nil; 2017 – US$30) — — 38 6.0 % 26 38 TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2018 – US$24; 2017 – US$25) 2020 33 3.5 % 31 1.1 % NORTH BAJA PIPELINE, LLC Unsecured Term Loan U.S. (2018 – US$50; 2017 – nil) 2021 68 3.5 % — — 39,982 34,677 Current portion of long-term debt (3,462 ) (2,866 ) Unamortized debt discount and issue costs (241 ) (174 ) Fair value adjustments 5 230 238 36,509 31,875 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. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premium and discounts. 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$500 million term loan facility was amended in September 2017 to extend the maturity dates from 2018 to 2022. 4 These notes were secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements. 5 The fair value adjustments include $ 232 million (2017 – $ 242 million) related to the acquisition of Columbia. The fair value adjustments also include a decrease of $ 2 million (2017 – $ 4 million) related to hedged interest rate risk. Refer to Note 24, Risk management and financial instruments, for further information. |
Schedule of Repayments of Long-Term Debt | At December 31, 2018, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2019 2020 2021 2022 2023 Principal repayments on long-term debt 3,465 2,834 2,098 2,100 1,930 |
Schedule of Retired Long-Term Debt | The Company retired/repaid long-term debt over the three years ended December 31, 2018 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED August 2018 Senior Unsecured Notes US 850 6.50 % March 2018 Debentures 150 9.45 % January 2018 Senior Unsecured Notes US 500 1.875 % January 2018 Senior Unsecured Notes US 250 Floating 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 % TC PIPELINES, LP December 2018 Unsecured Term Loan US 170 Floating COLUMBIA PIPELINE GROUP, INC. June 2018 Senior Unsecured Notes US 500 2.45 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM May 2018 Senior Secured Notes US 18 5.90 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP March 2018 Senior Unsecured Notes US 9 6.73 % 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 % 1 These facilities were put in place to finance a portion of the Columbia acquisition and were fully retired in second quarter 2017. |
Schedule of Interest Expense | Interest expense in the three years ended December 31 was as follows: year ended December 31 2018 2017 2016 (millions of Canadian $) Interest on long-term debt 1,877 1,794 1,765 Interest on junior subordinated notes 391 348 180 Interest on short-term debt 73 33 18 Capitalized interest (124 ) (173 ) (176 ) Amortization and other financial charges 1 48 67 211 2,265 2,069 1,998 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. In 2016, this amount includes dividend equivalent payments of $109 million on the subscription receipts issued to partially fund the Columbia acquisition. Refer to Note 20, Common shares, for further information. |
JUNIOR SUBORDINATED NOTES (Tabl
JUNIOR SUBORDINATED NOTES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Junior Subordinated Notes [Abstract] | |
Schedule of Junior Subordinated Notes | 2018 2017 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate 1 Outstanding at December 31 Effective Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED 2 US$1,000 notes issued 2007 at 6.35% 3 2067 1,364 5.6 % 1,252 5.0 % US$750 notes issued 2015 at 5.875% 4,5 2075 1,024 6.5 % 939 5.9 % US$1,200 notes issued 2016 at 6.125% 4,5 2076 1,637 7.2 % 1,502 6.6 % US$1,500 notes issued 2017 at 5.55% 4,5 2077 2,047 6.2 % 1,878 5.6 % $1,500 notes issued 2017 at 4.90% 4,5 2077 1,500 5.5 % 1,500 5.1 % 7,572 7,071 Unamortized debt discount and issue costs (64 ) (64 ) 7,508 7,007 1 The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for loan fees and discounts. 2 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 3 In May 2017, Junior subordinated notes of US $1 billion converted from a 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 . 4 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 TransCanada'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. 5 The coupon rate is initially a fixed interest rate for the first ten years and converts to a floating rate thereafter. |
NON-CONTROLLING INTERESTS (Tabl
NON-CONTROLLING INTERESTS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 2018 2017 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,655 1,852 The Company's Net (loss)/income attributable to non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2018 2017 2016 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP (185 ) 220 215 Non-controlling interest in Portland Natural Gas Transmission System 1 — 9 20 Non-controlling interest in Columbia Pipeline Partners LP 2 — 9 17 (185 ) 238 252 1 Non-controlling interest in 2017 for the period January 1 to May 31 when TransCanada sold its remaining interest in Portland to TC PipeLines, LP. Refer to Note 26, Acquisitions and dispositions for further information. 2 Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of Columbia Pipeline Partners LP. |
COMMON SHARES (Tables)
COMMON SHARES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2016 702,614 12,102 Issued under public offerings 1 156,825 7,752 Dividend reinvestment and share purchase plan 2,942 177 Exercise of options 1,683 74 Repurchase of shares (305 ) (6 ) Outstanding at December 31, 2016 863,759 20,099 Dividend reinvestment and share purchase plan 12,824 790 At-the-market equity issuance program 1 3,462 216 Exercise of options 1,331 62 Outstanding at December 31, 2017 881,376 21,167 At-the-market equity issuance program 1 20,050 1,118 Dividend reinvestment and share purchase plan 15,937 855 Exercise of options 734 34 Outstanding at December 31, 2018 918,097 23,174 1 Net of issue costs and deferred income taxes. |
Schedule of Weighted Average Shares | Weighted Average Common Shares Outstanding (millions) 2018 2017 2016 Basic 902 872 759 Diluted 903 874 760 |
Schedule of Stock Options Activity | Number of (thousands) Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (years) Options outstanding at January 1, 2018 11,026 $51.38 Options granted 2,250 $56.89 Options exercised (734 ) $42.65 Options forfeited/expired (138 ) $57.23 Options Outstanding at December 31, 2018 12,404 $52.83 3.6 Options Exercisable at December 31, 2018 8,189 $50.72 2.6 |
Schedule of Options Valuation Assumptions | The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions: year ended December 31 2018 2017 2016 Weighted average fair value $5.80 $7.22 $5.67 Expected life (years) 1 5.7 5.7 5.8 Interest rate 2.1 % 1.2 % 0.7 % Volatility 2 16 % 18 % 21 % Dividend yield 4.2 % 3.6 % 4.9 % Forfeiture rate 3 — — 5 % 1 Expected life is based on historical exercise activity. 2 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. 3 On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance. |
Schedule of Additional Option Information | The following table summarizes additional stock option information: year ended December 31 2018 2017 2016 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 10 28 31 Fair value of options that have vested 101 140 126 Total options vested 2.1 million 2.3 million 2.1 million |
PREFERRED SHARES (Tables)
PREFERRED SHARES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |
Schedule of Preferred Shares | at December 31 Number of Shares Outstanding Current Yield Annual Dividend Per Share Redemption Price Per Share Redemption and Conversion Option Date Right to Convert Into 1,2 2018 2017 2016 (thousands) (millions of Canadian $) 3 Cumulative First Preferred Shares Series 1 9,498 3.266 % $0.8165 $25.00 December 31, 2019 Series 2 233 233 233 Series 2 12,502 Floating 4 Floating $25.00 December 31, 2019 Series 1 306 306 306 Series 3 8,533 2.152 % $0.538 $25.00 June 30, 2020 Series 4 209 209 209 Series 4 5,467 Floating 4 Floating $25.00 June 30, 2020 Series 3 134 134 134 Series 5 12,714 2.263 % $0.56575 $25.00 January 30, 2021 Series 6 310 310 310 Series 6 1,286 Floating 4 Floating $25.00 January 30, 2021 Series 5 32 32 32 Series 7 24,000 4.00 % $1.00 $25.00 April 30, 2019 Series 8 589 589 589 Series 9 18,000 4.25 % $1.0625 $25.00 October 30, 2019 Series 10 442 442 442 Series 11 10,000 3.80 % $0.95 $25.00 November 30, 2020 Series 12 244 244 244 Series 13 20,000 5.50 % $1.375 $25.00 May 31, 2021 Series 14 493 493 493 Series 15 40,000 4.90 % $1.225 $25.00 May 31, 2022 Series 16 988 988 988 Carrying value 3,980 3,980 3,980 1 Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90 -day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), 2.96 per cent (Series 12), 4.69 per cent (Series 14) and 3.85 per cent (Series 16). These rates reset quarterly with the then current T-Bill rate. 2 The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then five -year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), 2.96 per cent (Series 11), 4.69 per cent , subject to a minimum of 5.50 per cent (Series 13) and 3.85 per cent , subject to a minimum of 4.90 per cent (Series 15). 3 Net of underwriting commissions and deferred income taxes. 4 The floating quarterly dividend rate for the Series 2 preferred shares is 3.633 per cent and for the Series 4 preferred shares is 2.993 per cent for the period starting December 31, 2018 to, but excluding, March 29, 2019. The floating quarterly dividend rate for the Series 6 preferred shares is 3.086 per cent for the period starting October 30, 2018 to, but excluding, January 30, 2019. These rates will reset each quarter going forward. |
OTHER COMPREHENSIVE INCOME_(L_2
OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Equity [Abstract] | |
Components of Other Comprehensive Income/(Loss) | Components of OCI, including the portion attributable to non-controlling interests and related tax effects, are as follows: year ended December 31, 2018 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 1,323 35 1,358 Change in fair value of net investment hedges (57 ) 15 (42 ) Change in fair value of cash flow hedges (14 ) 4 (10 ) Reclassification to net income of gains and losses on cash flow hedges 27 (6 ) 21 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (153 ) 39 (114 ) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 20 (5 ) 15 Other comprehensive income on equity investments 113 (27 ) 86 Other Comprehensive Income 1,259 55 1,314 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 disposal of foreign operations (77 ) — (77 ) 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 ) |
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, 2016 (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 (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 ) Other comprehensive income/(loss) before reclassifications 2 1,150 (9 ) (114 ) 72 1,099 Amounts reclassified from AOCI 4,5 — 16 15 12 43 Net current period other comprehensive income/(loss) 1,150 7 (99 ) 84 1,142 Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform — 1 (12 ) (6 ) (17 ) AOCI balance at December 31, 2018 107 (23 ) (314 ) (376 ) (606 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 In 2018 , other comprehensive income before reclassifications on currency translation adjustments and cash flow hedges are net of non-controlling interest gains of $166 million ( 2017 – $159 million losses; 2016 – $14 million losses) and losses of $1 million ( 2017 – $4 million gains and 2016 – $3 million gains), 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 $15 million ( $11 million , net of tax) at December 31, 2018 . 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. 5 Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million and $2 million , respectively. |
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 Reclas s ified 1 Affected Line Item year ended December 31 2018 2017 2016 (millions of Canadian $) Cash flow hedges Commodities (4 ) 20 (57 ) Revenues (Energy) Interest (18 ) (17 ) (14 ) Interest expense (22 ) 3 (71 ) Total before tax 6 (1 ) 29 Income tax expense (16 ) 2 (42 ) Net of tax 1,3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial gains and losses (16 ) (15 ) (22 ) Plant operating costs and other 2 Settlement charge (4 ) (2 ) — Plant operating costs and other 2 (20 ) (17 ) (22 ) Total before tax 5 5 6 Income tax expense (15 ) (12 ) (16 ) Net of tax 1 Equity investments Equity income (16 ) (15 ) (19 ) Income from equity investments 4 4 5 Income tax expense (12 ) (11 ) (14 ) Net of tax 1,3 Currency translation adjustments Realization of foreign currency translation gains on disposal of foreign operations — 77 — Gain/(loss) on assets held for sale/sold — — — Income tax expense — 77 — Net of tax 1 1 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 23, Employee post-retirement benefits for further information. 3 Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million (2017 – nil , 2016 – nil ) and $2 million (2017 – nil , 2016 – nil ), respectively. |
EMPLOYEE POST-RETIREMENT BENE_2
EMPLOYEE POST-RETIREMENT BENEFITS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Retirement Benefits [Abstract] | |
Schedule of Contributions for Defined Benefit Plans | Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2018 2017 2016 (millions of Canadian $) DB Plans 103 163 111 Other post-retirement benefit plans 23 7 8 Savings and DC Plans 59 42 52 185 212 171 |
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 $) 2018 2017 2018 2017 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,646 3,456 375 372 Service cost 121 113 4 4 Interest cost 134 135 14 14 Employee contributions 5 5 — 3 Benefits paid (177 ) (166 ) (23 ) (19 ) Actuarial (gain)/loss (92 ) 253 43 19 Curtailment — (14 ) — (2 ) Settlement (71 ) (66 ) — — Foreign exchange rate changes 87 (70 ) 17 (16 ) Benefit obligation – end of year 3,653 3,646 430 375 Change in Plan Assets Plan assets at fair value – beginning of year 3,451 3,208 365 354 Actual return on plan assets (73 ) 358 (15 ) 45 Employer contributions 2 103 163 23 7 Employee contributions 5 5 — 3 Benefits paid (176 ) (166 ) (27 ) (19 ) Settlement (71 ) (57 ) — — Foreign exchange rate changes 82 (60 ) 30 (25 ) Plan assets at fair value – end of year 3,321 3,451 376 365 Funded Status – Plan Deficit (332 ) (195 ) (54 ) (10 ) 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 a $17 million letter of credit provided to the Canadian DB Plan for funding purposes ( 2017 – $27 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 $) 2018 2017 2018 2017 Intangible and other assets (Note 12) — — 192 193 Accounts payable and other (1 ) (1 ) (8 ) (8 ) Other long-term liabilities (Note 15) (331 ) (194 ) (238 ) (195 ) (332 ) (195 ) (54 ) (10 ) |
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 $) 2018 2017 2018 2017 Projected benefit obligation 1 (3,653 ) (3,646 ) (246 ) (203 ) Plan assets at fair value 3,321 3,451 — — Funded Status – Plan Deficit (332 ) (195 ) (246 ) (203 ) 1 The projected benefit obligation for the pension benefit plans differ 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 2018 2017 (millions of Canadian $) Accumulated benefit obligation (3,347 ) (3,372 ) Plan assets at fair value 3,321 3,451 Funded Status (26 ) 79 |
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 2018 2017 (millions of Canadian $) Accumulated benefit obligation (3,347 ) (944 ) Plan assets at fair value 3,321 925 Funded Status – Plan Deficit (26 ) (19 ) |
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 2018 2017 2018 Debt securities 33 % 30 % 25% to 45% Equity securities 56 % 64 % 40% to 70% Alternatives 11 % 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 $) 2018 2017 2018 2017 Debt securities 8 7 0.3 % 0.2 % Equity securities 7 3 0.2 % 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 24, Risk management and financial instruments. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 Asset Category Cash and Cash Equivalents 48 44 — 17 — — 48 61 1 2 Equity Securities: Canadian 355 410 138 151 — — 493 561 13 15 U.S. 460 543 116 354 — — 576 897 16 24 International 40 45 281 322 — — 321 367 9 10 Global 116 — 268 301 — — 384 301 10 8 Emerging 8 8 138 147 — — 146 155 4 4 Fixed Income Securities: Canadian Bonds: Federal — — 186 193 — — 186 193 5 5 Provincial — — 198 194 — — 198 194 5 5 Municipal — — 8 8 — — 8 8 1 — Corporate — — 112 122 — — 112 122 3 3 U.S. Bonds: Federal 350 — — 244 — — 350 244 9 6 State — — — 41 — — — 41 — 1 Municipal — — — 4 — — — 4 — — Corporate 145 — 51 234 — — 196 234 5 6 International: Government 6 — 4 4 — — 10 4 1 — Corporate 19 — 18 5 — — 37 5 1 — Mortgage backed 128 — — 73 — — 128 73 3 2 Other Investments: Real estate — — — — 196 140 196 140 5 4 Infrastructure — — — — 163 70 163 70 4 2 Private equity funds — — — — 3 6 3 6 1 — Funds held on deposit 142 136 — — — — 142 136 4 3 1,817 1,186 1,518 2,414 362 216 3,697 3,816 100 100 |
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, 2016 199 Purchases and sales 11 Realized and unrealized gains 6 Balance at December 31, 2017 216 Purchases and sales 127 Realized and unrealized gains 19 Balance at December 31, 2018 362 |
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 2019 190 24 2020 193 23 2021 198 23 2022 203 23 2023 207 23 2024 to 2028 1,081 114 |
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 2018 2017 2018 2017 Discount rate 3.90 % 3.60 % 4.10 % 3.70 % Rate of compensation increase 3.00 % 3.00 % — — |
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 2018 2017 2016 2018 2017 2016 Discount rate 3.60 % 3.95 % 4.20 % 3.70 % 4.15 % 4.30 % Expected long-term rate of return on plan assets 6.70 % 6.50 % 6.70 % 4.00 % 6.05 % 5.95 % Rate of compensation increase 3.00 % 1.20 % 0.80 % — — — |
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 25 (21 ) |
Schedule of Net Benefit Costs | The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2018 2017 2016 2018 2017 2016 Service cost 1 121 108 107 4 4 3 Other components of net benefit cost 1 Interest cost 134 122 127 14 14 13 Expected return on plan assets (221 ) (178 ) (175 ) (16 ) (21 ) (11 ) Amortization of actuarial loss 15 14 20 1 1 2 Amortization of regulatory asset 18 37 27 — 1 1 Amortization of transitional obligation related to regulated business — — — — — 2 Settlement charge – regulatory asset — 2 — — — — Settlement charge – AOCI 4 2 — — — — (50 ) (1 ) (1 ) (1 ) (5 ) 7 Net Benefit Cost Recognized 71 107 106 3 (1 ) 10 1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income. |
Schedule of the Pre-Tax Amounts Recognized in AOCI | Pre-tax amounts recognized in AOCI were as follows: 2018 2017 2016 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 364 53 273 11 270 21 |
Schedule of the Pre-Tax Amounts Recognized in OCI | Pre-tax amounts recognized in OCI were as follows: 2018 2017 2016 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 net income (15 ) (1 ) (18 ) (1 ) (20 ) (2 ) Curtailment — — (14 ) (2 ) — — Settlement (4 ) — (11 ) — — — Funded status adjustment 110 43 46 (7 ) 43 (5 ) 91 42 3 (10 ) 23 (7 ) |
RISK MANAGEMENT AND FINANCIAL_2
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Risk Management and Financial Instruments [Abstract] | |
Summary of Derivative Instruments | The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows: 2018 2017 at December 31 Fair 1,2 Notional Fair 1,2 Notional (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2019) 3 (43 ) US 300 (199 ) US 1,200 U.S. dollar foreign exchange options (maturing 2019 to 2020) (47 ) US 2,500 5 US 500 (90 ) US 2,800 (194 ) US 1,700 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2018 , Net income includes net realized gains of $2 million ( 2017 – gains of $4 million ) related to the interest component of cross-currency swap settlements which are reported within Interest expense. The maturity and notional amount 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, 2018 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 23,865 44 59 — — Sales 1 17,689 56 79 — — Millions of U.S. dollars — — — 3,862 1,650 Maturity dates 2019-2023 2019-2027 2019 2019 2019-2030 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. 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 — — — 2,931 2,300 Millions of Mexican pesos — — — 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 . The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2018 2017 (millions of Canadian $, unless otherwise noted) Notional amount 31,000 (US 22,700) 25,400 (US 20,200) Fair value 31,700 (US 23,200) 28,900 (US 23,100) |
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: 2018 2017 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Long-term debt, including current portion 1,2 (Note 17) (39,971 ) (42,284 ) (34,741 ) (40,180 ) Junior subordinated notes (Note 18) (7,508 ) (6,665 ) (7,007 ) (7,233 ) (47,479 ) (48,949 ) (41,748 ) (47,413 ) 1 Long-term debt is recorded at amortized cost, except for US$750 million ( 2017 – US$1.1 billion ) that is attributed to hedged risk and recorded at fair value. 2 Net income in 2018 included unrealized losses of $2 million ( 2017 – gains of $4 million ) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$750 million of long-term debt at December 31, 2018 ( 2017 – US$1.1 billion ). 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: 2018 2017 at December 31 LMCI Restricted Investments Other Restricted Investments 1 LMCI Restricted Investments Other Restricted Investments 1 (millions of Canadian $) Fair value of fixed income securities 2 Fixed income securities (maturing within 1 year) — 22 — 23 Fixed income securities (maturing within 1-5 years) — 110 — 107 Fixed income securities (maturing within 5-10 years) 140 — 14 — Fixed income securities (maturing after 10 years) 952 — 790 — 1,092 132 804 130 1 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. 2 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. The balance sheet classification of the fair value of derivative instruments as at December 31, 2018 is as follows: at December 31, 2018 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 — — 716 717 Foreign exchange — — 16 1 17 Interest rate 3 — — — 3 4 — 16 717 737 Intangible and other assets (Note 12) Commodities 2 1 — — 50 51 Foreign exchange — — 1 — 1 Interest rate 8 1 — — 9 9 1 1 50 61 Total Derivative Assets 13 1 17 767 798 Accounts payable and other (Note 14) Commodities 2 (4 ) — — (622 ) (626 ) Foreign exchange — — (105 ) (188 ) (293 ) Interest rate — (3 ) — — (3 ) (4 ) (3 ) (105 ) (810 ) (922 ) Other long-term liabilities (Note 15) Commodities 2 — — — (28 ) (28 ) Foreign exchange — — (2 ) — (2 ) Interest rate (11 ) (1 ) — — (12 ) (11 ) (1 ) (2 ) (28 ) (42 ) Total Derivative Liabilities (15 ) (4 ) (107 ) (838 ) (964 ) Total Derivatives (2 ) (3 ) (90 ) (71 ) (166 ) 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, 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. |
Unrealized Gain (Loss) on Investments | 2018 2017 2016 year ended December 31 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments LMCI restricted investments 1 Other restricted investments LMCI restricted investments 1 Other restricted investments Net unrealized gains/(losses) 11 — (3 ) 1 (28 ) (1 ) Net realized losses 2 (4 ) — (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 The realized gains and losses on the sale of LMCI restricted investment securities are determined using the average cost basis. |
Realized Gain (Loss) on Investments | 2018 2017 2016 year ended December 31 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments LMCI restricted investments 1 Other restricted investments LMCI restricted investments 1 Other restricted investments Net unrealized gains/(losses) 11 — (3 ) 1 (28 ) (1 ) Net realized losses 2 (4 ) — (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 The realized gains and losses on the sale of LMCI restricted investment securities are determined using the average cost basis. |
