Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2016shares | |
Document and Entity Information | |
Entity Registrant Name | TRANSCANADA CORP |
Entity Central Index Key | 1,232,384 |
Document Type | 40-F |
Document Period End Date | Dec. 31, 2016 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Entity Voluntary Filers | Yes |
Entity Current Reporting Status | Yes |
Entity Filer Category | Accelerated Filer |
Entity Common Stock, Shares Outstanding | 863,759,075 |
Document Fiscal Year Focus | 2,016 |
Document Fiscal Period Focus | FY |
Consolidated statement of incom
Consolidated statement of income - CAD shares in Millions, CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues (Note 1) | |||
Liquids Pipelines | CAD 1,755 | CAD 1,879 | CAD 1,547 |
Energy | 4,164 | 4,038 | 3,725 |
Total Revenues | 12,505 | 11,300 | 10,185 |
Income from Equity Investments (Note 9) | 514 | 440 | 522 |
Operating and Other Expenses | |||
Plant operating costs and other | 3,819 | 3,250 | 2,973 |
Commodity purchases resold | 2,172 | 2,237 | 1,836 |
Property taxes | 555 | 517 | 473 |
Depreciation and amortization | 1,939 | 1,765 | 1,611 |
Goodwill and other asset impairment charges (Note 8, 11 and 12) | 1,388 | 3,745 | 0 |
Total Operating and Other Expenses | 9,873 | 11,514 | 6,893 |
(Loss)/Gain on Assets Held for Sale/Sold (Notes 6 and 26) | (833) | (125) | 117 |
Financial Charges | |||
Interest expense (Note 17) | 1,998 | 1,370 | 1,198 |
Allowance for funds used during construction | 419 | 295 | 136 |
Interest income and other | (103) | 132 | 45 |
Total Financial Charges/(Income) | 1,476 | 1,207 | 1,107 |
Income/(Loss) before Income Taxes | 837 | (1,106) | 2,824 |
Income Tax Expense/(Recovery) (Note 16) | |||
Current | 156 | 136 | 145 |
Deferred | 196 | (102) | 686 |
Total Income Tax Expense/(Recovery) | 352 | 34 | 831 |
Net Income/(Loss) | 485 | (1,140) | 1,993 |
Net Income attributable to non-controlling interests (Note 19) | 252 | 6 | 153 |
Net Income/(Loss) Attributable to Controlling Interests | 233 | (1,146) | 1,840 |
Preferred share dividends | 109 | 94 | 97 |
Net Income/(Loss) Attributable to Common Shares | CAD 124 | CAD (1,240) | CAD 1,743 |
Net Income/(Loss) per Common Share (Note 20) | |||
Basic and diluted (in dollars per share) | CAD 0.16 | CAD (1.75) | CAD 2.46 |
Dividends Declared per Common Share (in dollars per share) | CAD 2.26 | CAD 2.08 | CAD 1.92 |
Weighted Average Number of Common Shares (millions) (Note 20) | |||
Basic (in shares) | 759 | 709 | 708 |
Diluted (in shares) | 760 | 709 | 710 |
Canadian Natural Gas Pipelines | |||
Revenues (Note 1) | |||
Natural Gas Pipelines | CAD 3,682 | CAD 3,680 | CAD 3,557 |
U.S. Natural Gas Pipelines | |||
Revenues (Note 1) | |||
Natural Gas Pipelines | 2,526 | 1,444 | 1,159 |
Mexico Natural Gas Pipelines | |||
Revenues (Note 1) | |||
Natural Gas Pipelines | CAD 378 | CAD 259 | CAD 197 |
Consolidated statement of compr
Consolidated statement of comprehensive income - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Statement of Comprehensive Income [Abstract] | |||
Net Income/(Loss) | CAD 485 | CAD (1,140) | CAD 1,993 |
Other Comprehensive (Loss)/Income, Net of Income Taxes | |||
Foreign currency translation gains on net investment in foreign operations | 3 | 813 | 517 |
Change in fair value of net investment hedges | (10) | (372) | (276) |
Change in fair value of cash flow hedges | 30 | (57) | (69) |
Reclassification to net income of gains and losses on cash flow hedges | 42 | 88 | (55) |
Unrealized actuarial losses and gains on pension and other post-retirement benefit plans | (26) | 51 | (102) |
Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans | 16 | 32 | 18 |
Other comprehensive (loss)/income on equity investments | (87) | 47 | (204) |
Other comprehensive (loss)/income (Note 22) | (32) | 602 | (171) |
Comprehensive Income/(Loss) | 453 | (538) | 1,822 |
Comprehensive income attributable to non-controlling interests | 241 | 312 | 283 |
Comprehensive Income/(Loss) Attributable to Controlling Interests | 212 | (850) | 1,539 |
Preferred share dividends | 109 | 94 | 97 |
Comprehensive Income/(Loss) Attributable to Common Shares | CAD 103 | CAD (944) | CAD 1,442 |
Consolidated statement of cash
Consolidated statement of cash flows - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cash Generated from Operations | |||
Net Income/(Loss) | CAD 485 | CAD (1,140) | CAD 1,993 |
Depreciation and amortization | 1,939 | 1,765 | 1,611 |
Goodwill and other asset impairment charges (Note 8, 11 and 12) | 1,388 | 3,745 | 0 |
Deferred income taxes (Note 16) | 196 | (102) | 686 |
Income from equity investments (Note 9) | (514) | (440) | (522) |
Distributions received from operating activities of equity investments (Note 9) | 844 | 793 | 726 |
Employee post-retirement benefits expense, net of funding (Note 23) | (3) | 44 | 37 |
Loss/(gain) on assets held for sale/sold (Notes 6 and 26) | 833 | 125 | (117) |
Equity allowance for funds used during construction | (253) | (165) | (95) |
Unrealized (gains)/losses on financial instruments | (149) | 58 | 74 |
Other | 55 | 47 | 22 |
Decrease/(increase) in operating working capital (Note 25) | 248 | (346) | (189) |
Net cash provided by operations | 5,069 | 4,384 | 4,226 |
Investing Activities | |||
Capital expenditures (Note 4) | (5,007) | (3,918) | (3,489) |
Capital projects in development (Note 4) | (295) | (511) | (848) |
Contributions to equity investments (Note 9) | (765) | (493) | (256) |
Acquisitions, net of cash acquired (Note 5 and 26) | (13,608) | (236) | (241) |
Proceeds from sale of assets, net of transaction costs (Note 26) | 6 | 0 | 196 |
Other distributions from equity investments (Note 9) | 727 | 9 | 12 |
Deferred amounts and other | 159 | 270 | 335 |
Net cash used in investing activities | (18,783) | (4,879) | (4,291) |
Financing Activities | |||
Notes payable (repaid)/issued, net | (329) | (1,382) | 544 |
Long-term debt issued, net of issue costs | 12,333 | 5,045 | 1,403 |
Long-term debt repaid | (7,153) | (2,105) | (1,069) |
Junior subordinated notes issued, net of issue costs | 1,549 | 917 | 0 |
Dividends on common shares | (1,436) | (1,446) | (1,345) |
Dividends on preferred shares | (100) | (92) | (94) |
Distributions paid to non-controlling interests | (279) | (224) | (178) |
Common shares issued, net of issue costs | 7,747 | 27 | 47 |
Common shares repurchased (Note 20) | (14) | (294) | 0 |
Preferred shares issued, net of issue costs | 1,474 | 243 | 440 |
Partnership units of subsidiary issued, net of issue costs | 215 | 55 | 79 |
Preferred shares of subsidiary redeemed (Note 19) | 0 | 0 | (200) |
Net cash provided by/(used in) financing activities | 14,007 | 744 | (373) |
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents | (127) | 112 | 0 |
Increase/(Decrease) in Cash and Cash Equivalents | 166 | 361 | (438) |
Cash and Cash Equivalents, Beginning of year | 850 | 489 | 927 |
Cash and Cash Equivalents, End of year | CAD 1,016 | CAD 850 | CAD 489 |
Consolidated balance sheet
Consolidated balance sheet - CAD shares in Millions, CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Current Assets | ||
Cash and cash equivalents | CAD 1,016 | CAD 850 |
Accounts receivable | 2,075 | 1,387 |
Inventories | 368 | 323 |
Assets held for sale (Note 6) | 3,717 | 20 |
Other (Note 7) | 908 | 1,338 |
Total Current Assets | 8,084 | 3,918 |
Plant, Property and Equipment (Note 8) | 54,475 | 44,817 |
Equity Investments (Note 9) | 6,544 | 6,214 |
Regulatory Assets (Note 10) | 1,322 | 1,184 |
Goodwill (Note 11) | 13,958 | 4,812 |
Intangible and Other Assets (Note 12) | 3,026 | 3,102 |
Restricted Investments | 642 | 351 |
Total Assets | 88,051 | 64,398 |
Current Liabilities | ||
Notes payable (Note 13) | 774 | 1,218 |
Accounts payable and other (Note 14) | 3,861 | 2,653 |
Dividends payable | 526 | 385 |
Accrued interest | 595 | 520 |
Liabilities related to assets held for sale (Note 6) | 86 | 39 |
Current portion of long-term debt (Note 17) | 1,838 | 2,547 |
Total Current Liabilities | 7,680 | 7,362 |
Regulatory Liabilities (Note 10) | 2,121 | 1,159 |
Other Long-Term Liabilities (Note 15) | 1,183 | 1,260 |
Deferred Income Tax Liabilities (Note 16) | 7,662 | 5,144 |
Long-Term Debt (Note 17) | 38,312 | 28,909 |
Junior Subordinated Notes (Note 18) | 3,931 | 2,409 |
Total Liabilities | 60,889 | 46,243 |
Common Units Subject to Rescission or Redemption (Note 19) | 1,179 | 0 |
EQUITY | ||
Common shares, no par value (Note 20) | CAD 20,099 | CAD 12,102 |
Common shares issued (in shares) | 864 | 703 |
Preferred shares (Note 21) | CAD 3,980 | CAD 2,499 |
Additional paid-in capital | 0 | 7 |
Retained earnings | 1,138 | 2,769 |
Accumulated other comprehensive loss (Note 22) | (960) | (939) |
Controlling Interests | 24,257 | 16,438 |
Non-controlling interests (Note 19) | 1,726 | 1,717 |