Derivative Instruments - Balance Sheet and Income Statement Information | Derivatives in fair value hedging relationships The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities: at December 31 Carrying amount Fair value hedging adjustments 1 (millions of Canadian $) 2018 2017 2018 2017 Current portion of long-term debt (748 ) (688 ) 3 1 Long-term debt (273 ) (685 ) — 4 (1,021 ) (1,373 ) 3 5 1 At December 31, 2018 and 2017, adjustments for discontinued hedging relationships included in these balances were nil . Effect of fair value and cash flow hedging relationships The following table details amounts presented on the Consolidated statement of income in which the effects of fair value or cash flow hedging relationships are recorded. year ended December 31 Revenues (Energy) Interest Expense (millions of Canadian $) 2018 2017 2016 2018 2017 2016 Total Amount Presented in the Consolidated Statement of Income 2,124 3,593 4,206 (2,265 ) (2,069 ) (1,998 ) Fair Value Hedges Interest rate contracts Hedged items — — — (71 ) (74 ) (74 ) Derivatives designated as hedging instruments — — — (4 ) 1 8 Cash Flow Hedges Reclassification of gains/(losses) on derivative instruments from AOCI to net income 1,2 Interest rate contracts — — — 22 17 14 Commodity contracts 5 (20 ) 57 — — — 1 Refer to Note 22, Other comprehensive income/(loss) and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests. 2 There are no amounts recognized in earnings that were excluded from effectiveness testing. The following summary does not include hedges of the net investment in foreign operations. year ended December 31 2018 2017 2016 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 2 28 62 123 Foreign exchange (248 ) 88 25 Interest rate — (1 ) — Amount of realized gains/(losses) in the year Commodities 351 (107 ) (204 ) Foreign exchange (24 ) 18 62 Interest rate — 1 — Derivative instruments in hedging relationships Amount of realized (losses)/gains in the year Commodities (1 ) 23 (167 ) Foreign exchange — 5 (101 ) Interest rate (1 ) 1 4 1 Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively. 2 In 2018 and 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 22) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: year ended December 31 2018 2017 2016 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI 1 Commodities (1 ) (1 ) 39 Interest rate (13 ) 4 5 (14 ) 3 44 1 No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI. |
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, 2018 : at December 31, 2018 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 768 (626 ) 142 Foreign exchange 18 (18 ) — Interest rate 12 (4 ) 8 798 (648 ) 150 Derivative – Liability Commodities (654 ) 626 (28 ) Foreign exchange (295 ) 18 (277 ) Interest rate (15 ) 4 (11 ) (964 ) 648 (316 ) 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, 2017 : at December 31, 2017 Gross Derivative Instruments 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. |
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, 2018 : at December 31, 2018 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 768 (626 ) 142 Foreign exchange 18 (18 ) — Interest rate 12 (4 ) 8 798 (648 ) 150 Derivative – Liability Commodities (654 ) 626 (28 ) Foreign exchange (295 ) 18 (277 ) Interest rate (15 ) 4 (11 ) (964 ) 648 (316 ) 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, 2017 : at December 31, 2017 Gross Derivative Instruments 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. |
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 2018 , are categorized as follows: at December 31, 2018 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 581 187 — 768 Foreign exchange — 18 — 18 Interest rate — 12 — 12 Derivative Instrument Liabilities: Commodities (555 ) (95 ) (4 ) (654 ) Foreign exchange — (295 ) — (295 ) Interest rate — (15 ) — (15 ) 26 (188 ) (4 ) (166 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2018 . 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 . |
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) 2018 2017 Balance at beginning of year (7 ) 16 Transfers out of Level III 5 (19 ) Total gains/(losses) included in Net income 8 (17 ) Settlements (9 ) 18 Sales — (5 ) Foreign exchange (1 ) — Balance at end of year 1 (4 ) (7 ) 1 Revenues include unrealized losses of $5 million attributed to derivatives in the Level III category that were still held at December 31, 2018 ( 2017 – unrealized losses of $7 million ). |
CHANGES IN OPERATING WORKING _2
CHANGES IN OPERATING WORKING CAPITAL (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
CHANGES IN OPERATING WORKING CAPITAL | |
Schedule of changes in operating working capital | year ended December 31 2018 2017 2016 (millions of Canadian $) Increase in Accounts receivable (69 ) (576 ) (482 ) Increase in Inventories (49 ) (38 ) (87 ) Decrease/(increase) in Assets held for sale — 14 (13 ) Decrease in Other current assets 45 189 328 (Decrease)/increase in Accounts payable and other (70 ) 151 424 Increase in Accrued interest 41 12 62 (Decrease)/increase in Liabilities related to assets held for sale — (25 ) 16 (Increase)/decrease in Operating Working Capital (102 ) (273 ) 248 |
ACQUISITIONS AND DISPOSITIONS (
ACQUISITIONS AND DISPOSITIONS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | 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 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 TransCanada. (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) 627 (820 ) Net Income/(Loss) Attributable to Common Shares 234 (971 ) |
COMMITMENTS, CONTINGENCIES AN_2
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 $) 2019 81 7 74 2020 78 7 71 2021 76 4 72 2022 69 3 66 2023 67 3 64 2024 and thereafter 390 8 382 761 32 729 |
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: 2018 2017 at December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas ranging to 2020 183 1 315 2 Bruce Power ranging to 2021 88 — 88 1 Other jointly owned entities ranging to 2059 104 11 104 13 375 12 507 16 1 TransCanada's share of the potential estimated current or contingent exposure. |
CORPORATE RESTRUCTURING COSTS (
CORPORATE RESTRUCTURING COSTS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2016 36 63 99 Restructuring charges 1 — 6 6 Accretion expense — 1 1 Cash payments (27 ) (17 ) (44 ) Restructuring liability as at December 31, 2017 9 53 62 Restructuring charges 1 — 42 42 Accretion expense — 1 1 Cash payments (9 ) (15 ) (24 ) Restructuring Liability as at December 31, 2018 — 81 81 1 At December 31, 2018, the Company recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million as a regulatory asset on the Consolidated balance sheet related to costs that are recoverable through regulatory and tolling structures in future periods (2017 – $3 million and $3 million , respectively). |
VARIABLE INTEREST ENTITIES (Tab
VARIABLE INTEREST ENTITIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 $) 2018 2017 ASSETS Current Assets Cash and cash equivalents 45 41 Accounts receivable 79 63 Inventories 24 23 Other 13 11 161 138 Plant, Property and Equipment 3,026 3,535 Equity Investments 965 917 Goodwill 453 490 Intangible and Other Assets 8 3 4,613 5,083 LIABILITIES Current Liabilities Accounts payable and other 88 137 Dividends payable — 1 Accrued interest 24 23 Current portion of long-term debt 79 88 191 249 Regulatory Liabilities 43 34 Other Long-Term Liabilities 3 3 Deferred Income Tax Liabilities 13 13 Long-Term Debt 3,125 3,244 3,375 3,543 |
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 $) 2018 2017 Balance sheet Equity investments 4,575 4,372 Off-balance sheet Potential exposure to guarantees 170 171 Maximum exposure to loss 4,745 4,543 |
DESCRIPTION OF TRANSCANADA'S _2
DESCRIPTION OF TRANSCANADA'S BUSINESS (Details) | 12 Months Ended |
Dec. 31, 2018plantsegmentmikmBcf | |
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 | 40,686 |
Investments of regulated natural gas pipelines (in miles) | mi | 25,281 |
U.S. Natural Gas Pipelines | |
Segment Reporting Information [Line Items] | |
Investments of regulated natural gas pipelines (in kilometers) | km | 50,199 |
Investments of regulated natural gas pipelines (in miles) | mi | 31,192 |
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 | 1,670 |
Investments of regulated natural gas pipelines (in miles) | mi | 1,038 |
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 | 10 |
Non-regulated natural gas storage facilities (in billion cubic feet) | Bcf | 118 |
ACCOUNTING POLICIES (Details)
ACCOUNTING POLICIES (Details) | 12 Months Ended |
Dec. 31, 2018 | |
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) | 7.00% |
Midstream | Pipeline | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 1.70% |
Midstream | Pipeline | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 2.50% |
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 ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Jan. 01, 2019 | Jan. 01, 2018 | |
Retained Earnings | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform | $ 17 | ||
Accounting Standards Update 2016-02 | Scenario, Forecast | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Right-of-use asset | $ 606 | ||
Operating lease liabilities | $ 600 | ||
Accounting Standards Update 2016-16 | Retained Earnings | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Cumulative-effect adjustment for adoption of new accounting pronouncement | $ 95 |
SEGMENTED INFORMATION (Details)
SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Segmented information | |||
Revenues | $ 13,679 | $ 13,449 | $ 12,547 |
Income from equity investments | 714 | 773 | 514 |
Plant operating costs and other | (3,591) | (3,906) | (3,861) |
Commodity purchases resold | (1,488) | (2,382) | (2,172) |
Property taxes | (569) | (569) | (555) |
Depreciation and amortization | (2,350) | (2,055) | (1,939) |
Goodwill and other asset impairment charges | (801) | (1,257) | (1,388) |
Gain/(loss) on assets held for sale/sold | 170 | 631 | (833) |
Segmented earnings/(losses) | 5,764 | 4,684 | 2,313 |
Interest expense | (2,265) | (2,069) | (1,998) |
Allowance for funds used during construction | 526 | 507 | 419 |
Interest income and other | (76) | 184 | 103 |
Income before Income Taxes | 3,949 | 3,306 | 837 |
Income tax recovery/(expense) | (432) | 89 | (352) |
Net Income | 3,517 | 3,395 | 485 |
Net income attributable to non-controlling interests | 185 | (238) | (252) |
Net Income Attributable to Controlling Interests | 3,702 | 3,157 | 233 |
Preferred share dividends | (163) | (160) | (109) |
Net Income Attributable to Common Shares | 3,539 | 2,997 | 124 |
Capital spending | |||
Capital expenditures | 9,418 | 7,383 | 5,007 |
Capital projects in development | 496 | 146 | 295 |
Contributions to equity investments | 1,015 | 1,681 | 765 |
Capital spending | 10,929 | 9,210 | 6,067 |
Assets | 98,920 | 86,101 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 66,503 | 57,277 | |
Canada | |||
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 23,226 | 21,632 | |
Canada – domestic | |||
Segmented information | |||
Revenues | 4,187 | 3,618 | 3,697 |
Canada – export | |||
Segmented information | |||
Revenues | 1,075 | 1,255 | 1,177 |
United States | |||
Segmented information | |||
Revenues | 7,798 | 8,006 | 7,295 |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 37,385 | 30,693 | |
Mexico | |||
Segmented information | |||
Revenues | 619 | 570 | 378 |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 5,892 | 4,952 | |
Corporate | |||
Segmented information | |||
Revenues | (218) | (51) | (56) |
Income from equity investments | 5 | 63 | 0 |
Plant operating costs and other | 159 | (51) | (64) |
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) | (54) | (39) | (120) |
Capital spending | |||
Capital expenditures | 45 | 41 | 33 |
Capital projects in development | 0 | 0 | 0 |
Contributions to equity investments | 0 | 0 | 0 |
Capital spending | 45 | 41 | 33 |
Assets | 3,513 | 3,642 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 238 | 243 | |
Canadian Natural Gas Pipelines | |||
Segmented information | |||
Revenues | 4,038 | 3,693 | 3,682 |
Canadian Natural Gas Pipelines | Operating segments | |||
Segmented information | |||
Revenues | 4,038 | 3,693 | 3,682 |
Income from equity investments | 12 | 11 | 12 |
Plant operating costs and other | (1,405) | (1,300) | (1,245) |
Commodity purchases resold | 0 | 0 | 0 |
Property taxes | (266) | (260) | (267) |
Depreciation and amortization | (1,129) | (908) | (875) |
Goodwill and other asset impairment charges | 0 | 0 | 0 |
Gain/(loss) on assets held for sale/sold | 0 | 0 | 0 |
Segmented earnings/(losses) | 1,250 | 1,236 | 1,307 |
Capital spending | |||
Capital expenditures | 2,442 | 2,106 | 1,372 |
Capital projects in development | 36 | 75 | 153 |
Contributions to equity investments | 0 | 0 | 0 |
Capital spending | 2,478 | 2,181 | 1,525 |
Assets | 18,407 | 16,904 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 16,013 | 14,424 | |
Canadian Natural Gas Pipelines | Intersegment eliminations | |||
Segmented information | |||
Revenues | 0 | 0 | 0 |
U.S. Natural Gas Pipelines | |||
Segmented information | |||
Revenues | 4,314 | 3,584 | 2,526 |
U.S. Natural Gas Pipelines | Operating segments | |||
Segmented information | |||
Revenues | 4,476 | 3,635 | 2,582 |
Income from equity investments | 256 | 240 | 214 |
Plant operating costs and other | (1,368) | (1,340) | (1,057) |
Commodity purchases resold | 0 | 0 | 0 |
Property taxes | (199) | (181) | (120) |
Depreciation and amortization | (664) | (594) | (425) |
Goodwill and other asset impairment charges | (801) | 0 | 0 |
Gain/(loss) on assets held for sale/sold | 0 | 0 | (4) |
Segmented earnings/(losses) | 1,700 | 1,760 | 1,190 |
Capital spending | |||
Capital expenditures | 5,591 | 3,712 | 1,517 |
Capital projects in development | 1 | 0 | 0 |
Contributions to equity investments | 179 | 118 | 5 |
Capital spending | 5,771 | 3,830 | 1,522 |
Assets | 44,115 | 35,898 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 26,990 | 20,262 | |
U.S. Natural Gas Pipelines | Intersegment eliminations | |||
Segmented information | |||
Revenues | 162 | 51 | 56 |
Mexico Natural Gas Pipelines | |||
Segmented information | |||
Revenues | 619 | 570 | 378 |
Mexico Natural Gas Pipelines | Operating segments | |||
Segmented information | |||
Revenues | 619 | 570 | 378 |
Income from equity investments | 22 | (9) | (3) |
Plant operating costs and other | (34) | (42) | (43) |
Commodity purchases resold | 0 | 0 | 0 |
Property taxes | 0 | 0 | 0 |
Depreciation and amortization | (97) | (93) | (45) |
Goodwill and other asset impairment charges | 0 | 0 | 0 |
Gain/(loss) on assets held for sale/sold | 0 | 0 | 0 |
Segmented earnings/(losses) | 510 | 426 | 287 |
Capital spending | |||
Capital expenditures | 463 | 833 | 944 |
Capital projects in development | 0 | 0 | 0 |
Contributions to equity investments | 334 | 1,121 | 198 |
Capital spending | 797 | 1,954 | 1,142 |
Assets | 7,058 | 5,716 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 5,875 | 4,952 | |
Mexico Natural Gas Pipelines | Intersegment eliminations | |||
Segmented information | |||
Revenues | 0 | 0 | 0 |
Liquids Pipelines | |||
Segmented information | |||
Revenues | 2,584 | 2,009 | 1,755 |
Liquids Pipelines | Operating segments | |||
Segmented information | |||
Revenues | 2,584 | 2,009 | 1,755 |
Income from equity investments | 64 | (3) | (1) |
Plant operating costs and other | (630) | (623) | (568) |
Commodity purchases resold | 0 | 0 | 0 |
Property taxes | (98) | (89) | (88) |
Depreciation and amortization | (341) | (309) | (292) |
Goodwill and other asset impairment charges | 0 | (1,236) | 0 |
Gain/(loss) on assets held for sale/sold | 0 | 0 | 0 |
Segmented earnings/(losses) | 1,579 | (251) | 806 |
Capital spending | |||
Capital expenditures | 110 | 341 | 668 |
Capital projects in development | 459 | 71 | 142 |
Contributions to equity investments | 12 | 117 | 327 |
Capital spending | 581 | 529 | 1,137 |
Assets | 17,352 | 15,438 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 13,726 | 13,419 | |
Liquids Pipelines | Intersegment eliminations | |||
Segmented information | |||
Revenues | 0 | 0 | 0 |
Energy | |||
Segmented information | |||
Revenues | 2,124 | 3,593 | 4,206 |
Energy | Operating segments | |||
Segmented information | |||
Revenues | 2,180 | 3,593 | 4,206 |
Income from equity investments | 355 | 471 | 292 |
Plant operating costs and other | (313) | (550) | (884) |
Commodity purchases resold | (1,488) | (2,382) | (2,172) |
Property taxes | (6) | (39) | (80) |
Depreciation and amortization | (119) | (151) | (302) |
Goodwill and other asset impairment charges | 0 | (21) | (1,388) |
Gain/(loss) on assets held for sale/sold | 170 | 631 | (829) |
Segmented earnings/(losses) | 779 | 1,552 | (1,157) |
Capital spending | |||
Capital expenditures | 767 | 350 | 473 |
Capital projects in development | 0 | 0 | 0 |
Contributions to equity investments | 490 | 325 | 235 |
Capital spending | 1,257 | 675 | 708 |
Assets | 8,475 | 8,503 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment | 3,661 | 3,977 | |
Energy | Intersegment eliminations | |||
Segmented information | |||
Revenues | $ 56 | $ 0 | $ 0 |
REVENUES - Disaggregation of Re
REVENUES - Disaggregation of Revenues (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | $ 12,794 | ||
Other revenues | 885 | ||
Revenues | 13,679 | $ 13,449 | $ 12,547 |
Capacity arrangements and transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 10,280 | ||
Power generation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 1,771 | ||
Natural gas storage and other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 743 | ||
Canadian Natural Gas Pipelines | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 4,038 | ||
Other revenues | 0 | ||
Revenues | 4,038 | 3,693 | 3,682 |
Canadian Natural Gas Pipelines | Capacity arrangements and transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 4,038 | ||
Canadian Natural Gas Pipelines | Power generation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 0 | ||
Canadian Natural Gas Pipelines | Natural gas storage and other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 0 | ||
U.S. Natural Gas Pipelines | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 4,203 | ||
Other revenues | 111 | ||
Revenues | 4,314 | 3,584 | 2,526 |
U.S. Natural Gas Pipelines | Capacity arrangements and transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 3,549 | ||
U.S. Natural Gas Pipelines | Power generation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 0 | ||
U.S. Natural Gas Pipelines | Natural gas storage and other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 654 | ||
Mexico Natural Gas Pipelines | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 619 | ||
Other revenues | 0 | ||
Revenues | 619 | 570 | 378 |
Mexico Natural Gas Pipelines | Capacity arrangements and transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 614 | ||
Mexico Natural Gas Pipelines | Power generation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 0 | ||
Mexico Natural Gas Pipelines | Natural gas storage and other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 5 | ||
Liquids Pipelines | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 2,082 | ||
Other revenues | 502 | ||
Revenues | 2,584 | 2,009 | 1,755 |
Liquids Pipelines | Capacity arrangements and transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 2,079 | ||
Liquids Pipelines | Power generation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 0 | ||
Liquids Pipelines | Natural gas storage and other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 3 | ||
Energy | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 1,852 | ||
Other revenues | 272 | ||
Revenues | 2,124 | $ 3,593 | $ 4,206 |
Energy | Capacity arrangements and transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 0 | ||
Energy | Power generation | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 1,771 | ||
Energy | Natural gas storage and other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | $ 81 |
REVENUES - Impact of New Revenu
REVENUES - Impact of New Revenue Guidance (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Jan. 01, 2018 | Dec. 31, 2017 |
Current Assets | |||
Accounts receivable | $ 2,535 | $ 2,460 | $ 2,522 |
Other | 1,180 | 770 | 691 |
Current Liabilities | |||
Accounts payable and other | 5,408 | 4,074 | 4,057 |
Calculated under Revenue Guidance in Effect before Topic 606 | |||
Current Assets | |||
Accounts receivable | 2,694 | ||
Other | $ 1,021 | ||
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | |||
Current Assets | |||
Accounts receivable | 2,522 | ||
Other | 691 | ||
Current Liabilities | |||
Accounts payable and other | $ 4,057 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09 | |||
Current Assets | |||
Accounts receivable | (62) | ||
Other | 79 | ||
Current Liabilities | |||
Accounts payable and other | $ 17 |
REVENUES - Contract Balances (D
REVENUES - Contract Balances (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Jan. 01, 2018 | |
Revenue from Contract with Customer [Abstract] | ||
Receivables from contracts with customers | $ 1,684 | $ 1,736 |
Contract assets | 159 | 79 |
Long-term contract assets | 21 | 0 |
Contract liabilities | 11 | 17 |
Long-term contract liabilities | 121 | $ 0 |
Revenue recognized | $ 17 |
REVENUES - Remaining Performanc
REVENUES - Remaining Performance Obligations - Narrative (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018CAD ($) | |
Long-term pipeline capacity arrangements and transportation contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Future revenues, remaining performance obligation | $ 6,000 |
Future revenues, expected timing of satisfaction, period | 1 year |
Long-term pipeline capacity arrangements and transportation contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Future revenues, remaining performance obligation | $ 30,100 |
Natural gas storage and other | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Future revenues, remaining performance obligation | $ 283 |
Future revenues, expected timing of satisfaction, period | 1 year |
Natural gas storage and other | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Future revenues, remaining performance obligation | $ 1,200 |
REVENUES - Additional Informati
REVENUES - Additional Information - Narrative (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Rate-regulated firm capacity contracts | |
Disaggregation of Revenue [Line Items] | |
Future revenues, expected timing of satisfaction, explanation | one to three years |
ASSETS HELD FOR SALE - Narrativ
ASSETS HELD FOR SALE - Narrative (Details) $ in Millions, $ in Millions | Jun. 30, 2019CAD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 14, 2018USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Gain on sale | $ 170 | $ 631 | $ (833) | ||
Coolidge generating station | Disposal group, not discontinued operations | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Sale consideration | $ 465 | ||||
Coolidge generating station | Disposal group, not discontinued operations | Scenario, Forecast | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Gain on sale | $ 65 | ||||
Gain on sale, net of tax | 50 | ||||
Foreign currency translation gains | $ 10 |
ASSETS HELD FOR SALE - Assets a
ASSETS HELD FOR SALE - Assets and Liabilities Classified as Held for Sale (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Assets held for sale | ||
Total assets held for sale | $ 543 | $ 0 |
Coolidge generating station | Disposal group, not discontinued operations | ||
Assets held for sale | ||
Accounts receivable | 6 | |
Plant, property and equipment | 537 | |
Total assets held for sale | 543 | |
Liabilities related to assets held for sale | ||
Other long-term liabilities | (3) | |
Total liabilities related to assets held for sale | $ (3) |