Total Equity | 25,983 | 18,155 |
Total Liabilities and Equity | CAD 88,051 | CAD 64,398 |
Consolidated balance sheet (Par
Consolidated balance sheet (Parenthetical) - shares shares in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Statement of Financial Position [Abstract] | ||
Common shares issued (in shares) | 864 | 703 |
Common shares outstanding (in shares) | 864 | 703 |
Consolidated statement of equit
Consolidated statement of equity - CAD CAD in Millions | Total | Equity Attributable to Controlling Interests | Common Shares | Preferred Shares | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Loss | Equity Attributable to Non-Controlling Interests | TC PipeLines, LPEquity Attributable to Non-Controlling Interests | PORTLAND NATURAL GAS TRANSMISSION SYSTEMEquity Attributable to Non-Controlling Interests | Columbia Pipeline Partners LPEquity Attributable to Non-Controlling Interests |
Issuance of TC PipeLines, LP units | |||||||||||
Total Equity | CAD (934) | ||||||||||
Beginning balance at Dec. 31, 2013 | CAD 12,149 | CAD 1,813 | CAD 401 | CAD 5,096 | (934) | ||||||
Increase (decrease) in equity | |||||||||||
Shares issued under public offering, net of issue costs (Note 21) | 0 | 442 | |||||||||
Shares issued under dividend reinvestment and share purchase plan (Note 20) | 0 | ||||||||||
Shares issued on exercise of stock options (Note 20) | 53 | ||||||||||
Shares repurchased (Note 20) | 0 | 0 | |||||||||
Issuance of stock options, net of exercises | 3 | ||||||||||
Dilution impact from TC PipeLines, LP units issued | 9 | CAD 79 | |||||||||
Redemption of subsidiary's preferred shares | (6) | (194) | |||||||||
Impact of asset drop downs to TC PipeLines, LP (Note 26) | (37) | ||||||||||
Reclassification of additional paid-in capital deficit to retained earnings | 0 | ||||||||||
Net income/(loss) attributable to controlling interests | CAD 1,840 | 1,840 | |||||||||
Common share dividends | (1,360) | ||||||||||
Preferred share dividends | (98) | ||||||||||
Reclassification of additional paid-in capital deficit to retained earnings | 0 | ||||||||||
Other comprehensive (loss)/income attributable to controlling interests (Note 22) | (171) | (301) | |||||||||
Ending balance at Dec. 31, 2014 | CAD 19,070 | 12,202 | 2,255 | 370 | 5,478 | (1,235) | |||||
Beginning balance at Dec. 31, 2013 | 1,611 | ||||||||||
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward] | |||||||||||
Acquisition of non-controlling interests in Columbia Pipeline Partners LP | 0 | ||||||||||
Net income/(loss) attributable to non-controlling interests | |||||||||||
Pipeline Partners LP | CAD 136 | CAD 0 | |||||||||
Portland Natural Gas Transmission System | 153 | 136 | CAD 15 | 0 | |||||||
Preferred share dividends of TCPL | 2 | ||||||||||
Other comprehensive (loss)/income attributable to non-controlling interests | 130 | ||||||||||
Issuance of TC PipeLines, LP units | |||||||||||
Proceeds, net of issue costs | 9 | 79 | |||||||||
Decrease in TransCanada's ownership of TC PipeLines, LP | (14) | ||||||||||
Distributions declared to non-controlling interests | (182) | ||||||||||
Reclassification to common units subject to rescission or redemption (Note 19) | 0 | ||||||||||
Redemption of subsidiary's preferred shares | (6) | (194) | |||||||||
Ending balance at Dec. 31, 2014 | 1,583 | ||||||||||
Issuance of TC PipeLines, LP units | |||||||||||
Total Equity | 20,653 | (1,235) | |||||||||
Shares issued under public offering, net of issue costs (Note 21) | 0 | 244 | |||||||||
Shares issued under dividend reinvestment and share purchase plan (Note 20) | 0 | ||||||||||
Shares issued on exercise of stock options (Note 20) | 30 | ||||||||||
Shares repurchased (Note 20) | (130) | (164) | |||||||||
Issuance of stock options, net of exercises | 8 | ||||||||||
Dilution impact from TC PipeLines, LP units issued | 6 | 55 | |||||||||
Redemption of subsidiary's preferred shares | 0 | 0 | |||||||||
Impact of asset drop downs to TC PipeLines, LP (Note 26) | (213) | ||||||||||
Reclassification of additional paid-in capital deficit to retained earnings | 0 | ||||||||||
Net income/(loss) attributable to controlling interests | (1,146) | (1,146) | |||||||||
Common share dividends | (1,471) | ||||||||||
Preferred share dividends | (92) | ||||||||||
Reclassification of additional paid-in capital deficit to retained earnings | 0 | ||||||||||
Other comprehensive (loss)/income attributable to controlling interests (Note 22) | 602 | 296 | |||||||||