OTHER CURRENT ASSETS (Details)
OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Jan. 01, 2018 | Dec. 31, 2017 |
Other Assets [Abstract] | |||
Fair value of derivative contracts (Note 24) | $ 737 | $ 332 | |
Contract assets (Note 5) | 159 | $ 79 | |
Regulatory assets (Note 10) | 83 | 23 | |
Cash provided as collateral | 55 | 99 | |
Prepaid expenses | 41 | 109 | |
Other | 105 | 128 | |
Other current assets, total | $ 1,180 | $ 770 | $ 691 |
PLANT, PROPERTY AND EQUIPMENT_2
PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Oct. 05, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Plant, property and equipment | ||||||
Cost | $ 92,337 | $ 81,011 | $ 92,337 | $ 81,011 | ||
Accumulated Depreciation | 25,834 | 23,734 | 25,834 | 23,734 | ||
Net Book Value | 66,503 | 57,277 | 66,503 | 57,277 | ||
Revenues | 12,794 | |||||
Energy East, Eastern Mainline and Upland projects | ||||||
Plant, property and equipment | ||||||
Impairment charge | $ 83 | |||||
Impairment charge, net of tax | $ 64 | |||||
Power development project | ||||||
Plant, property and equipment | ||||||
Impairment charge | 21 | |||||
Impairment charge, net of tax | 16 | |||||
Bison | ||||||
Plant, property and equipment | ||||||
Impairment charge | 722 | |||||
Impairment charge, net of tax and noncontrolling interest | 140 | |||||
Gain on contract termination | 130 | |||||
Gain on contract termination, net of tax and noncontrolling interest | 25 | |||||
Canadian Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Revenues | 4,038 | |||||
Canadian Natural Gas Pipelines | Under construction | NGTL System | ||||||
Plant, property and equipment | ||||||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
U.S. Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Revenues | 4,203 | |||||
Mexico Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Revenues | 619 | |||||
Liquids Pipelines | ||||||
Plant, property and equipment | ||||||
Revenues | 2,082 | |||||
Liquids Pipelines | Tanks and other, operating leases | Keystone Pipeline System | ||||||
Plant, property and equipment | ||||||
Cost | 194 | 184 | 194 | 184 | ||
Accumulated Depreciation | 23 | 19 | 23 | 19 | ||
Operating lease income | 15 | 16 | $ 16 | |||
Liquids Pipelines | Pipelines, operating leases | Northern Courier | ||||||
Plant, property and equipment | ||||||
Cost | 1,130 | 1,111 | 1,130 | 1,111 | ||
Accumulated Depreciation | 32 | 4 | 32 | 4 | ||
Operating lease income | 142 | 20 | ||||
Energy | ||||||
Plant, property and equipment | ||||||
Revenues | 1,852 | |||||
Energy | Facilities under PPAs | ||||||
Plant, property and equipment | ||||||
Cost | 655 | 1,264 | 655 | 1,264 | ||
Accumulated Depreciation | 268 | 354 | 268 | 354 | ||
Revenues | 216 | 215 | $ 212 | |||
Operating segments | Canadian Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 33,897 | 31,300 | 33,897 | 31,300 | ||
Accumulated Depreciation | 17,884 | 16,876 | 17,884 | 16,876 | ||
Net Book Value | 16,013 | 14,424 | 16,013 | 14,424 | ||
Operating segments | Canadian Natural Gas Pipelines | NGTL System | ||||||
Plant, property and equipment | ||||||
Cost | 17,411 | 15,302 | 17,411 | 15,302 | ||
Accumulated Depreciation | 6,790 | 6,352 | 6,790 | 6,352 | ||
Net Book Value | 10,621 | 8,950 | 10,621 | 8,950 | ||
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | ||||||
Plant, property and equipment | ||||||
Cost | 14,520 | 14,179 | 14,520 | 14,179 | ||
Accumulated Depreciation | 9,674 | 9,161 | 9,674 | 9,161 | ||
Net Book Value | 4,846 | 5,018 | 4,846 | 5,018 | ||
Operating segments | Canadian Natural Gas Pipelines | Other | ||||||
Plant, property and equipment | ||||||
Cost | 1,842 | 1,815 | 1,842 | 1,815 | ||
Accumulated Depreciation | 1,420 | 1,363 | 1,420 | 1,363 | ||
Net Book Value | 422 | 452 | 422 | 452 | ||
Operating segments | Canadian Natural Gas Pipelines | Other Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 1,966 | 1,819 | 1,966 | 1,819 | ||
Accumulated Depreciation | 1,420 | 1,363 | 1,420 | 1,363 | ||
Net Book Value | 546 | 456 | 546 | 456 | ||
Operating segments | Canadian Natural Gas Pipelines | Pipeline | NGTL System | ||||||
Plant, property and equipment | ||||||
Cost | 10,764 | 10,153 | 10,764 | 10,153 | ||
Accumulated Depreciation | 4,500 | 4,190 | 4,500 | 4,190 | ||
Net Book Value | 6,264 | 5,963 | 6,264 | 5,963 | ||
Operating segments | Canadian Natural Gas Pipelines | Pipeline | Canadian Mainline | ||||||
Plant, property and equipment | ||||||
Cost | 10,077 | 9,763 | 10,077 | 9,763 | ||
Accumulated Depreciation | 6,777 | 6,455 | 6,777 | 6,455 | ||
Net Book Value | 3,300 | 3,308 | 3,300 | 3,308 | ||
Operating segments | Canadian Natural Gas Pipelines | Compression | NGTL System | ||||||
Plant, property and equipment | ||||||
Cost | 3,289 | 3,021 | 3,289 | 3,021 | ||
Accumulated Depreciation | 1,677 | 1,593 | 1,677 | 1,593 | ||
Net Book Value | 1,612 | 1,428 | 1,612 | 1,428 | ||
Operating segments | Canadian Natural Gas Pipelines | Compression | Canadian Mainline | ||||||
Plant, property and equipment | ||||||
Cost | 3,642 | 3,605 | 3,642 | 3,605 | ||
Accumulated Depreciation | 2,656 | 2,499 | 2,656 | 2,499 | ||
Net Book Value | 986 | 1,106 | 986 | 1,106 | ||
Operating segments | Canadian Natural Gas Pipelines | Metering and other | NGTL System | ||||||
Plant, property and equipment | ||||||
Cost | 1,247 | 1,188 | 1,247 | 1,188 | ||
Accumulated Depreciation | 613 | 569 | 613 | 569 | ||
Net Book Value | 634 | 619 | 634 | 619 | ||
Operating segments | Canadian Natural Gas Pipelines | Metering and other | Canadian Mainline | ||||||
Plant, property and equipment | ||||||
Cost | 652 | 655 | 652 | 655 | ||
Accumulated Depreciation | 241 | 207 | 241 | 207 | ||
Net Book Value | 411 | 448 | 411 | 448 | ||
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | NGTL System | ||||||
Plant, property and equipment | ||||||
Cost | 15,300 | 14,362 | 15,300 | 14,362 | ||
Accumulated Depreciation | 6,790 | 6,352 | 6,790 | 6,352 | ||
Net Book Value | 8,510 | 8,010 | 8,510 | 8,010 | ||
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | Canadian Mainline | ||||||
Plant, property and equipment | ||||||
Cost | 14,371 | 14,023 | 14,371 | 14,023 | ||
Accumulated Depreciation | 9,674 | 9,161 | 9,674 | 9,161 | ||
Net Book Value | 4,697 | 4,862 | 4,697 | 4,862 | ||
Operating segments | Canadian Natural Gas Pipelines | Under construction | NGTL System | ||||||
Plant, property and equipment | ||||||
Cost | 2,111 | 940 | 2,111 | 940 | ||
Net Book Value | 2,111 | 940 | 2,111 | 940 | ||
Operating segments | Canadian Natural Gas Pipelines | Under construction | Canadian Mainline | ||||||
Plant, property and equipment | ||||||
Cost | 149 | 156 | 149 | 156 | ||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
Net Book Value | 149 | 156 | 149 | 156 | ||
Operating segments | Canadian Natural Gas Pipelines | Under construction | Other Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 124 | 4 | 124 | 4 | ||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
Net Book Value | 124 | 4 | 124 | 4 | ||
Operating segments | U.S. Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 31,444 | 24,007 | 31,444 | 24,007 | ||
Accumulated Depreciation | 4,454 | 3,745 | 4,454 | 3,745 | ||
Net Book Value | 26,990 | 20,262 | 26,990 | 20,262 | ||
Operating segments | U.S. Natural Gas Pipelines | Other Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 9,503 | 8,944 | 9,503 | 8,944 | ||
Accumulated Depreciation | 2,841 | 2,600 | 2,841 | 2,600 | ||
Net Book Value | 6,662 | 6,344 | 6,662 | 6,344 | ||
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | ||||||
Plant, property and equipment | ||||||
Cost | 16,874 | 10,735 | 16,874 | 10,735 | ||
Accumulated Depreciation | 458 | 226 | 458 | 226 | ||
Net Book Value | 16,416 | 10,509 | 16,416 | 10,509 | ||
Operating segments | U.S. Natural Gas Pipelines | ANR | ||||||
Plant, property and equipment | ||||||
Cost | 5,067 | 4,328 | 5,067 | 4,328 | ||
Accumulated Depreciation | 1,155 | 919 | 1,155 | 919 | ||
Net Book Value | 3,912 | 3,409 | 3,912 | 3,409 | ||
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Other | ||||||
Plant, property and equipment | ||||||
Cost | 1,190 | 1,950 | 1,190 | 1,950 | ||
Accumulated Depreciation | 474 | 574 | 474 | 574 | ||
Net Book Value | 716 | 1,376 | 716 | 1,376 | ||
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gas | ||||||
Plant, property and equipment | ||||||
Cost | 6,711 | 3,550 | 6,711 | 3,550 | ||
Accumulated Depreciation | 251 | 125 | 251 | 125 | ||
Net Book Value | 6,460 | 3,425 | 6,460 | 3,425 | ||
Operating segments | U.S. Natural Gas Pipelines | Pipeline | ANR | ||||||
Plant, property and equipment | ||||||
Cost | 1,600 | 1,427 | 1,600 | 1,427 | ||
Accumulated Depreciation | 443 | 365 | 443 | 365 | ||
Net Book Value | 1,157 | 1,062 | 1,157 | 1,062 | ||
Operating segments | U.S. Natural Gas Pipelines | Pipeline | GTN | ||||||
Plant, property and equipment | ||||||
Cost | 2,322 | 2,107 | 2,322 | 2,107 | ||
Accumulated Depreciation | 951 | 822 | 951 | 822 | ||
Net Book Value | 1,371 | 1,285 | 1,371 | 1,285 | ||
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Great Lakes | ||||||
Plant, property and equipment | ||||||
Cost | 2,180 | 1,988 | 2,180 | 1,988 | ||
Accumulated Depreciation | 1,251 | 1,113 | 1,251 | 1,113 | ||
Net Book Value | 929 | 875 | 929 | 875 | ||
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gulf | ||||||
Plant, property and equipment | ||||||
Cost | 1,753 | 1,115 | 1,753 | 1,115 | ||
Accumulated Depreciation | 74 | 37 | 74 | 37 | ||
Net Book Value | 1,679 | 1,078 | 1,679 | 1,078 | ||
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Midstream | ||||||
Plant, property and equipment | ||||||
Cost | 1,212 | 1,085 | 1,212 | 1,085 | ||
Accumulated Depreciation | 91 | 54 | 91 | 54 | ||
Net Book Value | 1,121 | 1,031 | 1,121 | 1,031 | ||
Operating segments | U.S. Natural Gas Pipelines | Compression | Columbia Gas | ||||||
Plant, property and equipment | ||||||
Cost | 2,932 | 1,547 | 2,932 | 1,547 | ||
Accumulated Depreciation | 132 | 64 | 132 | 64 | ||
Net Book Value | 2,800 | 1,483 | 2,800 | 1,483 | ||
Operating segments | U.S. Natural Gas Pipelines | Compression | ANR | ||||||
Plant, property and equipment | ||||||
Cost | 1,978 | 1,582 | 1,978 | 1,582 | ||
Accumulated Depreciation | 388 | 286 | 388 | 286 | ||
Net Book Value | 1,590 | 1,296 | 1,590 | 1,296 | ||
Operating segments | U.S. Natural Gas Pipelines | Metering and other | Columbia Gas | ||||||
Plant, property and equipment | ||||||
Cost | 2,884 | 2,306 | 2,884 | 2,306 | ||
Accumulated Depreciation | 75 | 37 | 75 | 37 | ||
Net Book Value | 2,809 | 2,269 | 2,809 | 2,269 | ||
Operating segments | U.S. Natural Gas Pipelines | Metering and other | ANR | ||||||
Plant, property and equipment | ||||||
Cost | 1,217 | 961 | 1,217 | 961 | ||
Accumulated Depreciation | 324 | 268 | 324 | 268 | ||
Net Book Value | 893 | 693 | 893 | 693 | ||
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | Other Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 8,657 | 8,245 | 8,657 | 8,245 | ||
Accumulated Depreciation | 2,841 | 2,600 | 2,841 | 2,600 | ||
Net Book Value | 5,816 | 5,645 | 5,816 | 5,645 | ||
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | Columbia Gas | ||||||
Plant, property and equipment | ||||||
Cost | 12,527 | 7,403 | 12,527 | 7,403 | ||
Accumulated Depreciation | 458 | 226 | 458 | 226 | ||
Net Book Value | 12,069 | 7,177 | 12,069 | 7,177 | ||
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | ANR | ||||||
Plant, property and equipment | ||||||
Cost | 4,795 | 3,970 | 4,795 | 3,970 | ||
Accumulated Depreciation | 1,155 | 919 | 1,155 | 919 | ||
Net Book Value | 3,640 | 3,051 | 3,640 | 3,051 | ||
Operating segments | U.S. Natural Gas Pipelines | Under construction | ||||||
Plant, property and equipment | ||||||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
Operating segments | U.S. Natural Gas Pipelines | Under construction | Other Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 846 | 699 | 846 | 699 | ||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
Net Book Value | 846 | 699 | 846 | 699 | ||
Operating segments | U.S. Natural Gas Pipelines | Under construction | Columbia Gas | ||||||
Plant, property and equipment | ||||||
Cost | 4,347 | 3,332 | 4,347 | 3,332 | ||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
Net Book Value | 4,347 | 3,332 | 4,347 | 3,332 | ||
Operating segments | U.S. Natural Gas Pipelines | Under construction | ANR | ||||||
Plant, property and equipment | ||||||
Cost | 272 | 358 | 272 | 358 | ||
Net Book Value | 272 | 358 | 272 | 358 | ||
Operating segments | Mexico Natural Gas Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 6,308 | 5,261 | 6,308 | 5,261 | ||
Accumulated Depreciation | 433 | 309 | 433 | 309 | ||
Net Book Value | 5,875 | 4,952 | 5,875 | 4,952 | ||
Operating segments | Mexico Natural Gas Pipelines | Pipeline | ||||||
Plant, property and equipment | ||||||
Cost | 3,172 | 2,872 | 3,172 | 2,872 | ||
Accumulated Depreciation | 301 | 214 | 301 | 214 | ||
Net Book Value | 2,871 | 2,658 | 2,871 | 2,658 | ||
Operating segments | Mexico Natural Gas Pipelines | Compression | ||||||
Plant, property and equipment | ||||||
Cost | 506 | 448 | 506 | 448 | ||
Accumulated Depreciation | 41 | 30 | 41 | 30 | ||
Net Book Value | 465 | 418 | 465 | 418 | ||
Operating segments | Mexico Natural Gas Pipelines | Metering and other | ||||||
Plant, property and equipment | ||||||
Cost | 640 | 573 | 640 | 573 | ||
Accumulated Depreciation | 91 | 65 | 91 | 65 | ||
Net Book Value | 549 | 508 | 549 | 508 | ||
Operating segments | Mexico Natural Gas Pipelines | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 4,318 | 3,893 | 4,318 | 3,893 | ||
Accumulated Depreciation | 433 | 309 | 433 | 309 | ||
Net Book Value | 3,885 | 3,584 | 3,885 | 3,584 | ||
Operating segments | Mexico Natural Gas Pipelines | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 1,990 | 1,368 | 1,990 | 1,368 | ||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
Net Book Value | 1,990 | 1,368 | 1,990 | 1,368 | ||
Operating segments | Liquids Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 15,702 | 14,952 | 15,702 | 14,952 | ||
Accumulated Depreciation | 1,976 | 1,533 | 1,976 | 1,533 | ||
Net Book Value | 13,726 | 13,419 | 13,726 | 13,419 | ||
Operating segments | Liquids Pipelines | Keystone Pipeline System | ||||||
Plant, property and equipment | ||||||
Cost | 14,461 | 13,794 | 14,461 | 13,794 | ||
Accumulated Depreciation | 1,943 | 1,529 | 1,943 | 1,529 | ||
Net Book Value | 12,518 | 12,265 | 12,518 | 12,265 | ||
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 1,241 | 1,158 | 1,241 | 1,158 | ||
Accumulated Depreciation | 33 | 4 | 33 | 4 | ||
Net Book Value | 1,208 | 1,154 | 1,208 | 1,154 | ||
Operating segments | Liquids Pipelines | Pipeline | Keystone Pipeline System | ||||||
Plant, property and equipment | ||||||
Cost | 9,780 | 9,002 | 9,780 | 9,002 | ||
Accumulated Depreciation | 1,271 | 992 | 1,271 | 992 | ||
Net Book Value | 8,509 | 8,010 | 8,509 | 8,010 | ||
Operating segments | Liquids Pipelines | Pipeline | Intra-Alberta Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 762 | 748 | 762 | 748 | ||
Accumulated Depreciation | 22 | 3 | 22 | 3 | ||
Net Book Value | 740 | 745 | 740 | 745 | ||
Operating segments | Liquids Pipelines | Pumping equipment | Keystone Pipeline System | ||||||
Plant, property and equipment | ||||||
Cost | 1,065 | 1,022 | 1,065 | 1,022 | ||
Accumulated Depreciation | 184 | 152 | 184 | 152 | ||
Net Book Value | 881 | 870 | 881 | 870 | ||
Operating segments | Liquids Pipelines | Pumping equipment | Intra-Alberta Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 104 | 104 | 104 | 104 | ||
Accumulated Depreciation | 3 | 0 | 3 | 0 | ||
Net Book Value | 101 | 104 | 101 | 104 | ||
Operating segments | Liquids Pipelines | Tanks and other | Keystone Pipeline System | ||||||
Plant, property and equipment | ||||||
Cost | 3,598 | 3,314 | 3,598 | 3,314 | ||
Accumulated Depreciation | 488 | 385 | 488 | 385 | ||
Net Book Value | 3,110 | 2,929 | 3,110 | 2,929 | ||
Operating segments | Liquids Pipelines | Tanks and other | Intra-Alberta Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 291 | 259 | 291 | 259 | ||
Accumulated Depreciation | 8 | 1 | 8 | 1 | ||
Net Book Value | 283 | 258 | 283 | 258 | ||
Operating segments | Liquids Pipelines | Property, plant and equipment excluding under construction | Keystone Pipeline System | ||||||
Plant, property and equipment | ||||||
Cost | 14,443 | 13,338 | 14,443 | 13,338 | ||
Accumulated Depreciation | 1,943 | 1,529 | 1,943 | 1,529 | ||
Net Book Value | 12,500 | 11,809 | 12,500 | 11,809 | ||
Operating segments | Liquids Pipelines | Property, plant and equipment excluding under construction | Intra-Alberta Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 1,157 | 1,111 | 1,157 | 1,111 | ||
Accumulated Depreciation | 33 | 4 | 33 | 4 | ||
Net Book Value | 1,124 | 1,107 | 1,124 | 1,107 | ||
Operating segments | Liquids Pipelines | Under construction | Keystone Pipeline System | ||||||
Plant, property and equipment | ||||||
Cost | 18 | 456 | 18 | 456 | ||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
Net Book Value | 18 | 456 | 18 | 456 | ||
Operating segments | Liquids Pipelines | Under construction | Intra-Alberta Pipelines | ||||||
Plant, property and equipment | ||||||
Cost | 84 | 47 | 84 | 47 | ||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
Net Book Value | 84 | 47 | 84 | 47 | ||
Operating segments | Energy | ||||||
Plant, property and equipment | ||||||
Cost | 4,538 | 5,080 | 4,538 | 5,080 | ||
Accumulated Depreciation | 877 | 1,103 | 877 | 1,103 | ||
Net Book Value | 3,661 | 3,977 | 3,661 | 3,977 | ||
Operating segments | Energy | Natural Gas | ||||||
Plant, property and equipment | ||||||
Cost | 2,062 | 2,645 | 2,062 | 2,645 | ||
Accumulated Depreciation | 708 | 743 | 708 | 743 | ||
Net Book Value | 1,354 | 1,902 | 1,354 | 1,902 | ||
Operating segments | Energy | Wind | ||||||
Plant, property and equipment | ||||||
Cost | 0 | 673 | 0 | 673 | ||
Accumulated Depreciation | 0 | 204 | 0 | 204 | ||
Net Book Value | 0 | 469 | 0 | 469 | ||
Operating segments | Energy | Natural Gas Storage and Other | ||||||
Plant, property and equipment | ||||||
Cost | 741 | 734 | 741 | 734 | ||
Accumulated Depreciation | 169 | 156 | 169 | 156 | ||
Net Book Value | 572 | 578 | 572 | 578 | ||
Operating segments | Energy | Property, plant and equipment excluding under construction | ||||||
Plant, property and equipment | ||||||
Cost | 2,803 | 4,052 | 2,803 | 4,052 | ||
Accumulated Depreciation | 877 | 1,103 | 877 | 1,103 | ||
Net Book Value | 1,926 | 2,949 | 1,926 | 2,949 | ||
Operating segments | Energy | Under construction | ||||||
Plant, property and equipment | ||||||
Cost | 1,735 | 1,028 | 1,735 | 1,028 | ||
Accumulated Depreciation | 0 | 0 | 0 | 0 | ||
Net Book Value | 1,735 | 1,028 | 1,735 | 1,028 | ||
Corporate | ||||||
Plant, property and equipment | ||||||
Cost | 448 | 411 | 448 | 411 | ||
Accumulated Depreciation | 210 | 168 | 210 | 168 | ||
Net Book Value | $ 238 | $ 243 | $ 238 | $ 243 | ||
TC PipeLines, LP | ||||||
Plant, property and equipment | ||||||
Noncontrolling interest, ownership interest by parent | 25.50% | 25.50% |
EQUITY INVESTMENTS - Ownership
EQUITY INVESTMENTS - Ownership Information of Equity Investments (Details) $ in Millions, $ in Millions | 12 Months Ended | |||||||||
Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Aug. 31, 2017 | Jun. 02, 2017 | Jun. 01, 2017 | May 01, 2016 | Mar. 31, 2016 | |
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | $ 714 | $ 773 | $ 514 | |||||||
Equity Investments | 7,113 | 6,366 | ||||||||
Iroquois | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 50.00% | 49.35% | ||||||||
TransGas | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 46.50% | |||||||||
Grand Rapids | ||||||||||
Equity Investments | ||||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ 102 | 105 | ||||||||
Canadian Natural Gas Pipelines | TQM | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | $ 12 | 11 | 12 | |||||||
Equity Investments | $ 71 | 68 | ||||||||
U.S. Natural Gas Pipelines | Northern Border | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | $ 87 | 87 | 92 | |||||||
Equity Investments | $ 677 | 641 | ||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ 115 | $ 115 | ||||||||
U.S. Natural Gas Pipelines | Iroquois | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 50.00% | 50.00% | 0.66% | 50.00% | ||||||
Income/(Loss) from Equity Investments | $ 60 | 59 | 54 | |||||||
Equity Investments | $ 291 | 280 | ||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ 41 | $ 41 | ||||||||
U.S. Natural Gas Pipelines | Millennium | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 47.50% | 47.50% | ||||||||
Income/(Loss) from Equity Investments | $ 75 | 66 | 33 | |||||||
Equity Investments | $ 511 | 291 | ||||||||
U.S. Natural Gas Pipelines | Pennant Midstream | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 47.00% | 47.00% | ||||||||
Income/(Loss) from Equity Investments | $ 17 | 11 | 6 | |||||||
Equity Investments | 256 | 228 | ||||||||
U.S. Natural Gas Pipelines | Other | ||||||||||
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | 17 | 17 | 29 | |||||||
Equity Investments | $ 113 | 92 | ||||||||
Mexico Natural Gas Pipelines | Sur de Texas | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 60.00% | 60.00% | ||||||||
Income/(Loss) from Equity Investments | $ 27 | 66 | (3) | |||||||
Equity Investments | 627 | 399 | ||||||||
Mexico Natural Gas Pipelines | TransGas | ||||||||||
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | 0 | (12) | 0 | |||||||
Equity Investments | $ 0 | 0 | ||||||||
Liquids Pipelines | Grand Rapids | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | $ 65 | 17 | (1) | |||||||
Equity Investments | 1,028 | 996 | ||||||||
Liquids Pipelines | Other | ||||||||||
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | (1) | (20) | 0 | |||||||
Equity Investments | 21 | 20 | ||||||||
Liquids Pipelines | Canaport Energy East Marine Terminal Limited Partnership | ||||||||||
Equity Investments | ||||||||||
Equity Investments | $ 0 | 0 | ||||||||
Energy | Bruce Power | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 48.30% | 48.30% | ||||||||
Income/(Loss) from Equity Investments | $ 311 | 434 | 293 | |||||||
Equity Investments | 3,166 | 2,987 | ||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ 870 | 902 | ||||||||
Energy | Portlands Energy | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | $ 36 | 31 | 33 | |||||||
Equity Investments | 289 | 301 | ||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ 73 | 73 | ||||||||
Energy | ASTC Power Partnership | ||||||||||
Equity Investments | ||||||||||
Ownership interest percentage | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | $ 0 | 0 | (37) | |||||||
Equity Investments | 0 | 0 | ||||||||
Energy | Other | ||||||||||
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | 8 | 6 | $ 3 | |||||||
Equity Investments | $ 63 | $ 63 |
EQUITY INVESTMENTS - Summarized
EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income | |||
Revenues | $ 4,836 | $ 4,913 | $ 4,336 |
Operating and other expenses | (3,545) | (2,993) | (3,068) |
Net income | 1,515 | 1,636 | 1,080 |
Income from equity investments | 714 | 773 | $ 514 |
Balance Sheet | |||
Current assets | 2,209 | 2,176 | |
Non-current assets | 20,647 | 17,869 | |
Current liabilities | (2,049) | (1,577) | |
Non-current liabilities | $ (9,042) | $ (8,217) |
EQUITY INVESTMENTS - Narrative
EQUITY INVESTMENTS - Narrative (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||
Oct. 31, 2017CAD ($) | Aug. 31, 2017CAD ($) | Mar. 31, 2016CAD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2018MXN ($) | Dec. 31, 2017MXN ($) | |
Equity Investments | ||||||||
Distributions received from equity investments | $ 1,106 | $ 1,332 | $ 1,571 | |||||
Returns of capital | 121 | 362 | 727 | |||||
Contributions to equity investments | 1,015 | 1,681 | $ 765 | |||||
Joint Venture | Revolving credit facility | Unsecured Loan Facility | ||||||||
Equity Investments | ||||||||
Credit facility, amount | $ 21,300,000,000 | |||||||
TransGas | ||||||||
Equity Investments | ||||||||
Asset impairment charges | $ 12 | |||||||
Ownership interest percentage | 46.50% | |||||||
Contract term | 20 years | |||||||
Canaport Energy East Marine Terminal Limited Partnership | Liquids Pipelines | Energy East, Eastern Mainline and Upland projects | ||||||||
Equity Investments | ||||||||
Asset impairment charges | $ 20 | |||||||
Sundance B PPA | Energy | ||||||||
Equity Investments | ||||||||
Asset impairment charges | $ 29 | |||||||
Asset impairment charge, after tax | $ 21 | |||||||
Sur de Texas | ||||||||
Equity Investments | ||||||||
Contributions to equity investments | 179 | 977 | ||||||
Sur de Texas | Joint Venture | ||||||||
Equity Investments | ||||||||
Loans receivable from affiliates | 1,300 | 900 | $ 18,900,000,000 | $ 14,400,000,000 | ||||
Interest income, related party | $ 120 | $ 34 | ||||||
Sur de Texas | Mexico Natural Gas Pipelines | ||||||||
Equity Investments | ||||||||
Ownership interest percentage | 60.00% | 60.00% |
RATE-REGULATED BUSINESSES - Nar
RATE-REGULATED BUSINESSES - Narrative (Details) $ in Millions | Dec. 31, 2018pipeline | Feb. 22, 2018 | Feb. 21, 2018 | Dec. 31, 2017 | Jun. 30, 2018 | Mar. 31, 2016USD ($) | Dec. 31, 2014CAD ($) | Dec. 31, 2013USD ($) |
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 | 5 years | |||||||
Cost recovery and return on investment, additional period | 3 years | |||||||
NGTL System | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Period of settlement | 2 years | |||||||
Approved ROE on deemed common equity, percent | 10.10% | |||||||
Deemed common equity, percent | 40.00% | |||||||
Approved composite depreciation rate | 3.50% | |||||||
Canadian Mainline | ||||||||
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 | 3.20% | 3.90% | ||||||
After-tax annual contribution to reduce revenue requirement | $ 20 | |||||||
Fixed toll term | 6 years | |||||||
Great Lakes | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Maximum transportation rate decrease | 27.00% | 2.00% | ||||||
TC Pipe Lines LP | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Noncontrolling interest, ownership interest by parent | 25.50% | |||||||
TC Pipe Lines LP | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Number of wholly-owned or partially owned pipelines | pipeline | 8 |
RATE-REGULATED BUSINESSES - Ass
RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) $ in Millions, $ in Millions | Dec. 31, 2018CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2006CAD ($) | Dec. 31, 2006USD ($) | Jul. 31, 2016USD ($) |
Regulatory Assets | |||||||
Regulatory Assets | $ 1,631 | $ 1,399 | $ 1,631 | ||||
Less: Current portion included in Other current assets (Note 7) | 83 | 23 | 83 | ||||
Regulatory Assets, noncurrent | 1,548 | 1,376 | 1,548 | ||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 4,521 | 4,584 | 4,521 | ||||
Less: Current portion included in Accounts payable and other (Note 14) | 591 | 263 | 591 | ||||
Regulatory Liabilities, noncurrent | 3,930 | 4,321 | 3,930 | ||||
Operating and debt-service regulatory liabilities | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 96 | 188 | $ 96 | ||||
Remaining Recovery/ Settlement Period (years) | 1 year | ||||||
Pensions and other post retirement benefits | ANR PIPELINE COMPANY | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 54 | 66 | $ 54 | ||||
Long term adjustment account | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 1,015 | 1,142 | $ 1,015 | ||||
Long term adjustment account | Minimum | |||||||
Regulatory Liabilities | |||||||
Remaining Recovery/ Settlement Period (years) | 2 years | ||||||
Long term adjustment account | Maximum | |||||||
Regulatory Liabilities | |||||||
Remaining Recovery/ Settlement Period (years) | 45 years | ||||||
Bridging amortization account | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 305 | 202 | $ 305 | ||||
Remaining Recovery/ Settlement Period (years) | 12 years | ||||||
Pipeline abandonment trust balance | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 1,113 | 825 | $ 1,113 | ||||
Cost of removal | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 261 | 216 | 261 | ||||
Deferred income taxes | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 165 | 75 | 165 | ||||
U.S. Tax Reform | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 1,394 | 1,659 | 1,394 | ||||
Other | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 65 | 47 | 65 | ||||
Postretirement benefit costs | ANR PIPELINE COMPANY | |||||||
Other disclosures pertaining to regulated assets and liabilities | |||||||
Regulatory liability settlement | 11 | $ 8 | 26 | $ 21 | |||
Amount to be addressed In next settlement | $ 43 | $ 32 | |||||
Long term adjustment account, amount to be amortized over two years | |||||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 932 | 932 | |||||
Deferred income taxes | |||||||
Regulatory Assets | |||||||
Regulatory Assets | 1,051 | 940 | 1,051 | ||||
Operating and debt-service regulatory assets | |||||||
Regulatory Assets | |||||||
Regulatory Assets | 12 | $ 12 | |||||
Remaining Recovery/ Settlement Period (years) | 1 year | ||||||
Pensions and other post retirement benefits | |||||||
Regulatory Assets | |||||||
Regulatory Assets | 379 | 388 | $ 379 | ||||
Regulatory Liabilities | |||||||
Regulatory Liabilities | 53 | 164 | 53 | ||||
Foreign exchange on long-term debt | |||||||
Regulatory Assets | |||||||
Regulatory Assets | 46 | $ 46 | |||||
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) | 11 years | ||||||
Other | |||||||
Regulatory Assets | |||||||
Regulatory Assets | $ 143 | $ 71 | $ 143 |
GOODWILL (Details)
GOODWILL (Details) $ in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2017CAD ($) | Jun. 30, 2017USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2017USD ($) | |
Goodwill | |||||
Balance at the beginning of the period | $ 13,084 | ||||
Balance at the end of the period | 14,178 | $ 13,084 | |||
U.S. Natural Gas Pipelines | |||||
Goodwill | |||||
Balance at the beginning of the period | 13,084 | 13,958 | |||
Tuscarora impairment charge | (79) | ||||
Foreign exchange rate changes | 1,173 | (945) | |||
Balance at the end of the period | $ 14,178 | 13,084 | |||
Columbian Pipeline | |||||
Goodwill | |||||
Balance at the beginning of the period | $ 7,747 | ||||
Columbia adjustment (Note 26) | $ 71 | $ 55 | |||
Balance at the end of the period | $ 7,802 | ||||
Columbian Pipeline | U.S. Natural Gas Pipelines | |||||
Goodwill | |||||
Columbia adjustment (Note 26) | $ 71 |
GOODWILL - Narrative (Details)
GOODWILL - Narrative (Details) $ in Millions, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2017USD ($) | |
Goodwill recorded on Company's acquisitions in the U.S. | |||||
Goodwill | $ 14,178 | $ 13,084 | |||
Tuscarora | |||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||
Goodwill impairment charge | 79 | ||||
Goodwill impairment charge, net of tax and noncontrolling interest | $ 15 | ||||
Goodwill | $ 23 | $ 82 | |||
Great Lakes | |||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||
Goodwill | $ 573 | $ 573 | |||
Percentage of fair value in excess of carrying amount (less than) | 10.00% | 10.00% | |||
Ravenswood | |||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||
Goodwill impairment charge | $ 1,085 | ||||
Goodwill impairment charge, net of tax | $ 656 |
INTANGIBLE AND OTHER ASSETS (De
INTANGIBLE AND OTHER ASSETS (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Goodwill and Intangible Assets Disclosure [Abstract] | ||
Capital projects in development | $ 1,051 | $ 596 |
Deferred income tax assets (Note 16) | 322 | 316 |
Employee post-retirement benefits (Note 23) | 192 | 193 |
Fair value of derivative contracts (Note 24) | 61 | 73 |
Other | 295 | 306 |
Intangible and other assets | $ 1,921 | $ 1,484 |
INTANGIBLE AND OTHER ASSETS - N
INTANGIBLE AND OTHER ASSETS - Narrative (Details) - CAD ($) $ in Millions | Oct. 05, 2017 | Nov. 30, 2018 | Oct. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Finite-Lived Intangible Assets [Line Items] | |||||||
Capital projects in development | $ 1,051 | $ 596 | |||||
Reimbursement of costs related to capital projects in development | 470 | 634 | $ 0 | ||||
Asset impairment charges | 801 | 1,257 | $ 1,388 | ||||
Sundance A (expires 2017) | Energy | |||||||
Finite-Lived Intangible Assets [Line Items] | |||||||
Asset impairment charges | $ 92 | 211 | |||||
Asset impairment charge, after tax | $ 68 | 155 | |||||
Keystone XL | |||||||
Finite-Lived Intangible Assets [Line Items] | |||||||
Capital projects in development | $ 800 | $ 0 | |||||
Coastal GasLink pipeline project | |||||||
Finite-Lived Intangible Assets [Line Items] | |||||||
Reimbursement of costs related to capital projects in development | $ 470 | ||||||
Pacific Northwest LNG project | |||||||
Finite-Lived Intangible Assets [Line Items] | |||||||
Reimbursement of costs related to capital projects in development | $ 634 | ||||||
Energy East, Eastern Mainline and Upland projects | |||||||
Finite-Lived Intangible Assets [Line Items] | |||||||
Asset impairment charges | $ 1,153 | ||||||
Asset impairment charge, after tax | $ 870 |
NOTES PAYABLE (Details)
NOTES PAYABLE (Details) | 12 Months Ended | ||||||
Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2018MXN ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017MXN ($) | Dec. 31, 2017USD ($) | |
Notes payable | |||||||
Outstanding | $ 2,762,000,000 | $ 1,763,000,000 | |||||
Operated affiliates | |||||||
Notes payable | |||||||
Unused Capacity | 800,000,000 | 400,000,000 | |||||
Revolving credit facility | |||||||
Notes payable | |||||||
Cost to maintain | 12,000,000 | 7,000,000 | $ 10,000,000 | ||||
Revolving and demand credit facilities | |||||||
Notes payable | |||||||
Total Facilities | 12,900,000,000 | 11,000,000,000 | |||||
TCPL | Revolving credit facility | |||||||
Notes payable | |||||||
Total Facilities | $ 2,000,000,000 | ||||||
TCPL | Revolving credit facility | Maturing December 2023 | |||||||
Notes payable | |||||||
Total Facilities | 3,000,000,000 | 3,000,000,000 | |||||
Unused Capacity | 3,000,000,000 | ||||||
TCPL | Notes payable | |||||||
Notes payable | |||||||
Outstanding | $ 2,117,000,000 | $ 884,000,000 | |||||
Weighted average interest rate per annum | 2.50% | 1.60% | 2.50% | 2.50% | 1.60% | 1.60% | |
TCPL USA and TAIL | Notes payable | |||||||
Notes payable | |||||||
Outstanding | $ 611,000,000 | $ 862,000,000 | $ 448,000,000 | $ 688,000,000 | |||
Weighted average interest rate per annum | 3.10% | 2.20% | 3.10% | 3.10% | 2.20% | 2.20% | |
Mexico subsidiary | Revolving credit facility | |||||||
Notes payable | |||||||
Total Facilities | $ 5,000,000,000 | $ 5,000,000,000 | |||||
Unused Capacity | $ 4,500,000,000 | ||||||
Mexico subsidiary | Notes payable | |||||||
Notes payable | |||||||
Outstanding | $ 34,000,000 | $ 17,000,000 | $ 25,000,000 | $ 275,000,000 | |||
Weighted average interest rate per annum | 3.30% | 8.00% | 3.30% | 3.30% | 8.00% | 8.00% | |
TCPL/TCPL USA/Columbia/TAIL | Revolving credit facility | Maturing December 2019 | |||||||
Notes payable | |||||||
Total Facilities | $ 4,500,000,000 | $ 0 | |||||
Unused Capacity | 4,500,000,000 | ||||||
TCPL/TCPL USA/Columbia/TAIL | Revolving credit facility | Maturing December 2021 | |||||||
Notes payable | |||||||
Total Facilities | 1,000,000,000 | 0 | |||||
Unused Capacity | $ 1,000,000,000 | ||||||
TCPL USA | Revolving credit facility | |||||||
Notes payable | |||||||
Total Facilities | 1,000,000,000 | ||||||
Columbia | Revolving credit facility | |||||||
Notes payable | |||||||
Total Facilities | 1,000,000,000 | ||||||
TAIL | Revolving credit facility | |||||||
Notes payable | |||||||
Total Facilities | $ 500,000,000 | ||||||
TCPL/TCPL USA | Revolving credit facility | |||||||
Notes payable | |||||||
Total Facilities | $ 2,100,000,000 | $ 1,900,000,000 | |||||
Unused Capacity | $ 1,000,000,000 |
ACCOUNTS PAYABLE AND OTHER (Det
ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Jan. 01, 2018 | Dec. 31, 2017 |
Payables and Accruals [Abstract] | |||
Trade payables | $ 3,224 | $ 2,847 | |
Fair value of derivative contracts (Note 24) | 922 | 387 | |
Unredeemed shares of Columbia | 357 | 312 | |
Regulatory liabilities (Note 10) | 591 | 263 | |
Other | 314 | 248 | |
Accounts payable and other | $ 5,408 | $ 4,074 | $ 4,057 |
OTHER LONG-TERM LIABILITIES (De
OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred Costs, Noncurrent [Abstract] | ||
Employee post-retirement benefits (Note 23) | $ 569 | $ 389 |
Asset retirement obligations | 90 | 98 |
Fair value of derivative contracts (Note 24) | 42 | 72 |
Guarantees (Note 27) | 12 | 16 |
Other | 295 | 152 |
Other long-term liabilities | $ 1,008 | $ 727 |
INCOME TAXES - U.S. Tax Reform
INCOME TAXES - U.S. Tax Reform (Details) - CAD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Contingency [Line Items] | |||
Provisional deferred income tax recovery | $ 816 | ||
Increase in regulatory liabilities for businesses subject to RRA | 1,686 | ||
Additional deferred income tax recovery | $ 52 | ||
Additional deferred income tax recovery for businesses subject to RRA | 115 | ||
U.S. Tax Reform | |||
Income Tax Contingency [Line Items] | |||
Amortization of regulatory liability | $ 58 | ||
Net regulatory liability | $ 1,394 | $ 1,394 | 1,686 |
Other Post-Retirement Benefit Plans | |||
Income Tax Contingency [Line Items] | |||
Provisional deferred income tax recovery | $ 12 |
INCOME TAXES - Provision (Detai
INCOME TAXES - Provision (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current | |||
Canada | $ 65 | $ 113 | $ 116 |
Foreign | 250 | 36 | 40 |
Total | 315 | 149 | 156 |
Deferred | |||
Canada | 49 | (185) | 101 |
Foreign | 235 | 751 | 95 |
Deferred – U.S. Tax Reform and 2018 FERC Actions | (167) | (804) | 0 |
Total | 117 | (238) | 196 |
Income Tax (Recovery)/Expense | $ 432 | $ (89) | $ 352 |
INCOME TAXES - Geographic Compo
INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Canada | $ 433 | $ (339) | $ 219 |
Foreign | 3,516 | 3,645 | 618 |
Income before Income Taxes | $ 3,949 | $ 3,306 | $ 837 |
INCOME TAXES - Reconciliation o
INCOME TAXES - Reconciliation of Income Tax (Recovery)/Expense (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Income before income taxes | $ 3,949 | $ 3,306 | $ 837 |
Federal and provincial statutory tax rate | 27.00% | 27.00% | 27.00% |
Expected income tax expense | $ 1,066 | $ 893 | $ 226 |
U.S. Tax Reform and 2018 FERC Actions | (167) | (804) | 0 |
Foreign income tax rate differentials | (432) | (81) | (196) |
Loss/(income) from equity investments and non-controlling interests | 50 | (64) | (68) |
Income tax differential related to regulated operations | (54) | (42) | 81 |
Non-taxable portion of capital gains | (11) | (42) | 0 |
Asset impairment charges | 0 | 34 | 242 |
Non-deductible amounts | 0 | 4 | 46 |
Other | (20) | 13 | 21 |
Income Tax (Recovery)/Expense | 432 | (89) | 352 |
Foreign tax rate differential related to asset impairments, amount | $ 0 | $ 0 | $ 112 |
INCOME TAXES - Deferred Assets
INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred Income Tax Assets | ||
Tax loss and credit carryforwards | $ 1,238 | $ 1,379 |
Difference in accounting and tax bases of impaired assets and assets held for sale | 574 | 651 |
Regulatory and other deferred amounts | 858 | 512 |
Unrealized foreign exchange losses on long-term debt | 491 | 216 |
Financial instruments | 10 | |
Other | 292 | 227 |
Deferred tax assets, gross | 3,453 | 2,995 |
Less: Valuation allowance | 1,159 | 832 |
Deferred tax assets, net of Valuation allowance | 2,294 | 2,163 |
Deferred Income Tax Liabilities | ||
Difference in accounting and tax bases of plant, property and equipment and PPAs | 6,449 | 6,240 |
Equity investments | 1,069 | 632 |
Taxes on future revenue requirement | 300 | 238 |
Other | 180 | 140 |
Deferred tax liabilities, gross | 7,998 | 7,250 |
Net Deferred Income Tax Liabilities | 5,704 | 5,087 |
Deferred Income Tax Assets | ||
Intangible and other assets (Note 12) | 322 | 316 |
Deferred Income Tax Liabilities | ||
Deferred income tax liabilities | 6,026 | 5,403 |
Net Deferred Income Tax Liabilities | $ 5,704 | $ 5,087 |
INCOME TAXES - Reconciliation_2
INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Unrecognized tax benefit at beginning of year | $ 15 | $ 18 | $ 17 |
Gross increases – tax positions in prior years | 13 | 0 | 3 |
Gross decreases – tax positions in prior years | (5) | (1) | 0 |
Gross increases – tax positions in current year | 0 | 2 | 2 |
Settlement | 0 | 0 | (1) |
Lapse of statutes of limitations | (4) | (4) | (3) |
Unrecognized Tax Benefit at End of Year | $ 19 | $ 15 | $ 18 |
INCOME TAXES - Additional Narra
INCOME TAXES - Additional Narrative (Details) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Net operating loss carryforwards | |||||
Tax loss and credit carryforwards | $ 1,238,000,000 | $ 1,379,000,000 | |||
Deferred income tax liabilities on the unremitted earnings of foreign investments | 619,000,000 | 569,000,000 | |||
Income tax payments, net of refunds | 338,000,000 | 247,000,000 | $ 105,000,000 | ||
Interest expense (recovery) reflected within net tax expense | (1,000,000) | 0 | 0 | ||
Income tax penalties expense | 0 | 0 | $ 0 | ||
Accrued interest expense | 3,000,000 | 4,000,000 | |||
Income tax penalties accrued | 0 | 0 | |||
Canada federal and provincial | |||||
Net operating loss carryforwards | |||||
Unused net operating loss carryforwards | 1,867,000,000 | 1,280,000,000 | |||
Capital loss carryforwards | 0 | ||||
Capital loss carryforwards unrecognized | 821,000,000 | 668,000,000 | |||
Canada federal and provincial | Alternative minimum tax | |||||
Net operating loss carryforwards | |||||
Minimum tax credits | 91,000,000 | 82,000,000 | |||
U.S. federal | |||||
Net operating loss carryforwards | |||||
Unused net operating loss carryforwards | $ 889 | $ 1,800 | |||
Tax loss and credit carryforwards | $ 0 | $ 0 | |||
Operating loss carryforward unrecognized | 706 | 710 | |||
U.S. federal | Alternative minimum tax | |||||
Net operating loss carryforwards | |||||
Minimum tax credits | 1 | 56 | |||
Mexican Tax Authority | |||||
Net operating loss carryforwards | |||||
Tax loss and credit carryforwards | $ 3 | $ 7 |
LONG-TERM DEBT - Amounts Outsta
LONG-TERM DEBT - Amounts Outstanding and Principal Repayments (Details) $ in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Jun. 30, 2017CAD ($) | Jun. 30, 2017USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | |
Debt Instrument [Line Items] | |||||||
Outstanding | $ 39,982 | $ 34,677 | |||||
Current portion of long-term debt | (3,462) | (2,866) | |||||
Unamortized debt discount and issue costs | (241) | (174) | |||||
Fair value adjustments | 230 | 238 | |||||
Long-term debt, excluding current maturities | 36,509 | 31,875 | |||||
Decrease in fair value of interest rate hedge | 2 | 4 | |||||
Repayments of Long-term Debt [Abstract] | |||||||
2,019 | 3,465 | ||||||
2,020 | 2,834 | ||||||
2,021 | 2,098 | ||||||
2,022 | 2,100 | ||||||
2,023 | 1,930 | ||||||
Columbian Pipeline | |||||||
Debt Instrument [Line Items] | |||||||
Increase (decrease) in fair value of acquired liabilities, long-term debt | $ 300 | $ 231 | 232 | 242 | |||
TRANSCANADA PIPELINES LIMITED | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | 31,856 | 26,149 | |||||
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Dates Between 2019 and 2020 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 350 | $ 500 | |||||
Interest Rate | 11.40% | 10.80% | 11.40% | 10.80% | |||
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Date of 2021 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 546 | $ 501 | $ 400 | $ 400 | |||
Interest Rate | 9.90% | 9.90% | 9.90% | 9.90% | |||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 7,504 | $ 6,504 | |||||
Interest Rate | 4.80% | 4.90% | 4.80% | 4.90% | |||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 23,456 | $ 18,644 | $ 17,192 | $ 14,892 | |||
Interest Rate | 5.10% | 5.10% | 5.10% | 5.10% | |||
NOVA GAS TRANSMISSION LTD. | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 921 | $ 895 | |||||
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Date of 2024 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 100 | $ 100 | |||||
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 | $ 273 | $ 250 | $ 200 | $ 200 | |||
Interest Rate | 7.90% | 7.90% | 7.90% | 7.90% | |||
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity between 2025 and 2030 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 504 | $ 504 | |||||
Interest Rate | 7.40% | 7.40% | 7.40% | 7.40% | |||
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity Date of 2026 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 44 | $ 41 | $ 33 | $ 33 | |||
Interest Rate | 7.50% | 7.50% | 7.50% | 7.50% | |||
Columbian Pipeline | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 3,070 | $ 3,443 | $ 2,250 | $ 2,750 | |||
Interest Rate | 4.40% | 4.00% | 4.40% | 4.00% | |||
TC PIPELINES, LP | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 2,374 | $ 2,573 | |||||
TC PIPELINES, LP | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 1,637 | $ 1,502 | $ 1,200 | $ 1,200 | |||
Interest Rate | 4.40% | 4.40% | 4.40% | 4.40% | |||
TC PIPELINES, LP | Unsecured Loan Facility | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 55 | $ 232 | $ 40 | $ 185 | |||
Interest Rate | 3.80% | 2.70% | 3.80% | 2.70% | |||
TC PIPELINES, LP | Unsecured Term Loan | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 682 | $ 839 | $ 500 | $ 670 | |||
Interest Rate | 3.60% | 2.70% | 3.60% | 2.70% | |||
TC PIPELINES, LP | Unsecured Term Loan Maturing October 2022 | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 500 | ||||||
ANR PIPELINE COMPANY | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 918 | $ 842 | $ 672 | $ 672 | |||
Interest Rate | 7.20% | 7.20% | 7.20% | 7.20% | |||
GAS TRANSMISSION NORTHWEST LLC | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 389 | $ 382 | |||||
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 341 | $ 313 | $ 250 | $ 250 | |||
Interest Rate | 5.60% | 5.60% | 5.60% | 5.60% | |||
GAS TRANSMISSION NORTHWEST LLC | Unsecured Term Loan | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 48 | $ 69 | $ 35 | $ 55 | |||
Interest Rate | 3.30% | 1.10% | 3.30% | 1.10% | |||
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 327 | $ 324 | $ 240 | $ 259 | |||
Interest Rate | 7.70% | 7.70% | 7.70% | 7.70% | |||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 26 | $ 38 | |||||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Unsecured Loan Facility | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 26 | $ 19 | $ 0 | ||||
Interest Rate | 3.60% | 0.00% | 3.60% | 0.00% | |||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Senior Secured Notes | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 0 | $ 38 | $ 0 | $ 30 | |||
Interest Rate | 0.00% | 6.00% | 0.00% | 6.00% | |||
TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 33 | $ 31 | $ 24 | $ 25 | |||
Interest Rate | 3.50% | 1.10% | 3.50% | 1.10% | |||
NORTH BAJA PIPELINE, LLC | Unsecured Term Loan | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding | $ 68 | $ 50 | $ 0 | ||||
Interest Rate | 3.50% | 0.00% | 3.50% | 0.00% |
LONG-TERM DEBT - Issued (Detail
LONG-TERM DEBT - Issued (Details) $ in Millions, $ in Millions | 1 Months Ended | |||||||||||||