Ending balance at Dec. 31, 2015 | 16,438 | 16,438 | 12,102 | 2,499 | 7 | 2,769 | (939) | ||||
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward] | |||||||||||
Acquisition of non-controlling interests in Columbia Pipeline Partners LP | 0 | ||||||||||
Net income/(loss) attributable to non-controlling interests | |||||||||||
Pipeline Partners LP | (13) | 0 | |||||||||
Portland Natural Gas Transmission System | 6 | (13) | 19 | 0 | |||||||
Preferred share dividends of TCPL | 0 | ||||||||||
Other comprehensive (loss)/income attributable to non-controlling interests | 306 | ||||||||||
Issuance of TC PipeLines, LP units | |||||||||||
Proceeds, net of issue costs | 6 | 55 | |||||||||
Decrease in TransCanada's ownership of TC PipeLines, LP | (11) | ||||||||||
Distributions declared to non-controlling interests | (222) | ||||||||||
Reclassification to common units subject to rescission or redemption (Note 19) | 0 | ||||||||||
Redemption of subsidiary's preferred shares | 0 | 0 | |||||||||
Ending balance at Dec. 31, 2015 | 1,717 | 1,717 | 1,590 | 127 | |||||||
Issuance of TC PipeLines, LP units | |||||||||||
Total Equity | 18,155 | (939) | |||||||||
Shares issued under public offering, net of issue costs (Note 21) | 7,752 | 1,481 | |||||||||
Shares issued under dividend reinvestment and share purchase plan (Note 20) | 177 | ||||||||||
Shares issued on exercise of stock options (Note 20) | 74 | ||||||||||
Shares repurchased (Note 20) | (6) | (8) | |||||||||
Issuance of stock options, net of exercises | 6 | ||||||||||
Dilution impact from TC PipeLines, LP units issued | 24 | 215 | |||||||||
Redemption of subsidiary's preferred shares | 0 | 0 | |||||||||
Impact of asset drop downs to TC PipeLines, LP (Note 26) | (38) | ||||||||||
Reclassification of additional paid-in capital deficit to retained earnings | 9 | ||||||||||
Net income/(loss) 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 (loss)/income attributable to controlling interests (Note 22) | (32) | (21) | |||||||||
Ending balance at Dec. 31, 2016 | 24,257 | CAD 24,257 | CAD 20,099 | CAD 3,980 | 0 | CAD 1,138 | (960) | ||||
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward] | |||||||||||
Acquisition of non-controlling interests in Columbia Pipeline Partners LP | 1,051 | ||||||||||
Net income/(loss) attributable to non-controlling interests | |||||||||||
Pipeline Partners LP | 215 | 17 | |||||||||
Portland Natural Gas Transmission System | 252 | 215 | 20 | CAD 17 | |||||||
Preferred share dividends of TCPL | 0 | ||||||||||
Other comprehensive (loss)/income attributable to non-controlling interests | (11) | ||||||||||
Issuance of TC PipeLines, LP units | |||||||||||
Proceeds, net of issue costs | 24 | 215 | |||||||||
Decrease in TransCanada's ownership of TC PipeLines, LP | (40) | ||||||||||
Distributions declared to non-controlling interests | (279) | ||||||||||
Reclassification to common units subject to rescission or redemption (Note 19) | (1,179) | ||||||||||
Redemption of subsidiary's preferred shares | CAD 0 | 0 | |||||||||
Ending balance at Dec. 31, 2016 | 1,726 | CAD 1,726 | CAD 1,596 | CAD 130 | |||||||
Issuance of TC PipeLines, LP units | |||||||||||
Total Equity | CAD 25,983 | CAD (960) |
DESCRIPTION OF TRANSCANADA'S BU
DESCRIPTION OF TRANSCANADA'S BUSINESS | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
DESCRIPTION OF TRANSCANADA'S BUSINESS | DESCRIPTION OF TRANSCANADA'S BUSINESS TransCanada Corporation (TransCanada or the Company) is a leading North American energy infrastructure company which operates in three core businesses, Natural Gas Pipelines, Liquids Pipelines and Energy, each of which offers different products and services. As a result of the acquisition of Columbia Pipeline Group, Inc. (Columbia) and the pending monetization of the United States (U.S.) Northeast power business, the Company has revised its reporting segments from Natural Gas Pipelines, Liquids Pipelines, Energy and Corporate, to Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines, Energy and Corporate as at December 31, 2016 . The Corporate segment is non-operational, consisting of corporate and administrative functions. The revised structure aligns with the information reviewed by the Chief Operating Decision Maker (CODM). Historical financial results for the years ended December 31, 2015 and 2014 have been adjusted to align with this change