Dec. 31, 2018USD ($) | Oct. 31, 2018USD ($) | Jul. 31, 2018CAD ($) | May 31, 2018USD ($) | Apr. 30, 2018USD ($) | Nov. 30, 2017USD ($) | Sep. 30, 2017CAD ($) | Aug. 31, 2017USD ($) | May 31, 2017USD ($) | Nov. 30, 2016USD ($) | Jun. 30, 2016CAD ($) | Jun. 30, 2016USD ($) | Apr. 30, 2016USD ($) | Jan. 31, 2016USD ($) | |
Acquisition Bridge Facility | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 6,900 | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due March 2049 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 1,000 | |||||||||||||
Interest Rate | 5.10% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due May 2028 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 400 | $ 1,000 | ||||||||||||
Interest Rate | 4.25% | 4.25% | ||||||||||||
Long-term debt, re-issuance yield, percent | 4.439% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due July 2048 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 800 | |||||||||||||
Interest Rate | 4.18% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due March 2028 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 200 | |||||||||||||
Interest Rate | 3.39% | |||||||||||||
Long-term debt, re-issuance yield, percent | 3.41% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due May 2048 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 1,000 | |||||||||||||
Interest Rate | 4.875% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due May 2038 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 500 | |||||||||||||
Interest Rate | 4.75% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due November 2019, floating interest rate | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 550 | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due November 2019, fixed interest rate | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 700 | |||||||||||||
Interest Rate | 2.125% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due March 2028 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 300 | |||||||||||||
Interest Rate | 3.39% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due September 2047 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 700 | |||||||||||||
Interest Rate | 4.33% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Acquisition Bridge Facility | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 5,213 | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due July 2023 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 300 | |||||||||||||
Interest Rate | 3.69% | 3.69% | ||||||||||||
Long-term debt, re-issuance yield, percent | 2.69% | 2.69% | ||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due June 2046 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 700 | |||||||||||||
Interest Rate | 4.35% | 4.35% | ||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due January 2026 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 850 | |||||||||||||
Interest Rate | 4.875% | |||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due January 2019 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 400 | |||||||||||||
Interest Rate | 3.125% | |||||||||||||
NORTH BAJA PIPELINE, LLC | Unsecured Term Loan due December 2021 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 50 | |||||||||||||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Unsecured Loan Facility due April 2023 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 19 | |||||||||||||
TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan due August 2020 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 25 | |||||||||||||
TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan due April 2019 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 10 | |||||||||||||
TC PIPELINES, LP | Senior Unsecured Notes due May 2027 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 500 | |||||||||||||
Interest Rate | 3.90% | |||||||||||||
TRANSCANADA PIPELINE USA LTD. | Acquisition Bridge Facility | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 1,700 | |||||||||||||
ANR PIPELINE COMPANY | Senior Unsecured Notes Due June 2026 | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Amount | $ 240 | |||||||||||||
Interest Rate | 4.14% | 4.14% |
LONG-TERM DEBT - Retired (Detai
LONG-TERM DEBT - Retired (Details) $ in Millions, $ in Millions | 1 Months Ended | ||||||||||||||||||
Dec. 31, 2018USD ($) | Aug. 31, 2018USD ($) | Jun. 30, 2018USD ($) | May 31, 2018USD ($) | Mar. 31, 2018CAD ($) | Mar. 31, 2018USD ($) | Jan. 31, 2018USD ($) | Dec. 31, 2017CAD ($) | 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 ($) | |
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due August 2018 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 850 | ||||||||||||||||||
Interest Rate | 6.50% | ||||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Debentures due March 2018 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 150 | ||||||||||||||||||
Interest Rate | 9.45% | 9.45% | |||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due January 2018, fixed interest rate | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 500 | ||||||||||||||||||
Interest Rate | 1.875% | ||||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due January 2018, floating interest rate | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 250 | ||||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Debentures due December 2017 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 100 | ||||||||||||||||||
Interest Rate | 9.80% | ||||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due November 2017 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 1,000 | ||||||||||||||||||
Interest Rate | 1.625% | ||||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Acquisition Bridge Facility | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 1,513 | $ 500 | $ 3,200 | ||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due January 2017 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 300 | ||||||||||||||||||
Interest Rate | 5.10% | ||||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due October 2016 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 400 | ||||||||||||||||||
Interest Rate | 4.65% | ||||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due June 2016, fixed interest rate | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 84 | ||||||||||||||||||
Interest Rate | 7.69% | ||||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Medium Term Notes due June 2016, floating interest rate | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 500 | ||||||||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due January 2016 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 750 | ||||||||||||||||||
Interest Rate | 0.75% | ||||||||||||||||||
TC PIPELINES, LP | Unsecured Term Loan due December 2018 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 170 | ||||||||||||||||||
COLUMBIA PIPELINE GROUP, INC. | Senior Unsecured Notes due June 2018 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 500 | ||||||||||||||||||
Interest Rate | 2.45% | ||||||||||||||||||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Senior Secured Notes due May 2018 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 18 | ||||||||||||||||||
Interest Rate | 5.90% | ||||||||||||||||||
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes due March 2018 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 9 | ||||||||||||||||||
Interest Rate | 6.73% | 6.73% | |||||||||||||||||
TUSCARORA GAS TRANSMISSION COMPANY | Senior Secured Notes due August 2017 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 12 | ||||||||||||||||||
Interest Rate | 3.82% | ||||||||||||||||||
TRANSCANADA PIPELINE USA LTD. | Acquisition Bridge Facility | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 630 | $ 1,070 | |||||||||||||||||
NOVA GAS TRANSMISSION LTD. | Debentures due February 2016 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount | $ 225 | ||||||||||||||||||
Interest Rate | 12.20% |
LONG-TERM DEBT - Interest Expen
LONG-TERM DEBT - Interest Expense and Payments (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Interest Expense [Abstract] | |||
Capitalized interest | $ (124) | $ (173) | $ (176) |
Amortization and other financial charges | 48 | 67 | 211 |
Interest expense | 2,265 | 2,069 | 1,998 |
Interest payments, net of interest capitalized | 2,156 | 1,987 | 1,721 |
Interest Expense | |||
Interest Expense [Abstract] | |||
Dividend equivalent payments recorded as interest expense | 109 | 109 | |
Short-term debt | |||
Interest Expense [Abstract] | |||
Interest on debt | 73 | 33 | 18 |
Long-term debt (excluding junior subordinated notes) | |||
Interest Expense [Abstract] | |||
Interest on debt | 1,877 | 1,794 | 1,765 |
Junior subordinated notes | |||
Interest Expense [Abstract] | |||
Interest on debt | $ 391 | $ 348 | $ 180 |
JUNIOR SUBORDINATED NOTES (Deta
JUNIOR SUBORDINATED NOTES (Details) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||
May 31, 2017USD ($) | Mar. 31, 2017USD ($) | Aug. 31, 2016USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2017USD ($) | May 31, 2017CAD ($) | |
Debt Instrument [Line Items] | |||||||||
Outstanding | $ 39,982,000,000 | $ 34,677,000,000 | |||||||
Unamortized debt discount and issue costs | (241,000,000) | (174,000,000) | |||||||
Long-term Debt | $ 750,000,000 | $ 1,100,000,000 | |||||||
TRANSCANADA PIPELINES LIMITED | |||||||||
Debt Instrument [Line Items] | |||||||||
Outstanding | 31,856,000,000 | 26,149,000,000 | |||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Outstanding | 7,572,000,000 | 7,071,000,000 | |||||||
Unamortized debt discount and issue costs | (64,000,000) | (64,000,000) | |||||||
Long-term Debt | 7,508,000,000 | 7,007,000,000 | |||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067 | Junior subordinated notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Outstanding | $ 1,364,000,000 | $ 1,252,000,000 | |||||||
Effective Interest Rate | 5.60% | 5.60% | 5.00% | 5.00% | |||||
Debt instrument, face amount | $ 1,000,000,000 | ||||||||
Stated interest rate | 6.35% | 6.35% | 6.35% | ||||||
Stated interest rate, period of time | 10 years | ||||||||
Debt converted | $ 1,000,000,000 | ||||||||
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] | |||||||||
Outstanding | $ 1,024,000,000 | $ 939,000,000 | |||||||
Effective Interest Rate | 6.50% | 6.50% | 5.90% | 5.90% | |||||
Debt instrument, face amount | $ 750,000,000 | ||||||||
Stated interest rate | 5.875% | 5.875% | |||||||
Stated interest rate, period of time | 10 years | ||||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2076 | Junior subordinated notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Outstanding | $ 1,637,000,000 | $ 1,502,000,000 | |||||||
Effective Interest Rate | 7.20% | 7.20% | 6.60% | 6.60% | |||||
Debt instrument, face amount | $ 1,200,000,000 | ||||||||
Stated interest rate | 6.125% | 6.125% | |||||||
Stated interest rate, period of time | 10 years | ||||||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2077 | Junior subordinated notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Outstanding | $ 2,047,000,000 | $ 1,878,000,000 | |||||||
Effective Interest Rate | 6.20% | 6.20% | 5.60% | 5.60% | |||||
Debt instrument, face amount | $ 1,500,000,000 | ||||||||
Stated interest rate | 5.55% | 5.55% | |||||||
Stated interest rate, period of time | 10 years | ||||||||
TRANSCANADA PIPELINES LIMITED | Canadian junior subordinated debt, due 2077 | Junior subordinated notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Outstanding | $ 1,500,000,000 | $ 1,500,000,000 | |||||||
Effective Interest Rate | 5.50% | 5.50% | 5.10% | 5.10% | |||||
Debt instrument, face amount | $ 1,500,000,000 | ||||||||
Stated interest rate | 4.90% | 4.90% | |||||||
Stated interest rate, period of time | 10 years | ||||||||
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 percentage | 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 | $ 1,500,000,000 | ||||||||
Stated interest rate | 4.90% | ||||||||
Administrative charge percentage | 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 percentage | 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 | 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 | $ 1,500,000,000 | ||||||||
Stated interest rate, period of time | 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 | 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 ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Non-controlling interest included in the Consolidated Balance Sheet | |||
Non-controlling interest in TC PipeLines, LP | $ 1,655 | $ 1,852 | |
Non-controlling interests included in the Consolidated Statement of Income | |||
Net (loss)/income attributable to non-controlling interests | (185) | 238 | $ 252 |
Noncontrolling Interest | |||
Non-controlling interests included in the Consolidated Statement of Income | |||
Net (loss)/income attributable to non-controlling interests | 185 | (238) | (252) |
TC PipeLines, LP | Noncontrolling Interest | |||
Non-controlling interest included in the Consolidated Balance Sheet | |||
Non-controlling interest in TC PipeLines, LP | 1,655 | 1,852 | |
Non-controlling interests included in the Consolidated Statement of Income | |||
Net (loss)/income attributable to non-controlling interests | (185) | 220 | 215 |
Portland Natural Gas Transmission System | Noncontrolling Interest | |||
Non-controlling interests included in the Consolidated Statement of Income | |||
Net (loss)/income attributable to non-controlling interests | 0 | 9 | 20 |
Columbia Pipeline Partners LP | Noncontrolling Interest | |||
Non-controlling interests included in the Consolidated Statement of Income | |||
Net (loss)/income attributable to non-controlling interests | $ 0 | $ 9 | $ 17 |
NON-CONTROLLING INTERESTS - Nar
NON-CONTROLLING INTERESTS - Narrative (Details) $ / shares in Units, shares in Millions, $ in Millions, $ in Millions | Jun. 01, 2017 | Feb. 17, 2017USD ($)$ / shares | Jan. 01, 2016 | May 19, 2016shares | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2016USD ($) | Jul. 01, 2016 |
Noncontrolling Interest | |||||||||
Non-controlling interests | |||||||||
Aggregate transaction value | $ | $ 9 | $ 41 | $ 40 | ||||||
TC Pipe Lines LP | |||||||||
Non-controlling interests | |||||||||
Common units outstanding, subject to rescission, amount | $ 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 Pipe Lines LP | Noncontrolling Interest | |||||||||
Non-controlling interests | |||||||||
Percentage of non-controlling interests | 74.50% | 74.30% | |||||||
TC Pipe Lines LP | Noncontrolling Interest | Minimum | |||||||||
Non-controlling interests | |||||||||
Percentage of non-controlling interests | 73.20% | 72.00% | 72.00% | ||||||
TC Pipe Lines LP | Noncontrolling Interest | Maximum | |||||||||
Non-controlling interests | |||||||||
Percentage of non-controlling interests | 74.30% | 73.20% | 73.20% | ||||||
Portland Natural Gas Transmission System | Noncontrolling Interest | |||||||||
Non-controlling interests | |||||||||
Percentage of non-controlling interests | 0.00% | ||||||||
Ownership interest before transaction, percent | 11.81% | 49.90% | |||||||
Columbia Pipeline Partners LP | |||||||||
Non-controlling interests | |||||||||
Common units outstanding, subject to rescission, amount | $ 1,073 | $ 799 | |||||||
Columbia Pipeline Partners LP | Noncontrolling Interest | |||||||||
Non-controlling interests | |||||||||
Percentage of non-controlling interests | 53.50% | ||||||||
Share price (in dollars per share) | $ / shares | $ 17 | ||||||||
Stub period distribution payments acquired (in dollars per share) | $ / shares | $ 0.10 | ||||||||
Aggregate transaction value | $ | $ 921 |
COMMON SHARES - Reconciliation
COMMON SHARES - Reconciliation and Weighted Average Common Shares Outstanding (Details) - CAD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Nov. 30, 2016 | Jan. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (decrease) in equity | |||||
Outstanding at the beginning of the period (in shares) | 881,000,000 | ||||
Outstanding at the beginning of the period | $ 21,167 | ||||
Issued under public offerings (in shares) | 60,200,000 | ||||
Exercise of options (in shares) | 734,000 | ||||
Repurchase of shares (in shares) | (305,407) | ||||
Repurchase of shares | $ (14) | ||||
Outstanding at the end of the period (in shares) | 918,000,000 | 881,000,000 | |||
Outstanding at the end of the period | $ 23,174 | $ 21,167 | |||
Weighted Average Common Shares Outstanding | |||||
Basic (in shares) | 902,000,000 | 872,000,000 | 759,000,000 | ||
Diluted (in shares) | 903,000,000 | 874,000,000 | 760,000,000 | ||
Common Shares | |||||
Increase (decrease) in equity | |||||
Outstanding at the beginning of the period (in shares) | 702,614,000 | 881,376,000 | 863,759,000 | 702,614,000 | |
Outstanding at the beginning of the period | $ 12,102 | $ 21,167 | $ 20,099 | $ 12,102 | |
Issued under public offerings (in shares) | 156,825,000 | ||||
Issued under public offerings | $ 7,752 | ||||
Dividend reinvestment and share purchase plan (in shares) | 15,937,000 | 12,824,000 | 2,942,000 | ||
Dividend reinvestment and share purchase plan | $ 855 | $ 790 | $ 177 | ||
At-the-market equity issuance program (in shares) | 20,050,000 | 3,462,000 | |||
At-the-market equity issuance program | $ 1,118 | $ 216 | |||
Exercise of options (in shares) | 734,000 | 1,331,000 | 1,683,000 | ||
Exercise of options | $ 34 | $ 62 | $ 74 | ||
Repurchase of shares (in shares) | (305,000) | ||||
Repurchase of shares | $ (6) | $ (6) | |||
Outstanding at the end of the period (in shares) | 918,097,000 | 881,376,000 | 863,759,000 | ||
Outstanding at the end of the period | $ 23,174 | $ 21,167 | $ 20,099 | ||
Weighted Average Common Shares Outstanding | |||||
Basic (in shares) | 902,000,000 | 872,000,000 | 759,000,000 | ||
Diluted (in shares) | 903,000,000 | 874,000,000 | 760,000,000 |
COMMON SHARES - Dividend Reinve
COMMON SHARES - Dividend Reinvestment and Share Purchase Plan (Details) | Jul. 01, 2016 |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |
Discount of shares issued from treasury (percent) | 2.00% |
COMMON SHARES - TransCanada Cor
COMMON SHARES - TransCanada Corporation At-the-Market Equity Issuance Program (Details) - CAD ($) $ / shares in Units, shares in Millions | Dec. 31, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2018 | Nov. 30, 2016 |
Subsidiary, Sale of Stock [Line Items] | |||||
Price per share (in Canadian dollars per share) | $ 58.50 | ||||
At-the-Market Equity Issuance Program | |||||
Subsidiary, Sale of Stock [Line Items] | |||||
Stock issuance program, period in effect (in months) | 25 months | ||||
Authorized amount | $ 2,000,000,000 | $ 1,000,000,000 | |||
Treasury stock reissued during period (in shares) | 3.5 | 20 | |||
Price per share (in Canadian dollars per share) | $ 63.03 | $ 56.13 | |||
Consideration received on transaction | $ 216,000,000 | $ 1,100,000,000 | |||
Payments of stock issuance costs | $ 2,000,000 | $ 10,000,000 | |||
Additional authorized amount | $ 1,000,000,000 |
COMMON SHARES - Common Share Pu
COMMON SHARES - Common Share Public Offering and Subscription Receipts (Details) $ / shares in Units, $ in Millions, $ in Billions | 1 Months Ended | 12 Months Ended | ||||
Nov. 30, 2016CAD ($)$ / sharesshares | Nov. 30, 2016USD ($)shares | Apr. 30, 2016CAD ($)$ / sharesshares | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | |
Class of Stock [Line Items] | ||||||
Subscription receipt (in shares) | shares | 96,600,000 | |||||
Share price (in CAD per share) | $ / shares | $ 45.75 | |||||
Common stock, value, subscriptions | $ 4,400 | |||||
Common stock subscriptions, number of common shares issuable per subscription (in shares) | shares | 1 | |||||
Issued under public offerings (in shares) | shares | 60,200,000 | 60,200,000 | ||||
Sale of stock, price per share (in CAD per share) | $ / shares | $ 58.50 | |||||
Common shares issued, net of issue costs | $ 3,500 | $ 1,148 | $ 274 | $ 7,747 | ||
Acquisition Bridge Facility | ||||||
Class of Stock [Line Items] | ||||||
Proceeds from lines of credit | $ 6.9 | |||||
Interest Expense | ||||||
Class of Stock [Line Items] | ||||||
Dividend equivalent payments recorded as interest expense | $ 109 | $ 109 |
COMMON SHARES - Common Shares R
COMMON SHARES - Common Shares Repurchased (Details) - CAD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | |
Jan. 31, 2016 | Nov. 30, 2015 | Dec. 31, 2016 | |
Class of Stock [Line Items] | |||
Number of shares approved to be repurchased and canceled from the Toronto Stock Exchange (in shares) | 21,000,000 | ||
Number of common shares repurchased (in shares) | 305,407 | ||
Average price per share of common shares repurchased (in Canadian dollars per share) | $ 44.90 | ||
Value recorded for common stock repurchased | $ 14 | ||
Common Shares | |||
Class of Stock [Line Items] | |||
Percentage of shares authorized to be repurchased and canceled | 3.00% | ||
Number of common shares repurchased (in shares) | 305,000 | ||
Value recorded for common stock repurchased | 6 | $ 6 | |
Additional Paid-In Capital | |||
Class of Stock [Line Items] | |||
Value recorded for common stock repurchased | $ 8 | $ 8 |
COMMON SHARES - Options (Detail
COMMON SHARES - Options (Details) | 12 Months Ended |
Dec. 31, 2018$ / sharesshares | |
Number of Options (thousands) | |
Outstanding at the beginning of the period (in shares) | 11,026,000 |
Granted (in shares) | 2,250,000 |
Exercised (in shares) | (734,000) |
Options forfeited/expired (in shares) | (138,000) |
Outstanding at the end of the period (in shares) | 12,404,000 |
Options Exercisable (in shares) | 8,189,000 |
Weighted Average Exercise Prices | |
Outstanding at the beginning of the period (in Canadian dollars per share) | $ / shares | $ 51.38 |
Granted (in Canadian dollars per share) | $ / shares | 56.89 |
Exercised (in Canadian dollars per share) | $ / shares | 42.65 |
Options forfeited/expired (in Canadian dollars per share) | $ / shares | 57.23 |
Outstanding at the end of the period (in Canadian dollars per share) | $ / shares | 52.83 |
Options Exercisable at December 31, 2017 (in Canadian dollars per share) | $ / shares | $ 50.72 |
Weighted Average Remaining Contractual Life (years) | |
Options Outstanding | 3 years 7 months 6 days |
Options Exercisable | 2 years 7 months 6 days |
Number of shares available for grant (in shares) | 9,790,373 |
Options expiration term | 7 years |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
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 ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan, Assumptions Used in Calculations [Abstract] | |||
Weighted average fair value (in dollars per share) | $ 5.80 | $ 7.22 | $ 5.67 |
Expected life | 5 years 8 months 12 days | 5 years 8 months 12 days | 5 years 9 months 18 days |
Interest rate | 2.10% | 1.20% | 0.70% |
Volatility | 16.00% | 18.00% | 21.00% |
Dividend yield | 4.20% | 3.60% | 4.90% |
Forfeiture rate | 0.00% | 0.00% | 5.00% |
Expense for stock options | $ 13 | $ 12 | $ 15 |
Unrecognized compensation costs related to non-vested stock options | $ 16 | ||
Employee Stock Option | |||
Defined Benefit Plan, Assumptions Used in Calculations [Abstract] | |||
Expense recognition period | 3 years |
COMMON SHARES - Summary of Addi
COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |||
Total intrinsic value of options exercised | $ 10 | $ 28 | $ 31 |
Fair value of options that have vested | $ 101 | $ 140 | $ 126 |
Total options vested (in shares) | 2.1 | 2.3 | 2.1 |
Options, exercisable, intrinsic value | $ 8 | ||
Options, outstanding, intrinsic value | $ 9 |
COMMON SHARES - Shareholder Rig
COMMON SHARES - Shareholder Rights Plan (Details) | Dec. 31, 2018shares |
Shareholder Rights Plan | |
Number of rights entitled to each common share (in shares) | 1 |
PREFERRED SHARES (Details)
PREFERRED SHARES (Details) - CAD ($) $ / shares in Units, $ in Millions | Dec. 31, 2015 | Nov. 30, 2016 | Apr. 30, 2016 | Feb. 29, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Preferred Shares [Line Items] | |||||||
Carrying value | $ 3,980 | $ 3,980 | $ 3,980 | ||||
Number of shares issued (in shares) | 60,200,000 | ||||||
Series 1 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 9,498,000 | ||||||
Current Yield | 3.266% | ||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | $ 0.8165 | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 233 | 233 | 233 | ||||
Series 1 | Government of Canada, Five-Year Bond Yield | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 1.92% | ||||||
Series 2 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 12,502,000 | ||||||
Current Yield | 3.633% | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 306 | 306 | 306 | ||||
Series 2 | Government of Canada, Treasury Bill Rate | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 1.92% | ||||||
Series 3 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 8,533,000 | ||||||
Current Yield | 2.152% | ||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | $ 0.538 | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 209 | 209 | 209 | ||||
Series 3 | Government of Canada, Five-Year Bond Yield | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 1.28% | ||||||
Series 4 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 5,467,000 | ||||||
Current Yield | 2.993% | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 134 | 134 | 134 | ||||
Series 4 | Government of Canada, Treasury Bill Rate | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 1.28% | ||||||
Series 5 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 12,714,000 | ||||||
Current Yield | 2.263% | ||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | $ 0.56575 | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 310 | 310 | 310 | ||||
Number of shares converted (in shares) | 1,285,739 | ||||||
Series 5 | Government of Canada, Five-Year Bond Yield | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 1.54% | ||||||
Series 6 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 1,286,000 | ||||||
Current Yield | 3.086% | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 32 | 32 | 32 | ||||
Series 6 | Government of Canada, Treasury Bill Rate | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 1.54% | ||||||
Series 7 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 24,000,000 | ||||||
Current Yield | 4.00% | ||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | $ 1 | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 589 | 589 | 589 | ||||
Series 7 | Government of Canada, Five-Year Bond Yield | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 2.38% | ||||||
Series 9 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 18,000,000 | ||||||
Current Yield | 4.25% | ||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | $ 1.0625 | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 442 | 442 | 442 | ||||
Series 9 | Government of Canada, Five-Year Bond Yield | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 2.35% | ||||||
Series 11 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 10,000,000 | ||||||
Current Yield | 3.80% | ||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | $ 0.95 | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 244 | 244 | 244 | ||||
Series 11 | Government of Canada, Five-Year Bond Yield | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 2.96% | ||||||
Series 13 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 20,000,000 | ||||||
Current Yield | 5.50% | ||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | $ 1.375 | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 493 | 493 | 493 | ||||
Number of shares issued (in shares) | 20,000,000 | ||||||
Price per share (in Canadian dollars per share) | $ 25 | ||||||
Gross proceeds from public offering of preferred shares | $ 500 | ||||||
Series 13 | Government of Canada, Five-Year Bond Yield | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 4.69% | ||||||
Preferred stock, fixed percentage added To Bond Or Treasury Bill rate for calculating dividend yield, minimum | 5.50% | ||||||
Series 15 | |||||||
Preferred Shares [Line Items] | |||||||
Preferred shares, outstanding (in shares) | 40,000,000 | ||||||
Current Yield | 4.90% | ||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | $ 1.225 | ||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25 | ||||||
Carrying value | $ 988 | $ 988 | $ 988 | ||||
Number of shares issued (in shares) | 40,000,000 | ||||||
Price per share (in Canadian dollars per share) | $ 25 | ||||||
Gross proceeds from public offering of preferred shares | $ 1,000 | ||||||
Series 15 | Government of Canada, Five-Year Bond Yield | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 3.85% | ||||||
Preferred stock, fixed percentage added To Bond Or Treasury Bill rate for calculating dividend yield, minimum | 4.90% | ||||||
Even numbered series of preferred shares | |||||||
Preferred Shares [Line Items] | |||||||
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum | 90 days | ||||||
Series 8 | Government of Canada, Treasury Bill Rate | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 2.38% | ||||||
Series 10 | Government of Canada, Treasury Bill Rate | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 2.35% | ||||||
Series 12 | Government of Canada, Treasury Bill Rate | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 2.96% | ||||||
Series 14 | Government of Canada, Treasury Bill Rate | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 4.69% | ||||||
Series 16 | Government of Canada, Treasury Bill Rate | |||||||
Preferred Shares [Line Items] | |||||||
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum | 3.85% | ||||||
Odd numbered series of preferred shares | |||||||
Preferred Shares [Line Items] | |||||||
Period of time preferred stock or bond is considered for dividend yield calculation | 5 years | ||||||
Series 2 and Series 4 and Series 6 | |||||||
Preferred Shares [Line Items] | |||||||
Redemption Price Per Share (in Canadian dollars per share) | $ 25.50 |
OTHER COMPREHENSIVE INCOME_(L_3
OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Before Tax Amount | |||
Other Comprehensive Income (Loss) | $ 1,259 | $ (957) | $ (29) |
Income Tax Recovery/(Expense) | |||
Other Comprehensive Income (Loss) | 55 | 31 | (3) |
Net of Tax Amount | |||
Other comprehensive income/(loss) (Note 22) | 1,314 | (926) | (32) |
Foreign currency translation gains on net investment in foreign operations | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | 1,323 | (746) | 3 |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 35 | (3) | 0 |
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | 1,358 | (749) | 3 |
Change in fair value of net investment hedges | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (57) | (77) | (14) |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 15 | 0 | 4 |
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | (42) | (77) | (10) |
Change in fair value and reclassification of gains and losses of cash flow hedges | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (14) | (3) | 44 |
Reclassification from accumulated other comprehensive Income | 27 | 3 | 71 |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 4 | 1 | (14) |
Reclassification from AOCI | (6) | 0 | (29) |
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | (10) | (2) | 30 |
Reclassification from accumulated other comprehensive income | 21 | 3 | 42 |
Unrealized actuarial gains and losses and reclassification of actuarial gains and losses of pension and other post-retirement benefits | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (153) | (14) | (38) |
Reclassification from accumulated other comprehensive Income | 20 | 21 | 22 |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 39 | 3 | 12 |
Reclassification from AOCI | (5) | (5) | (6) |
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | (114) | (11) | (26) |
Reclassification from accumulated other comprehensive income | 15 | 16 | 16 |
Other comprehensive income on equity investments | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | 113 | ||
Other Comprehensive Income (Loss) | (141) | (117) | |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | (27) | ||
Other Comprehensive Income (Loss) | 35 | 30 | |
Net of Tax Amount | |||
Other comprehensive income/(loss), before reclassifications | $ 86 | ||
Other comprehensive income/(loss) (Note 22) | $ (106) | $ (87) |
OTHER COMPREHENSIVE INCOME_(L_4
OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | $ 26,891 | $ 25,983 | |
Other comprehensive income/(loss) (Note 22) | 1,314 | (926) | $ (32) |
Balance at end of year | 30,993 | 26,891 | 25,983 |
Accumulated benefit obligation, (increase) decrease for settlement and curtailment | 27 | ||
Cash flow hedge loss reported in AOCI and expected to be reclassified to net income in the next 12 months, net of tax | 15 | ||
Cash flow hedge gain (loss) to be reclassified within twelve months, net of tax | (11) | ||
Currency Translation Adjustments | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (1,043) | (376) | (383) |
Other comprehensive income/(loss), before reclassifications | 1,150 | (590) | 7 |
Amounts reclassified from AOCI | 0 | (77) | 0 |
Other comprehensive income/(loss) (Note 22) | 1,150 | (667) | 7 |
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform | 0 | ||
Balance at end of year | 107 | (1,043) | (376) |
Cash Flow Hedges | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (31) | (28) | (97) |
Other comprehensive income/(loss), before reclassifications | (9) | (1) | 27 |
Amounts reclassified from AOCI | 16 | (2) | 42 |
Other comprehensive income/(loss) (Note 22) | 7 | (3) | 69 |
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform | 1 | ||
Balance at end of year | (23) | (31) | (28) |
Pension and Other Post-Retirement Benefit Plan Adjustments | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (203) | (208) | (198) |
Other comprehensive income/(loss), before reclassifications | (114) | (11) | (26) |
Amounts reclassified from AOCI | 15 | 16 | 16 |
Other comprehensive income/(loss) (Note 22) | (99) | 5 | (10) |
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform | (12) | ||
Balance at end of year | (314) | (203) | (208) |
Equity Investments | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (454) | (348) | (261) |
Other comprehensive income/(loss), before reclassifications | 72 | (117) | (101) |
Amounts reclassified from AOCI | 12 | 11 | 14 |
Other comprehensive income/(loss) (Note 22) | 84 | (106) | (87) |
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform | (6) | ||
Balance at end of year | (376) | (454) | (348) |
Accumulated Other Comprehensive Loss | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at beginning of year | (1,731) | (960) | (939) |
Other comprehensive income/(loss), before reclassifications | 1,099 | (719) | (93) |
Amounts reclassified from AOCI | 43 | (52) | 72 |
Other comprehensive income/(loss) (Note 22) | 1,142 | (771) | (21) |
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform | (17) | ||
Balance at end of year | (606) | (1,731) | (960) |
Accumulated foreign currency adjustment attributable to noncontrolling interest | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Other comprehensive income/(loss), before reclassifications | 166 | (159) | (14) |
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 | (1) | $ 4 | $ 3 |
Amounts reclassified from AOCI | 5 | ||
Accumulated net gain (loss) from equity investments attributable to noncontrolling interest | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Amounts reclassified from AOCI | $ 2 |
OTHER COMPREHENSIVE INCOME_(L_5
OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Revenues (Energy) | $ 13,679 | $ 13,449 | $ 12,547 |
Interest expense | (2,265) | (2,069) | (1,998) |
Plant operating costs and other | 3,591 | 3,906 | 3,861 |
Income from equity investments | 714 | 773 | 514 |
Gain/(loss) on assets held for sale/sold | 170 | 631 | (833) |
Total before tax | 3,949 | 3,306 | 837 |
Income tax expense | (432) | 89 | (352) |
Net Income Attributable to Common Shares | 3,539 | 2,997 | 124 |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Total before tax | (22) | 3 | (71) |
Income tax expense | 6 | (1) | 29 |
Net Income Attributable to Common Shares | (16) | 2 | (42) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges | Interest | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Interest expense | (18) | (17) | (14) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Amortization of actuarial gains and losses | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Plant operating costs and other | (16) | (15) | (22) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Settlement charge | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Plant operating costs and other | (4) | (2) | 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 | (20) | (17) | (22) |
Income tax expense | 5 | 5 | 6 |
Net Income Attributable to Common Shares | (15) | (12) | (16) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Equity investments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Income from equity investments | (16) | (15) | (19) |
Income tax expense | 4 | 4 | 5 |
Net Income Attributable to Common Shares | (12) | (11) | (14) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Currency translation adjustments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Gain/(loss) on assets held for sale/sold | 77 | 0 | |
Income tax expense | 0 | 0 | |
Net Income Attributable to Common Shares | 77 | 0 | |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Accumulated net gain (loss) from cash flow hedges attributable to noncontrolling interest | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Net Income Attributable to Common Shares | 5 | 0 | 0 |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Accumulated net gain (loss) from equity investments attributable to noncontrolling interest | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Net Income Attributable to Common Shares | 2 | 0 | 0 |
Energy | Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges | Commodities | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Revenues (Energy) | $ (4) | $ 20 | $ (57) |
EMPLOYEE POST-RETIREMENT BENE_3
EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments, Changes and Balance Sheet Presentation (Details) - CAD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
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 | $ 59 | $ 42 | $ 52 | |
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | ||||
Savings and DC Plans | 59 | 42 | 52 | |
Total cash contributions | 185 | 212 | $ 171 | |
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 | 3,816 | |||
Plan assets at fair value – end of year | 3,697 | 3,816 | ||
Amounts recognized in the Balance Sheet | ||||
Intangible and other assets (Note 12) | 192 | 193 | ||
Other long-term liabilities (Note 15) | $ (569) | $ (389) | ||
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 | 9 years | |
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | ||||
DB Plans and Other post-retirement benefit plans | $ 103 | $ 163 | $ 111 | |
Total amount outstanding under letters of credit | $ 17 | $ 27 | ||
Discount rate | 3.90% | 3.60% | ||
Remeasurement impact on unrealized actuarial gain (loss), recorded in regulated assets | $ 0 | $ (2) | 0 | |
Change in Benefit Obligation | ||||
Benefit obligation – beginning of year | 3,646 | 3,456 | ||
Service cost | 121 | 113 | ||
Interest cost | 134 | 135 | ||
Employee contributions | 5 | 5 | ||
Benefits paid | (177) | (166) | ||
Actuarial (gain)/loss | (92) | 253 | ||
Curtailment | 0 | (14) | ||
Settlement | (71) | (66) | ||
Foreign exchange rate changes | 87 | (70) | ||
Benefit obligation – end of year | 3,653 | 3,646 | 3,456 | |
Change in Plan Assets | ||||
Plan assets at fair value – beginning of year | 3,451 | 3,208 | ||
Actual return on plan assets | (73) | 358 | ||
Employer contributions | 103 | 163 | ||
Employee contributions | 5 | 5 | ||
Benefits paid | (176) | (166) | ||
Settlement | (71) | (57) | ||
Foreign exchange rate changes | 82 | (60) | ||
Plan assets at fair value – end of year | 3,321 | 3,451 | 3,208 | |
Funded Status – Plan Deficit | (332) | (195) | ||
Amounts recognized in the Balance Sheet | ||||
Intangible and other assets (Note 12) | 0 | 0 | ||
Accounts payable and other | (1) | (1) | ||
Other long-term liabilities (Note 15) | (331) | (194) | ||
Net | (332) | (195) | ||
Other Post-Retirement Benefit Plans | ||||
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | ||||
DB Plans and Other post-retirement benefit plans | $ 23 | $ 7 | 8 | |
Discount rate | 4.10% | 3.70% | ||
Remeasurement impact on unrealized actuarial gain (loss), recorded in regulated assets | $ 0 | $ 0 | 0 | |
Change in Benefit Obligation | ||||
Benefit obligation – beginning of year | 375 | 372 | ||
Service cost | 4 | 4 | ||
Interest cost | 14 | 14 | ||
Employee contributions | 0 | 3 | ||
Benefits paid | (23) | (19) | ||
Actuarial (gain)/loss | 43 | 19 | ||
Curtailment | 0 | (2) | ||
Settlement | 0 | 0 | ||
Foreign exchange rate changes | 17 | (16) | ||
Benefit obligation – end of year | 430 | 375 | 372 | |
Change in Plan Assets | ||||
Plan assets at fair value – beginning of year | 365 | 354 | ||
Actual return on plan assets | (15) | 45 | ||
Employer contributions | 23 | 7 | ||
Employee contributions | 0 | 3 | ||
Benefits paid | (27) | (19) | ||
Settlement | 0 | 0 | ||
Foreign exchange rate changes | 30 | (25) | ||
Plan assets at fair value – end of year | 376 | 365 | 354 | |
Funded Status – Plan Deficit | (54) | (10) | ||
Amounts recognized in the Balance Sheet | ||||
Intangible and other assets (Note 12) | 192 | 193 | ||
Accounts payable and other | (8) | (8) | ||
Other long-term liabilities (Note 15) | (238) | (195) | ||
Net | (54) | (10) | ||
Canadian | Pension Benefit Plans | ||||
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | ||||
Letter of credit to the DB Plan | 17 | 27 | $ 20 | |
Total amount outstanding under letters of credit | 277 | |||
U.S. | Pension Benefit Plans | ||||
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract] | ||||
Other comprehensive income (loss), defined benefit plan, settlement and curtailment gain (loss) | 4 | 3 | ||
Net periodic benefit cost (credit), gain (loss) due to settlement | $ (4) | $ (2) | ||
Discount rate | 4.10% | |||
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 | $ 16 | |||
Remeasurement impact on unrealized actuarial gain (loss), recorded in regulated assets | 14 | |||
Remeasurement impact recorded in OCI | $ 2 |
EMPLOYEE POST-RETIREMENT BENE_4
EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Plan assets at fair value | $ 3,697 | $ 3,816 | |
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 | $ (3,653) | $ (3,646) | $ (3,456) |
Plan assets at fair value | 3,321 | 3,451 | 3,208 |
Funded Status – Plan Deficit | (332) | (195) | |
Funded status based on accumulated benefit obligation | |||
Accumulated benefit obligation | (3,347) | (3,372) | |
Plan assets at fair value | 3,321 | 3,451 | |
Funded Status | $ (26) | $ 79 | |
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 | 33.00% | 30.00% | |
Company debt or common shares included in plan assets, amount | $ 8 | $ 7 | |
Company debt or common shares included in plan assets, percentage | 0.30% | 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 | 45.00% | ||
Pension Benefit Plans | Equity securities | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 56.00% | 64.00% | |
Company debt or common shares included in plan assets, amount | $ 7 | $ 3 | |
Company debt or common shares included in plan assets, percentage | 0.20% | 0.10% | |
Pension Benefit Plans | Equity securities | Minimum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 40.00% | ||
Pension Benefit Plans | Equity securities | Maximum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 70.00% | ||
Pension Benefit Plans | Alternatives | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 11.00% | 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% | ||
Pension Benefit Plans | Not fully funded | |||
Benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Projected benefit obligation | $ (3,653) | $ (3,646) | |
Plan assets at fair value | 3,321 | 3,451 | |
Funded Status – Plan Deficit | (332) | (195) | |
Funded status based on accumulated benefit obligation | |||
Accumulated benefit obligation | (3,347) | (944) | |
Plan assets at fair value | 3,321 | 925 | |
Funded Status | (26) | (19) | |
Other Post-Retirement Benefit Plans | |||
Benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Projected benefit obligation | (430) | (375) | (372) |
Plan assets at fair value | 376 | 365 | $ 354 |
Funded Status – Plan Deficit | (54) | (10) | |
Other Post-Retirement Benefit Plans | Not fully funded | |||
Benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Projected benefit obligation | (246) | (203) | |
Plan assets at fair value | 0 | 0 | |
Funded Status – Plan Deficit | $ (246) | $ (203) |
EMPLOYEE POST-RETIREMENT BENE_5
EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Employee post-retirement benefits | |||
Fair value of plan assets | $ 3,697 | $ 3,816 | |
Percentage of Total Portfolio | 100.00% | 100.00% | |
Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 1,817 | $ 1,186 | |
Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 1,518 | 2,414 | |
Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 362 | 216 | $ 199 |
Cash and Cash Equivalents | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 48 | $ 61 | |
Percentage of Total Portfolio | 1.00% | 2.00% | |
Cash and Cash Equivalents | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 48 | $ 44 | |
Cash and Cash Equivalents | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 17 | |
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 | $ 493 | $ 561 | |
Percentage of Total Portfolio | 13.00% | 15.00% | |
Equity Securities, Canadian | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 355 | $ 410 | |
Equity Securities, Canadian | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 138 | 151 | |
Equity Securities, Canadian | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity Securities, U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 576 | $ 897 | |
Percentage of Total Portfolio | 16.00% | 24.00% | |
Equity Securities, U.S. | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 460 | $ 543 | |
Equity Securities, U.S. | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 116 | 354 | |
Equity Securities, U.S. | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity Securities, International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 321 | $ 367 | |
Percentage of Total Portfolio | 9.00% | 10.00% | |
Equity Securities, International | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 40 | $ 45 | |
Equity Securities, International | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 281 | 322 | |
Equity Securities, International | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity Securities, Global | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 384 | $ 301 | |
Percentage of Total Portfolio | 10.00% | 8.00% | |
Equity Securities, Global | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 116 | $ 0 | |
Equity Securities, Global | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 268 | 301 | |
Equity Securities, Global | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity Securities, Emerging | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 146 | $ 155 | |
Percentage of Total Portfolio | 4.00% | 4.00% | |
Equity Securities, Emerging | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 8 | $ 8 | |
Equity Securities, Emerging | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 138 | 147 | |
Equity Securities, Emerging | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, Canadian Bonds, Federal | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 186 | $ 193 | |
Percentage of Total Portfolio | 5.00% | 5.00% | |
Fixed Income Securities, Canadian Bonds, Federal | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 0 | |
Fixed Income Securities, Canadian Bonds, Federal | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 186 | 193 | |
Fixed Income Securities, Canadian Bonds, Federal | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, Canadian Bonds, Provincial | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 198 | $ 194 | |
Percentage of Total Portfolio | 5.00% | 5.00% | |
Fixed Income Securities, Canadian Bonds, Provincial | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 0 | |
Fixed Income Securities, Canadian Bonds, Provincial | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 198 | 194 | |
Fixed Income Securities, Canadian Bonds, Provincial | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, Canadian Bonds, Municipal | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 8 | $ 8 | |
Percentage of Total Portfolio | 1.00% | 0.00% | |
Fixed Income Securities, Canadian Bonds, Municipal | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 0 | |
Fixed Income Securities, Canadian Bonds, Municipal | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 8 | 8 | |
Fixed Income Securities, Canadian Bonds, Municipal | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, Canadian Bonds, Corporate | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 112 | $ 122 | |
Percentage of Total Portfolio | 3.00% | 3.00% | |
Fixed Income Securities, Canadian Bonds, Corporate | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 0 | |
Fixed Income Securities, Canadian Bonds, Corporate | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 112 | 122 | |
Fixed Income Securities, Canadian Bonds, Corporate | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, U.S. Bonds, Federal | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 350 | $ 244 | |
Percentage of Total Portfolio | 9.00% | 6.00% | |
Fixed Income Securities, U.S. Bonds, Federal | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 350 | $ 0 | |
Fixed Income Securities, U.S. Bonds, Federal | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 244 | |
Fixed Income Securities, U.S. Bonds, Federal | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, U.S. Bonds, State | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 41 | |
Percentage of Total Portfolio | 0.00% | 1.00% | |
Fixed Income Securities, U.S. Bonds, State | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 0 | |
Fixed Income Securities, U.S. Bonds, State | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 41 | |
Fixed Income Securities, U.S. Bonds, State | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, U.S. Bonds, Municipal | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 4 | |
Percentage of Total Portfolio | 0.00% | 0.00% | |
Fixed Income Securities, U.S. Bonds, Municipal | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 0 | |
Fixed Income Securities, U.S. Bonds, Municipal | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 4 | |
Fixed Income Securities, U.S. Bonds, Municipal | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, U.S. Bonds, Corporate | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 196 | $ 234 | |
Percentage of Total Portfolio | 5.00% | 6.00% | |
Fixed Income Securities, U.S. Bonds, Corporate | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 145 | $ 0 | |
Fixed Income Securities, U.S. Bonds, Corporate | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 51 | 234 | |
Fixed Income Securities, U.S. Bonds, Corporate | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, International, Government | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 10 | $ 4 | |
Percentage of Total Portfolio | 1.00% | 0.00% | |
Fixed Income Securities, International, Government | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 6 | $ 0 | |
Fixed Income Securities, International, Government | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 4 | 4 | |
Fixed Income Securities, International, Government | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, International, Corporate | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 37 | $ 5 | |
Percentage of Total Portfolio | 1.00% | 0.00% | |
Fixed Income Securities, International, Corporate | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 19 | $ 0 | |
Fixed Income Securities, International, Corporate | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 18 | 5 | |
Fixed Income Securities, International, Corporate | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Fixed Income Securities, International, Mortgage-backed | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 128 | $ 73 | |
Percentage of Total Portfolio | 3.00% | 2.00% | |
Fixed Income Securities, International, Mortgage-backed | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 128 | $ 0 | |
Fixed Income Securities, International, Mortgage-backed | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 73 | |
Fixed Income Securities, International, Mortgage-backed | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Real estate | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 196 | $ 140 | |
Percentage of Total Portfolio | 5.00% | 4.00% | |
Real estate | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 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 | 196 | 140 | |
Infrastructure | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 163 | $ 70 | |
Percentage of Total Portfolio | 4.00% | 2.00% | |
Infrastructure | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 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 | 163 | 70 | |
Private equity funds | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 3 | $ 6 | |
Percentage of Total Portfolio | 1.00% | 0.00% | |
Private equity funds | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 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 | 3 | 6 | |
Funds held on deposit | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 142 | $ 136 | |
Percentage of Total Portfolio | 4.00% | 3.00% | |
Funds held on deposit | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 142 | $ 136 | |
Funds held on deposit | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Funds held on deposit | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | $ 0 | $ 0 |
EMPLOYEE POST-RETIREMENT BENE_6
EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Net change in the Level III fair value category | ||
Plan assets at fair value – beginning of year | $ 3,816 | |
Plan assets at fair value – end of year | 3,697 | $ 3,816 |
Significant Unobservable Inputs (Level III) | ||
Net change in the Level III fair value category | ||
Plan assets at fair value – beginning of year | 216 | 199 |
Purchases and sales | 127 | 11 |
Realized and unrealized gains | 19 | 6 |
Plan assets at fair value – end of year | $ 362 | $ 216 |
EMPLOYEE POST-RETIREMENT BENE_7
EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Other post-retirement benefit plans, Savings Plan and DC Plans | |||
Company's expected funding contributions for savings plan and DC Plans | $ 61 | ||
Health care benefits | |||
Assumed average annual rate of increase in the per capita cost of covered health care benefits | 6.00% | ||
Percentage level to which average annual rate was assumed to decrease | 4.50% | ||
Effects of a one per cent change in assumed health care cost trend rates | |||
Effect on total of service and interest cost components, Increase | $ 1 | ||
Effect on total of service and interest cost components, Decrease | (1) | ||
Effect on post-retirement benefit obligation, Increase | 25 | ||
Effect on post-retirement benefit obligation, Decrease | (21) | ||
Pension Benefit Plans | |||
DB Plans | |||
Company's expected funding contributions | 113 | ||
Other post-retirement benefit plans, Savings Plan and DC Plans | |||
Expected estimated additional letter of credit | 17 | ||
Estimated future benefit payments, which reflect expected future service | |||
2,019 | 190 | ||
2,020 | 193 | ||
2,021 | 198 | ||
2,022 | 203 | ||
2,023 | 207 | ||
2024 to 2028 | $ 1,081 | ||
Weighted average actuarial assumptions adopted in measuring the benefit obligations | |||
Discount rate | 3.90% | 3.60% | |
Rate of compensation increase | 3.00% | 3.00% | |
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs | |||
Discount rate | 3.60% | 3.95% | 4.20% |
Expected long-term rate of return on plan assets | 6.70% | 6.50% | 6.70% |
Rate of compensation increase | 3.00% | 1.20% | 0.80% |
Net benefit cost | |||
Service cost | $ 121 | $ 108 | $ 107 |
Other components of net benefit cost | |||
Interest cost | 134 | 122 | 127 |
Expected return on plan assets | (221) | (178) | (175) |
Amortization of actuarial loss | 15 | 14 | 20 |
Amortization of regulatory asset | 18 | 37 | 27 |
Amortization of transitional obligation related to regulated business | 0 | 0 | 0 |
Settlement charge – regulatory asset | 0 | 2 | 0 |
Settlement charge – AOCI | 4 | 2 | 0 |
Other components of net benefit cost | (50) | (1) | (1) |
Net Benefit Cost Recognized | 71 | 107 | 106 |
Pre-tax amounts recognized in AOCI | |||
Net loss | 364 | 273 | 270 |
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year | |||
Estimated net loss that will be amortized | 12 | ||
Pre-tax amounts recognized in OCI | |||
Amortization of net loss from AOCI to net income | (15) | (18) | (20) |
Curtailment | 0 | (14) | 0 |
Settlement | (4) | (11) | 0 |
Funded status adjustment | 110 | 46 | 43 |
Total pre-tax amounts recognized in OCI | 91 | $ 3 | $ 23 |
Other Post-Retirement Benefit Plans | |||
DB Plans | |||
Company's expected funding contributions | 7 | ||
Estimated future benefit payments, which reflect expected future service | |||
2,019 | 24 | ||
2,020 | 23 | ||
2,021 | 23 | ||
2,022 | 23 | ||
2,023 | 23 | ||
2024 to 2028 | $ 114 | ||
Weighted average actuarial assumptions adopted in measuring the benefit obligations | |||
Discount rate | 4.10% | 3.70% | |
Rate of compensation increase | 0.00% | 0.00% | |
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs | |||
Discount rate | 3.70% | 4.15% | 4.30% |
Expected long-term rate of return on plan assets | 4.00% | 6.05% | 5.95% |
Rate of compensation increase | 0.00% | 0.00% | 0.00% |
Net benefit cost | |||
Service cost | $ 4 | $ 4 | $ 3 |
Other components of net benefit cost | |||
Interest cost | 14 | 14 | 13 |
Expected return on plan assets | (16) | (21) | (11) |
Amortization of actuarial loss | 1 | 1 | 2 |
Amortization of regulatory asset | 0 | 1 | 1 |
Amortization of transitional obligation related to regulated business | 0 | 0 | 2 |
Settlement charge – regulatory asset | 0 | 0 | 0 |
Settlement charge – AOCI | 0 | 0 | 0 |
Other components of net benefit cost | (1) | (5) | 7 |
Net Benefit Cost Recognized | 3 | (1) | 10 |
Pre-tax amounts recognized in AOCI | |||
Net loss | 53 | 11 | 21 |
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year | |||
Estimated net loss that will be amortized | 2 | ||
Pre-tax amounts recognized in OCI | |||
Amortization of net loss from AOCI to net income | (1) | (1) | (2) |
Curtailment | 0 | (2) | 0 |
Settlement | 0 | 0 | 0 |
Funded status adjustment | 43 | (7) | (5) |
Total pre-tax amounts recognized in OCI | $ 42 | $ (10) | $ (7) |
RISK MANAGEMENT AND FINANCIAL_3
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) $ in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Derivative [Line Items] | ||||
Fair Value | $ (166) | $ (54) | ||
Designated as a net investment hedge | ||||
Derivative [Line Items] | ||||
Fair Value | (90) | (194) | ||
Designated as a net investment hedge | US$ denominated | ||||
Derivative [Line Items] | ||||
Notional Amount | $ 2,800 | $ 1,700 | ||
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2019) | ||||
Derivative [Line Items] | ||||
Fair Value | (43) | (199) | ||
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2019) | US$ denominated | ||||
Derivative [Line Items] | ||||
Notional Amount | 300 | 1,200 | ||
Net realized gains related to the interest component | 2 | 4 | ||
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2019 to 2020) | ||||
Derivative [Line Items] | ||||
Fair Value | $ (47) | $ 5 | ||
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2019 to 2020) | US$ denominated | ||||
Derivative [Line Items] | ||||
Notional Amount | $ 2,500 | $ 500 |
RISK MANAGEMENT AND FINANCIAL_4
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge $ in Millions, $ in Millions | Dec. 31, 2018CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2017USD ($) |
Derivative [Line Items] | ||||
Notional amount | $ 31,000 | $ 25,400 | ||
Fair value | $ 31,700 | $ 28,900 | ||
US$ denominated | ||||
Derivative [Line Items] | ||||
Notional amount | $ 22,700 | $ 20,200 | ||
Fair value | $ 23,200 | $ 23,100 |
RISK MANAGEMENT AND FINANCIAL_5
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Concentration Risk [Line Items] | ||
Financing receivable, recorded investment, past due | $ 0 | $ 0 |
Provision for other credit losses | 0 | 0 |
Customer Concentration Risk | ||
Concentration Risk [Line Items] | ||
Credit risk concentration | $ 0 | $ 0 |
RISK MANAGEMENT AND FINANCIAL_6
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) $ in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Carrying and fair values of non-derivative financial instruments | ||||
Long-term debt, including current portion (Note 17) | $ (39,982) | $ (34,677) | ||
Junior subordinated notes (Note 18) | (7,508) | (7,007) | ||
Long-term debt | $ 750 | $ 1,100 | ||
Interest rate swap agreements | ||||
Carrying and fair values of non-derivative financial instruments | ||||
Unrealized gains (losses) on hedged items | (2) | 4 | ||
Long-term debt hedged | $ 750 | $ 1,100 | ||
Level II | Carrying Amount | ||||
Carrying and fair values of non-derivative financial instruments | ||||
Long-term debt, including current portion (Note 17) | (39,971) | (34,741) | ||
Junior subordinated notes (Note 18) | (7,508) | (7,007) | ||
Total liabilities | (47,479) | (41,748) | ||
Level II | Fair Value | ||||
Carrying and fair values of non-derivative financial instruments | ||||
Long-term debt, including current portion (Note 17) | (42,284) | (40,180) | ||
Junior subordinated notes (Note 18) | (6,665) | (7,233) | ||
Total liabilities | $ (48,949) | $ (47,413) |
RISK MANAGEMENT AND FINANCIAL_7
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Total Derivatives | |||
Derivative Assets | $ 798 | $ 405 | |
Derivative Liabilities | (964) | (459) | |
Total Derivatives | (166) | (54) | |
Total trading activity | |||
Total Derivatives | |||
Derivative Assets | 767 | 389 | |
Derivative Liabilities | (838) | (244) | |
Total Derivatives | (71) | 145 | |
Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Assets | 13 | 8 | |
Derivative Liabilities | (15) | (8) | |
Total Derivatives | (2) | 0 | |
Fair Value Hedges | |||
Total Derivatives | |||
Derivative Assets | 1 | 0 | |
Derivative Liabilities | (4) | (5) | |
Total Derivatives | (3) | (5) | |
Net Investment Hedges | |||
Total Derivatives | |||
Derivative Assets | 17 | 8 | |
Derivative Liabilities | (107) | (202) | |
Total Derivatives | (90) | (194) | |
Foreign exchange | |||
Total Derivatives | |||
Derivative Assets | 18 | 78 | |
Derivative Liabilities | (295) | (212) | |
Interest rate | |||
Total Derivatives | |||
Derivative Assets | 12 | 8 | |
Derivative Liabilities | (15) | (5) | |
Other current assets | |||
Total Derivatives | |||
Derivative Assets | 737 | 332 | |
Other current assets | Total trading activity | |||
Total Derivatives | |||
Derivative Assets | 717 | 320 | |
Other current assets | Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Assets | 4 | 4 | |
Other current assets | Fair Value Hedges | |||
Total Derivatives | |||
Derivative Assets | 0 | 0 | |
Other current assets | Net Investment Hedges | |||
Total Derivatives | |||
Derivative Assets | 16 | 8 | |
Other current assets | Commodities | |||
Total Derivatives | |||
Derivative Assets | 717 | 250 | |
Other current assets | Commodities | Commodities | |||
Total Derivatives | |||
Derivative Assets | 716 | 249 | |
Other current assets | Commodities | Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Assets | 1 | 1 | |
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 | 17 | 78 | |
Other current assets | Foreign exchange | Foreign exchange | |||
Total Derivatives | |||
Derivative Assets | 1 | 70 | |
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 | 16 | 8 | |
Other current assets | Interest rate | |||
Total Derivatives | |||
Derivative Assets | 3 | 4 | |
Other current assets | Interest rate | Interest rate | |||
Total Derivatives | |||
Derivative Assets | 0 | 1 | |
Other current assets | Interest rate | Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Assets | 3 | 3 | |
Other current assets | Interest rate | Fair Value Hedges | |||
Total Derivatives | |||
Derivative Assets | 0 | 0 | |
Other current assets | Interest rate | Net Investment Hedges | |||
Total Derivatives | |||
Derivative Assets | 0 | 0 | |
Intangible and other assets | |||
Total Derivatives | |||
Derivative Assets | 61 | 73 | |
Intangible and other assets | Total trading activity | |||
Total Derivatives | |||
Derivative Assets | 50 | 69 | |
Intangible and other assets | Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Assets | 9 | 4 | |
Intangible and other assets | Fair Value Hedges | |||
Total Derivatives | |||
Derivative Assets | 1 | 0 | |
Intangible and other assets | Net Investment Hedges | |||
Total Derivatives | |||
Derivative Assets | 1 | 0 | |
Intangible and other assets | Commodities | |||
Total Derivatives | |||
Derivative Assets | 51 | 69 | |
Intangible and other assets | Commodities | Commodities | |||
Total Derivatives | |||
Derivative Assets | 50 | 69 | |
Intangible and other assets | Commodities | Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Assets | 1 | 0 | |
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 | 1 | ||
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 | 1 | ||
Intangible and other assets | Interest rate | |||
Total Derivatives | |||
Derivative Assets | 9 | 4 | |
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 | 8 | 4 | |
Intangible and other assets | Interest rate | Fair Value Hedges | |||
Total Derivatives | |||
Derivative Assets | 1 | 0 | |
Intangible and other assets | Interest rate | Net Investment Hedges | |||
Total Derivatives | |||
Derivative Assets | 0 | 0 | |
Accounts payable and other | |||
Total Derivatives | |||
Derivative Liabilities | (922) | (387) | |
Accounts payable and other | Total trading activity | |||
Total Derivatives | |||
Derivative Liabilities | (810) | (218) | |
Accounts payable and other | Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Liabilities | (4) | (6) | |
Accounts payable and other | Fair Value Hedges | |||
Total Derivatives | |||
Derivative Liabilities | (3) | (4) | |
Accounts payable and other | Net Investment Hedges | |||
Total Derivatives | |||
Derivative Liabilities | (105) | (159) | |
Accounts payable and other | Commodities | |||
Total Derivatives | |||
Derivative Liabilities | (626) | (214) | |
Accounts payable and other | Commodities | Commodities | |||
Total Derivatives | |||
Derivative Liabilities | (622) | (208) | |
Accounts payable and other | Commodities | Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Liabilities | (4) | (6) | |
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 | (293) | (169) | |
Accounts payable and other | Foreign exchange | Foreign exchange | |||
Total Derivatives | |||
Derivative Liabilities | (188) | (10) | |
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 | (105) | (159) | |
Accounts payable and other | Interest rate | |||
Total Derivatives | |||
Derivative Liabilities | (3) | (4) | |
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 | 0 | |
Accounts payable and other | Interest rate | Fair Value Hedges | |||
Total Derivatives | |||
Derivative Liabilities | (3) | (4) | |
Accounts payable and other | Interest rate | Net Investment Hedges | |||
Total Derivatives | |||
Derivative Liabilities | 0 | 0 | |
Other long-term liabilities | |||
Total Derivatives | |||
Derivative Liabilities | (42) | (72) | |
Other long-term liabilities | Total trading activity | |||
Total Derivatives | |||
Derivative Liabilities | (28) | (26) | |
Other long-term liabilities | Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Liabilities | (11) | (2) | |
Other long-term liabilities | Fair Value Hedges | |||
Total Derivatives | |||
Derivative Liabilities | (1) | (1) | |
Other long-term liabilities | Net Investment Hedges | |||
Total Derivatives | |||
Derivative Liabilities | (2) | (43) | |
Other long-term liabilities | Commodities | |||
Total Derivatives | |||
Derivative Liabilities | (28) | (28) | |
Other long-term liabilities | Commodities | Commodities | |||
Total Derivatives | |||
Derivative Liabilities | (28) | (26) | |
Other long-term liabilities | Commodities | Cash Flow Hedges | |||
Total Derivatives | |||
Derivative Liabilities | 0 | (2) | |
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 | (2) | (43) | |
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 | (2) | (43) | |
Other long-term liabilities | Interest rate | |||
Total Derivatives | |||
Derivative Liabilities | (12) | (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 | (11) | 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 gains/(losses) | 11 | (3) | $ (28) |
Net realized losses | (4) | (1) | 0 |
Other Restricted Investments | |||
Gain (Loss) on Investments, Realized and Unrealized | |||
Net unrealized gains/(losses) | 0 | 1 | (1) |
Net realized losses | 0 | 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) | 140 | 14 | |
Fixed income securities (maturing after 10 years) | 952 | 790 | |
Fixed income securities | 1,092 | 804 | |
Fixed income securities | Other Restricted Investments | |||
Fair value | |||
Fixed income securities (maturing within 1 year) | 22 | 23 | |
Fixed income securities (maturing within 1-5 years) | 110 | 107 | |
Fixed income securities (maturing within 5-10 years) | 0 | 0 | |
Fixed income securities (maturing after 10 years) | 0 | 0 | |
Fixed income securities | $ 132 | $ 130 |
RISK MANAGEMENT AND FINANCIAL_8
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Fair Value Hedging Relationships (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Fair value hedging adjustments, discontinued hedges | $ 0 | $ 0 |
Current portion of long-term debt | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Carrying amount | (748) | (688) |
Fair value hedging adjustments | 3 | 1 |
Long-term debt | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Carrying amount | (273) | (685) |
Fair value hedging adjustments | 0 | 4 |
Long-term debt, including current portion | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Carrying amount | (1,021) | (1,373) |
Fair value hedging adjustments | $ 3 | $ 5 |
RISK MANAGEMENT AND FINANCIAL_9
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional and Maturity Summary (Details) $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)GWhBcfMMBbls | Dec. 31, 2017MXN ($)GWhBcfMMBbls | Dec. 31, 2017USD ($) | |
Commodities | Power | Purchases | |||
Derivative [Line Items] | |||
Notional amount, energy (gwh) | GWh | 23,865 | 66,132 | |
Commodities | Power | Sales | |||
Derivative [Line Items] | |||
Notional amount, energy (gwh) | GWh | 17,689 | 42,836 | |
Commodities | Natural Gas | Purchases | |||
Derivative [Line Items] | |||
Notional amount, volume (bcf and mmbbls) | Bcf | 44 | 133 | |
Commodities | Natural Gas | Sales | |||
Derivative [Line Items] | |||
Notional amount, volume (bcf and mmbbls) | Bcf | 56 | 135 | |
Commodities | Liquids | Purchases | |||
Derivative [Line Items] | |||
Notional amount, volume (bcf and mmbbls) | MMBbls | 59 | 6 | |
Commodities | Liquids | Sales | |||
Derivative [Line Items] | |||
Notional amount, volume (bcf and mmbbls) | MMBbls | 79 | 7 | |
Foreign exchange | |||
Derivative [Line Items] | |||
Notional amount | $ 3,862 | $ 100 | $ 2,931 |
Interest rate | |||
Derivative [Line Items] | |||
Notional amount | $ | $ 1,650 | $ 2,300 |
RISK MANAGEMENT AND FINANCIA_10
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses)/Gains (Details) - CAD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
U.S. Northeast Merchant Power Assets | |||
Derivative [Line Items] | |||
Gain (loss) on cash flow hedge | $ 0 | $ 0 | $ (42,000,000) |
Commodities | |||
Derivative [Line Items] | |||
Amount of unrealized gains/(losses) in the year | 28,000,000 | 62,000,000 | 123,000,000 |
Amount of realized gains/(losses) in the year | 351,000,000 | (107,000,000) | (204,000,000) |
Commodities | Derivative instruments in hedging relationships | |||
Derivative [Line Items] | |||
Amount of realized (losses)/gains in the year | (1,000,000) | 23,000,000 | (167,000,000) |
Foreign exchange | |||
Derivative [Line Items] | |||
Amount of unrealized gains/(losses) in the year | (248,000,000) | 88,000,000 | 25,000,000 |
Amount of realized gains/(losses) in the year | (24,000,000) | 18,000,000 | 62,000,000 |
Foreign exchange | Derivative instruments in hedging relationships | |||
Derivative [Line Items] | |||
Amount of realized (losses)/gains in the year | 0 | 5,000,000 | (101,000,000) |
Interest rate | |||
Derivative [Line Items] | |||
Amount of unrealized gains/(losses) in the year | 0 | (1,000,000) | 0 |
Amount of realized gains/(losses) in the year | 0 | 1,000,000 | 0 |
Interest rate | Derivative instruments in hedging relationships | |||
Derivative [Line Items] | |||
Amount of realized (losses)/gains in the year | $ (1,000,000) | $ 1,000,000 | $ 4,000,000 |
RISK MANAGEMENT AND FINANCIA_11
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - Cash Flow Hedges - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Components of OCI related to derivatives | |||
Change in fair value of derivative instruments recognized in OCI (effective portion) | $ (14) | $ 3 | $ 44 |
Commodities | Power | |||
Components of OCI related to derivatives | |||
Change in fair value of derivative instruments recognized in OCI (effective portion) | (1) | (1) | 39 |
Interest rate | |||
Components of OCI related to derivatives | |||
Change in fair value of derivative instruments recognized in OCI (effective portion) | $ (13) | $ 4 | $ 5 |
RISK MANAGEMENT AND FINANCIA_12
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effect of Fair Value and Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Revenues (Energy) | $ 13,679 | $ 13,449 | $ 12,547 |
Interest Expense | (2,265) | (2,069) | (1,998) |
Energy | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Revenues (Energy) | 2,124 | 3,593 | 4,206 |
Interest Expense | Interest rate contracts | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Hedged items | (71) | (74) | (74) |
Derivatives designated as hedging instruments | (4) | 1 | 8 |
Reclassification of gains/(losses) on derivative instruments from AOCI to net income | 22 | 17 | 14 |
Revenue | Commodity contracts | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Reclassification of gains/(losses) on derivative instruments from AOCI to net income | $ 5 | $ (20) | $ 57 |
RISK MANAGEMENT AND FINANCIA_13
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative – Asset | ||
Gross Derivative Instruments | $ 798 | $ 405 |
Amounts Available for Offset | (648) | (255) |
Net Amounts | 150 | 150 |
Derivative – Liability | ||
Gross Derivative Instruments | (964) | (459) |
Amounts Available for Offset | 648 | 255 |
Net Amounts | (316) | (204) |
Cash collateral provided by the Company | 143 | 165 |
Letters of credit provided by the Company | 22 | 30 |
Cash collateral received by the Company | 0 | 0 |
Letters of credit received by the Company | 1 | 3 |
Credit Risk Related Contingent Features | ||
Aggregate fair value of derivative instruments in a net liability position | 6 | 2 |
Additional collateral required if credit-risk-related contingent features were triggered | 6 | 2 |
Foreign exchange | ||
Derivative – Asset | ||
Gross Derivative Instruments | 18 | 78 |
Amounts Available for Offset | (18) | (56) |
Net Amounts | 0 | 22 |
Derivative – Liability | ||
Gross Derivative Instruments | (295) | (212) |
Amounts Available for Offset | 18 | 56 |
Net Amounts | (277) | (156) |
Interest rate | ||
Derivative – Asset | ||
Gross Derivative Instruments | 12 | 8 |
Amounts Available for Offset | (4) | (1) |
Net Amounts | 8 | 7 |
Derivative – Liability | ||
Gross Derivative Instruments | (15) | (5) |
Amounts Available for Offset | 4 | 1 |
Net Amounts | (11) | (4) |
Power | Commodities | ||
Derivative – Asset | ||
Gross Derivative Instruments | 768 | 319 |
Amounts Available for Offset | (626) | (198) |
Net Amounts | 142 | 121 |
Derivative – Liability | ||
Gross Derivative Instruments | (654) | (242) |
Amounts Available for Offset | 626 | 198 |
Net Amounts | $ (28) | $ (44) |
RISK MANAGEMENT AND FINANCIA_14
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value Hierarchy | ||
Derivative Instrument Assets: | $ 798 | $ 405 |
Derivative Instrument Liabilities: | (964) | (459) |
Commodities | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 768 | 319 |
Derivative Instrument Liabilities: | (654) | (242) |
Foreign exchange | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 18 | 78 |
Derivative Instrument Liabilities: | (295) | (212) |
Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 12 | 8 |
Derivative Instrument Liabilities: | (15) | (5) |
Recurring basis | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | (166) | (54) |
Recurring basis | Commodities | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 768 | 319 |
Derivative Instrument Liabilities: | (654) | (242) |
Recurring basis | Foreign exchange | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 18 | 78 |
Derivative Instrument Liabilities: | (295) | (212) |
Recurring basis | Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 12 | 8 |
Derivative Instrument Liabilities: | (15) | (5) |
Recurring basis | Quoted Prices in Active Markets (Level I) | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | 26 | (6) |
Recurring basis | Quoted Prices in Active Markets (Level I) | Commodities | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 581 | 21 |
Derivative Instrument Liabilities: | (555) | (27) |
Recurring basis | Quoted Prices in Active Markets (Level I) | Foreign exchange | ||
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 | (188) | (41) |
Recurring basis | Significant Other Observable Inputs (Level II) | Commodities | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 187 | 283 |
Derivative Instrument Liabilities: | (95) | (193) |
Recurring basis | Significant Other Observable Inputs (Level II) | Foreign exchange | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 18 | 78 |
Derivative Instrument Liabilities: | (295) | (212) |
Recurring basis | Significant Other Observable Inputs (Level II) | Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 12 | 8 |
Derivative Instrument Liabilities: | (15) | (5) |
Recurring basis | Significant Unobservable Inputs (Level III) | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | (4) | (7) |
Recurring basis | Significant Unobservable Inputs (Level III) | Commodities | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 0 | 15 |
Derivative Instrument Liabilities: | (4) | (22) |
Recurring basis | Significant Unobservable Inputs (Level III) | Foreign exchange | ||
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: | $ 0 | $ 0 |
RISK MANAGEMENT AND FINANCIA_15
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue | ||
Net change in the Level III fair value category | ||
Unrealized gains (losses) attributed to derivatives in the Level III category | $ (5) | $ (7) |
Commodity contracts | Power | ||
Net change in the Level III fair value category | ||
Balance at beginning of year | (7) | 16 |
Transfers out of Level III | 5 | (19) |
Total gains/(losses) included in Net income | 8 | (17) |
Settlements | (9) | 18 |
Sales | 0 | (5) |
Foreign exchange | (1) | 0 |
Balance at end of year | (4) | $ (7) |
Commodity contracts | Power | Level III | ||
Net change in the Level III fair value category | ||
Decrease in fair value of outstanding derivative instruments included in Level III due to a 10% increase in commodity prices | 2 | |
Increase in fair value of outstanding derivative instruments included in Level III due to a 10% decrease in commodity prices | $ 2 |
CHANGES IN OPERATING WORKING _3
CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
CHANGES IN OPERATING WORKING CAPITAL | |||
Increase in Accounts receivable | $ (69) | $ (576) | $ (482) |
Increase in Inventories | (49) | (38) | (87) |
Decrease/(increase) in Assets held for sale | 0 | 14 | (13) |
Decrease in Other current assets | 45 | 189 | 328 |
(Decrease)/increase in Accounts payable and other | (70) | 151 | 424 |
Increase in Accrued interest | 41 | 12 | 62 |
(Decrease)/increase in Liabilities related to assets held for sale | 0 | (25) | 16 |
(Increase)/decrease in Operating Working Capital | $ (102) | $ (273) | $ 248 |
ACQUISITIONS AND DISPOSITIONS -
ACQUISITIONS AND DISPOSITIONS - Narrative (Details) $ / shares in Units, shares in Millions, $ in Millions, $ in Millions | Oct. 24, 2018CAD ($) | Dec. 19, 2017CAD ($) | Jun. 02, 2017USD ($) | Jun. 01, 2017USD ($) | Apr. 19, 2017USD ($) | Jul. 01, 2016CAD ($)mikmBcf | Jul. 01, 2016USD ($) | May 01, 2016USD ($) | Mar. 31, 2016USD ($) | Feb. 29, 2016USD ($) | Jan. 31, 2016USD ($) | Jun. 30, 2017CAD ($) | Jun. 30, 2017USD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2018CAD ($)mikmBcf | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jul. 01, 2016USD ($)mikm$ / sharesBcf | Jun. 30, 2016$ / sharesshares | Apr. 30, 2016CAD ($)shares | Apr. 01, 2016shares |
Business Acquisition [Line Items] | |||||||||||||||||||||||
Contributions to equity investments | $ 1,015 | $ 1,681 | $ 765 | ||||||||||||||||||||
Common stock, value, subscriptions | $ 4,400 | ||||||||||||||||||||||
Subscription receipt (in shares) | shares | 96.6 | ||||||||||||||||||||||
Goodwill | 14,178 | 13,084 | |||||||||||||||||||||
Proceeds from sale of assets, net of transaction costs | 614 | 4,683 | 6 | ||||||||||||||||||||
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 | $ 4,400 | ||||||||||||||||||||||
Subscription receipt (in shares) | shares | 96.6 | ||||||||||||||||||||||
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 | $ 45 | $ 35 | |||||||||||||||||||||
Goodwill adjustment | 71 | 55 | |||||||||||||||||||||
Goodwill | $ 10,078 | $ 7,802 | $ 7,747 | $ 7,747 | |||||||||||||||||||
Increase (decrease) in fair value of acquired liabilities, long-term debt | 300 | 231 | $ 232 | 242 | |||||||||||||||||||
Common unit, outstanding (in shares) | shares | 53.8 | ||||||||||||||||||||||
Share price (in USD per share) | $ / shares | $ 15 | ||||||||||||||||||||||
Acquisition costs | $ 36 | 36 | |||||||||||||||||||||
Revenue of acquiree since acquisition date | 929 | ||||||||||||||||||||||
Earnings of acquiree since acquisition date | 132 | ||||||||||||||||||||||
Columbian Pipeline | U.S. federal | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Effective income tax rate percent | 39.00% | 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 | $ 116 | $ 90 | |||||||||||||||||||
Columbian Pipeline | Natural Gas | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Increase (decrease) in fair value of property, plant, and equipment | $ 840 | 646 | |||||||||||||||||||||
Columbian Pipeline | Bridge Facility | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Proceeds from lines of credit | $ 6,900 | ||||||||||||||||||||||
Natural Gas – Ironwood | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Purchase price | $ 653 | ||||||||||||||||||||||
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 | (829) | ||||||||||||||||||||||
Gain (loss) on disposition of property plant equipment, net of tax | (863) | ||||||||||||||||||||||
U.S. Natural Gas Pipelines | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Investments of regulated natural gas pipelines (in kilometers) | km | 50,199 | ||||||||||||||||||||||
Investments of regulated natural gas pipelines (in miles) | mi | 31,192 | ||||||||||||||||||||||
Investments of regulated natural gas storage facilities (in billion cubic feet) | Bcf | 535 | ||||||||||||||||||||||
Goodwill | $ 13,958 | $ 14,178 | 13,084 | 13,958 | |||||||||||||||||||
U.S. Natural Gas Pipelines | Columbian Pipeline | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Goodwill adjustment | 71 | ||||||||||||||||||||||
Iroquois | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Ownership interest percentage | 50.00% | 49.35% | |||||||||||||||||||||
Additional ownership acquired (percent) | 0.65% | 4.87% | |||||||||||||||||||||
Contributions to equity investments | $ 7 | $ 54 | |||||||||||||||||||||
Iroquois | U.S. Natural Gas Pipelines | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Ownership interest percentage | 0.66% | 50.00% | 50.00% | ||||||||||||||||||||
Ontario Solar Assets | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Proceeds from sale of assets, net of transaction costs | $ 541 | ||||||||||||||||||||||
Gain (loss) on disposition of property plant equipment | 127 | ||||||||||||||||||||||
Gain (loss) on disposition of property plant equipment, net of tax | $ 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 | 715 | ||||||||||||||||||||||
Gain (loss) on disposition of property plant equipment, net of tax | 440 | ||||||||||||||||||||||
Income tax recovery related to sale | $ 27 | ||||||||||||||||||||||
Gain (loss) on disposition of property plant and equipment foreign currency translation amount | 5 | ||||||||||||||||||||||
Ravenswood, Ironwood, Kibby Wind and Ocean State Power | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Gain (loss) on disposition of property plant equipment | (211) | ||||||||||||||||||||||
Gain (loss) on disposition of property plant equipment, net of tax | (167) | ||||||||||||||||||||||
Foreign currency translation gain on assets held for sale | $ 2 | $ 70 | |||||||||||||||||||||
Disposal group, disposed of by sale, not discontinued operations | PNGTS And Iroquois Transmission systems | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Total consideration | $ 765 | ||||||||||||||||||||||
Cash received | 597 | ||||||||||||||||||||||
Assumption of debt by purchaser | $ 168 | ||||||||||||||||||||||
Disposal group, disposed of by sale, not discontinued operations | Cartier Wind | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Ownership interest before transaction, percent | 62.00% | ||||||||||||||||||||||
Proceeds from sale of assets, net of transaction costs | $ 630 | ||||||||||||||||||||||
Gain (loss) on disposition of property plant equipment | 170 | ||||||||||||||||||||||
Gain (loss) on disposition of property plant equipment, net of tax | $ 143 | ||||||||||||||||||||||
Disposal group, disposed of by sale, not discontinued operations | Iroquois | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Ownership interest before transaction, percent | 49.34% | ||||||||||||||||||||||
Disposal group, disposed of by sale, not discontinued operations | PNGTS | |||||||||||||||||||||||
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 |
ACQUISITIONS AND DISPOSITIONS_2
ACQUISITIONS AND DISPOSITIONS - Schedule of Assets Acquired and Liabilities Assumed (Details) $ in Millions, $ in Millions | Jul. 01, 2016CAD ($) | Jul. 01, 2016USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jul. 01, 2016USD ($) |
Fair Value | |||||||
Goodwill | $ 14,178 | $ 13,084 | |||||
Exchange rate | 1.30 | 1.30 | |||||
Columbian Pipeline | |||||||
Business Acquisition [Line Items] | |||||||
Purchase Price Consideration | $ 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 | $ 10,078 | $ 7,802 | $ 7,747 | $ 7,747 |
ACQUISITIONS AND DISPOSITIONS_3
ACQUISITIONS AND DISPOSITIONS - Schedule of Fair Value of Debt Acquired (Details) - Columbian Pipeline $ in Millions | Jul. 01, 2016CAD ($) | Jul. 01, 2016USD ($) |
Debt Instrument [Line Items] | ||
Fair Value | $ 3,878 | $ 2,981,000,000 |
Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Fair Value | 2,981,000,000 | |
Senior Unsecured Notes (US$500) | Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | 500,000,000 | |
Fair Value | $ 506,000,000 | |
Interest Rate | 2.45% | 2.45% |
Senior Unsecured Notes (US$750) | Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 750,000,000 | |
Fair Value | $ 779,000,000 | |
Interest Rate | 3.30% | 3.30% |
Senior Unsecured Notes (US$1,000) | Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 1,000,000,000 | |
Fair Value | $ 1,092,000,000 | |
Interest Rate | 4.50% | 4.50% |
Senior Unsecured Notes (US$500) | Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 500,000,000 | |
Fair Value | $ 604,000,000 | |
Interest Rate | 5.80% | 5.80% |
ACQUISITIONS AND DISPOSITIONS_4
ACQUISITIONS AND DISPOSITIONS - Pro Forma Information (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Business Combinations [Abstract] | ||
Revenues | $ 13,404 | $ 13,007 |
Net Income/(Loss) | 627 | (820) |
Net Income/(Loss) Attributable to Common Shares | $ 234 | $ (971) |
COMMITMENTS, CONTINGENCIES AN_3
COMMITMENTS, CONTINGENCIES AND GUARANTEES - Operating Leases (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Minimum Lease Payments | |||
2,019 | $ 81 | ||
2,020 | 78 | ||
2,021 | 76 | ||
2,022 | 69 | ||
2,023 | 67 | ||
2024 and thereafter | 390 | ||
Minimum Lease Payments | 761 | ||
Amounts Recoverable under Subleases | |||
2,019 | 7 | ||
2,020 | 7 | ||
2,021 | 4 | ||
2,022 | 3 | ||
2,023 | 3 | ||
2024 and thereafter | 8 | ||
Amounts Recoverable under Subleases | 32 | ||
Net Payments | |||
2,019 | 74 | ||
2,020 | 71 | ||
2,021 | 72 | ||
2,022 | 66 | ||
2,023 | 64 | ||
2024 and thereafter | 382 | ||
Net Payments | 729 | ||
Rent Expense | |||
Net rental expense on operating leases | $ 84 | $ 93 | $ 145 |
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 AN_4
COMMITMENTS, CONTINGENCIES AND GUARANTEES - Other Commitments and Contingencies (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Contingencies | ||
Amount accrued related to operating facilities for the estimated expenses to remediate the sites | $ 40 | $ 34 |
Operating segments | Canadian Natural Gas Pipelines | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 4,600 | |
Operating segments | U.S. Natural Gas Pipelines | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 100 | |
Operating segments | Mexico Natural Gas Pipelines | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 300 | |
Operating segments | Liquids Pipelines | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 400 | |
Operating segments | Energy | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | 700 | |
Corporate | Capital expenditures | ||
Other Commitments | ||
Commitment for capital expenditures | $ 100 |
COMMITMENTS, CONTINGENCIES AN_5
COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Guarantees | ||
Potential Exposure | $ 375 | $ 507 |
Carrying Value | 12 | 16 |
Sur de Texas | ||
Guarantees | ||
Potential Exposure | 183 | 315 |
Carrying Value | 1 | 2 |
Bruce Power | ||
Guarantees | ||
Potential Exposure | 88 | 88 |
Carrying Value | 0 | 1 |
Other jointly owned entities | ||
Guarantees | ||
Potential Exposure | 104 | 104 |
Carrying Value | $ 11 | $ 13 |
CORPORATE RESTRUCTURING COSTS_2
CORPORATE RESTRUCTURING COSTS (Details) $ in Millions | Dec. 31, 2018CAD ($) |
Restructuring Cost and Reserve [Line Items] | |
Cumulative recoverable restructuring costs | $ 157 |
Employee Severance | |
Restructuring Cost and Reserve [Line Items] | |
Cumulative restructuring costs incurred | 86 |
Lease Commitments | |
Restructuring Cost and Reserve [Line Items] | |
Cumulative restructuring costs incurred | $ 60 |
CORPORATE RESTRUCTURING COSTS -
CORPORATE RESTRUCTURING COSTS - Schedule of Change In Restructuring Liability (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Restructuring Reserve [Roll Forward] | ||
Restructuring liability as at the beginning of period | $ 62 | $ 99 |
Restructuring charges | 42 | 6 |
Accretion expense | 1 | 1 |
Cash payments | (24) | (44) |
Restructuring Liability as at the end of period | 81 | 62 |
Recoverable restructuring costs incurred | 21 | 3 |
Employee Severance | ||
Restructuring Reserve [Roll Forward] | ||
Restructuring liability as at the beginning of period | 9 | 36 |
Restructuring charges | 0 | 0 |
Accretion expense | 0 | 0 |
Cash payments | (9) | (27) |
Restructuring Liability as at the end of period | 0 | 9 |
Lease Commitments | ||
Restructuring Reserve [Roll Forward] | ||
Restructuring liability as at the beginning of period | 53 | 63 |
Restructuring charges | 42 | 6 |
Accretion expense | 1 | 1 |
Cash payments | (15) | (17) |
Restructuring Liability as at the end of period | $ 81 | $ 53 |
VARIABLE INTEREST ENTITIES (Det
VARIABLE INTEREST ENTITIES (Details) | 12 Months Ended |
Dec. 31, 2018 | |
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 ($) $ in Millions | Dec. 31, 2018 | Jan. 01, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Current Assets | |||||
Cash and cash equivalents | $ 446 | $ 1,089 | $ 1,016 | $ 850 | |
Accounts receivable | 2,535 | $ 2,460 | 2,522 | ||
Inventories | 431 | 378 | |||
Other | 1,180 | 770 | 691 | ||
Total Current Assets | 5,135 | 4,680 | |||
Plant, Property and Equipment | 66,503 | 57,277 | |||
Equity Investments | 7,113 | 6,366 | |||
Goodwill | 14,178 | 13,084 | |||
Total Assets | 98,920 | 86,101 | |||
Current Liabilities | |||||
Accounts payable and other | 5,408 | $ 4,074 | 4,057 | ||
Accrued interest | 646 | 605 | |||
Current portion of long-term debt | 3,462 | 2,866 | |||
Total Current Liabilities | 12,946 | 9,877 | |||
Total Regulatory Liabilities | 3,930 | 4,321 | |||
Other Long-Term Liabilities | 1,008 | 727 | |||
Deferred Income Tax Liabilities | 6,026 | 5,403 | |||
Long-Term Debt | 36,509 | 31,875 | |||
Total Liabilities | 67,927 | 59,210 | |||
Variable Interest Entity, Primary Beneficiary | |||||
Current Assets | |||||
Cash and cash equivalents | 45 | 41 | |||
Accounts receivable | 79 | 63 | |||
Inventories | 24 | 23 | |||
Other | 13 | 11 | |||
Total Current Assets | 161 | 138 | |||
Plant, Property and Equipment | 3,026 | 3,535 | |||
Equity Investments | 965 | 917 | |||
Goodwill | 453 | 490 | |||
Intangible and Other Assets | 8 | 3 | |||
Total Assets | 4,613 | 5,083 | |||
Current Liabilities | |||||
Accounts payable and other | 88 | 137 | |||
Dividends payable | 0 | 1 | |||
Accrued interest | 24 | 23 | |||
Current portion of long-term debt | 79 | 88 | |||
Total Current Liabilities | 191 | 249 | |||
Total Regulatory Liabilities | 43 | 34 | |||
Other Long-Term Liabilities | 3 | 3 | |||
Deferred Income Tax Liabilities | 13 | 13 | |||
Long-Term Debt | 3,125 | 3,244 | |||
Total Liabilities | $ 3,375 | $ 3,543 |
VARIABLE INTEREST ENTITIES - Ca
VARIABLE INTEREST ENTITIES - Carrying Value of VIEs and Maximum Exposure (Details) - Variable Interest Entity, Not Primary Beneficiary - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Balance sheet | ||
Equity investments | $ 4,575 | $ 4,372 |
Off-balance sheet | ||
Potential exposure to guarantees | 170 | 171 |
Maximum exposure to loss | $ 4,745 | $ 4,543 |
Uncategorized Items - trp-20181
Label | Element | Value |
Accounting Standards Update 2016-09 [Member] | Retained Earnings [Member] | ||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | $ 12,000,000 |