in the Company's segmented reporting. Canadian Natural Gas Pipelines The Canadian Natural Gas Pipelines segment consists of the Company's investments in 40,111 km ( 24,923 miles ) of regulated natural gas pipelines. U.S. Natural Gas Pipelines The U.S. Natural Gas Pipelines segment consists of the Company's investments in 49,776 km ( 30,933 miles ) of regulated natural gas pipelines, 535 Bcf of regulated natural gas storage facilities, midstream and other assets. Acquired as part of Columbia on July 1, 2016, the Company owns and operates: • Columbia Gas – an interstate natural gas transportation pipeline and storage system, which has largely operated as a means to transport gas from the Gulf Coast, via Columbia Gulf, from various pipeline interconnects and from production areas in the Appalachian region to markets in the midwest, Atlantic, and northeast regions. • Columbia Gulf – a long-haul interstate natural gas transportation pipeline system that was originally designed to transport supply from the Gulf of Mexico to major supply markets in the U.S. Northeast. The pipeline is now transitioning and expanding to accommodate new supply from the Appalachian basin at its interconnect with Columbia Gas and other pipelines to deliver natural gas across various Gulf Coast markets. • Millennium – a 47.5 per cent ownership interest in Millennium Pipeline, which transports natural gas primarily sourced from the Marcellus shale to markets across southern New York and the lower Hudson Valley, as well as to New York City through its pipeline interconnections. • Crossroads – an interstate natural gas pipeline operating in Indiana and Ohio. • Midstream – this business provides natural gas producer services including gathering, treating, conditioning, processing, compression and liquids handling in the Appalachian Basin, and includes a 47 per cent interest in Pennant Midstream. Mexico Natural Gas Pipelines The Mexico Natural Gas Pipelines segment consists of the Company's investments in 1,617 km ( 1,005 miles ) of regulated natural gas pipelines in Mexico. This segment also includes the Company's 46.5 percent interest in the TransGas pipeline located in Colombia and prior to its sale in November 2014, the Company's interest in Gas Pacifico/INNERGY in South America. Liquids Pipelines The Liquids Pipelines segment consists of the Company's investment in 4,324 km ( 2,687 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 18 power generation plants and 118 Bcf of non-regulated natural gas storage facilities. These include Canadian plants in Alberta, Ontario, Québec and New Brunswick, and U.S. plants in New York, New England, Pennsylvania and Arizona. At December 31, 2016, five power generation plants in New York and New England, Pennsylvania are 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, 2016 | |
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 its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-controlling interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation. Use of Estimates and Judgments In preparing these 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. Significant estimates and judgments used in the preparation of the consolidated financial statements include, but are not limited to: • fair value of assets and liabilities acquired in a business combination (Note 5) • fair value and depreciation rates of plant, property and equipment (Note 8) • carrying value of regulatory assets and liabilities (Note 10) • fair value of goodwill (Note 11) • fair value of intangible assets (Note 12) • carrying value of asset retirement obligations (Note 15) • provisions for income taxes (Note 16) • assumptions used to measure retirement and other post-retirement obligations (Note 23) • fair value of financial instruments (Note 24) and • provision for commitments, contingencies, guarantees (Note 27) and restructuring (Note 28). Actual results could differ from these estimates. Regulation In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB). In the U.S., natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). The Company's Canadian, U.S. and Mexican natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls. Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TransCanada's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain of its liquids pipelines projects. RRA is not applicable to the Keystone Pipeline System as the regulators' decisions regarding operations and tolls on that system generally do not have an impact on timing of recognition of revenues and expenses. Revenue Recognition Natural Gas Pipelines and Liquids Pipelines Transportation Revenues from the Company's natural gas and liquids pipelines, with the exception of Canadian natural gas pipelines which are subject to RRA, are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made. Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline tolls are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines generally are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines, at times, are subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues are recognized on firm contracted capacity ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenue are recorded when the NEB decision is received. The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. Revenues from the Company's Mexican natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and recognized ratably over the contract period. Other volumes shipped on these pipelines are subject to CRE-approved tariffs. The Company does not take ownership of the gas that it transports for others. Regulated Natural Gas Storage Revenues from the Company's regulated natural gas storage services are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the gas that it stores for others. Midstream and Other Revenues from the Company's midstream natural gas services, including gathering, treating, conditioning, processing, compression and liquids handling services, are generated from volumetric based contractual arrangements and are recognized ratably over the contract period regardless of the amount of natural gas that is subject to these services. The Company also owns mineral rights in association with certain storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest. Royalties from mineral interests are recognized when product is produced. Energy Power Revenues from the Company's Energy business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative instruments and hedging activities policy in this note. Non-Regulated Natural Gas Storage Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues. Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. Inventories Inventories primarily consist of natural gas inventory in storage, crude oil in transit, materials and supplies including spare parts and fuel. Inventories are all carried at the lower of weighted average cost or market. Plant, Property and Equipment Natural Gas Pipelines Plant, property and equipment for natural gas pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to six per cent, and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in plant, property and equipment and the equity component of AFUDC is a non-cash expenditure with a corresponding credit recognized in Allowance for funds used during construction in the Consolidated statement of income. Interest is capitalized during construction of non-regulated natural gas pipelines. Natural gas storage base gas, which is valued at cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. Natural gas storage base gas is not depreciated. When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove a plant from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Midstream and Other Plant, property and equipment for midstream assets are 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 and amortization are derecognized and any gain or loss is recorded in net income. The Company participates as a working interest partner in the development of Marcellus and Utica acreage. The working interest allows the Company to invest in the drilling activities in addition to 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 are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction for non-regulated liquids pipelines and AFUDC for regulated pipelines. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in net income. Energy Power generation and natural gas storage plant, equipment and structures are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in net income. Natural gas storage base gas, which is valued at original cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. Natural gas storage base gas is not depreciated. Corporate Corporate plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent. Capitalized Project Costs The Company capitalizes project costs once advancement to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest for non-regulated projects in development and AFUDC for regulated projects. Capital projects in development are included in Intangible and other assets. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to Plant, property and equipment under construction. When the asset is ready for its intended use and available for operations, capitalized project costs are depreciated in accordance with the Company's depreciation policies. Assets Held For Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next twelve months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, reduced for selling costs, and any losses are recognized in Net income. Depreciation expense is no longer recorded once assets are classified as held for sale. Impairment of Long-Lived Assets The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows or the estimated sale price is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset. Acquisitions and Goodwill The Company accounts for business acquisitions 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 initially assesses qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the first step of the two- step impairment test is performed by comparing the fair value of the reporting unit to its carrying value, which includes goodwill. If the fair value of the reporting unit is less than its carrying value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference. Power Purchase Arrangements A power purchase 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. Prior to their termination, substantially all the PPAs under which TransCanada purchased power were also accounted for as operating leases, and initial payments to acquire these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts. A portion of these PPAs were subleased to third parties under terms and conditions similar to the PPAs, and were also accounted for as operating leases with the margin earned from the subleases recorded in Revenues. During 2016, the Company terminated these PPAs and recorded an impairment charge. 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 during which they occur except for changes in balances related to the Canadian regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the NEB. D eferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet. Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Operating and other expenses. The Company has recorded ARO related to its non-regulated natural gas storage operations, mineral rights and certain power generation facilities. The scope and timing of asset retirements related to most of the Company's natural gas pipelines, liquids pipelines and hydroelectric power plants is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities 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 Columbia Gas. Environmental Liabilities The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability. Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and expensed when they are utilized. Compliance costs are expensed when incurred. Allowances granted to or internally generated by 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. The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets. Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five -year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service life of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income/(loss) (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated other comprehensive income/(loss) (AOCI) and into Net income over the average remaining service life of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees. Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or reporting subsidiary operates, 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 and are designated for hedge accounting treatment, which includes fair value and cash flow hedges, and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in Net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in Net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in Net income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects Net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to Net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. In hedging the foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in Net income. The amounts recognized previously in AOCI are reclassified to Net income in the event the Company reduces its net investment in a foreign operation. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in Net income in the period of change. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as Regulatory assets or Regulatory liabilities and are refunded to or collected from the ratepayers, in subsequent years when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in Net income. Long-Term Debt Transaction Costs The Company records long-term debt transaction costs as a deduction from the carrying amount of the related debt and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms. Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company or partially owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments, Plant, property and equipment, or a charge to Net income, and a corresponding liability is recorded in Other long-term liabilities. The release from the obligation is recognized either over the term of the guarantee or upon expiration or settlement. |
ACCOUNTING CHANGES
ACCOUNTING CHANGES | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Changes and Error Corrections [Abstract] | |
ACCOUNTING CHANGES | ACCOUNTING CHANGES Changes in Accounting Policies for 2016 Extraordinary and unusual income statement items In January 2015, the Financial Accounting Standards Board (FASB) issued new guidance on extraordinary and unusual income statement items. This update eliminates the concept of extraordinary items from GAAP. This new guidance was effective January 1, 2016 , was applied prospectively and did not have an impact on the Company’s consolidated financial statements. Consolidation In February 2015, the FASB issued new guidance on consolidation. This guidance requires that entities re-evaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance was effective January 1, 2016 , was applied retrospectively and did not result in any change to the Company's consolidation conclusions. Disclosure requirements outlined in the new guidance are included in Note 29, Variable interest entities. Imputation of interest In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. This guidance requires that debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of the related debt liability consistent with debt discounts or premiums. This new guidance was effective January 1, 2016 , was applied retrospectively and resulted in a reclassification of debt issuance costs previously recorded in Intangible and other assets to an offset of their respective debt liabilities on the Company’s Consolidated balance sheet. Business combinations In September 2015, the FASB issued guidance which intends to simplify the accounting measurement period adjustments in business combinations. The amended guidance requires an acquirer to recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In the period the adjustment was determined, the guidance also requires the acquirer to record the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This new guidance was effective January 1, 2016 , was applied prospectively and did not have a material impact on the Company's consolidated financial statements. Classification of certain cash receipts and cash payments In August 2016, the FASB issued new guidance to clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows. This new guidance is effective January 1, 2018, however, since early adoption is permitted, the Company elected to retrospectively apply this guidance effective December 31, 2016 . The application of this guidance did not have a material impact on the classification of debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and proceeds from the settlement of corporate owned life insurance. The Company has elected to classify distributions received from equity method investments using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investments that generated the distributions. As a result, certain comparative period distributions received from equity method investments have been reclassified from investing activities to cash generated from operations in the Consolidated statement of cash flows. Future Accounting Changes Revenue from contracts with customers In 2014, the FASB issued new guidance on revenue from contracts with customers. Current guidance allows for revenue recognition when certain criteria are met. The new guidance requires that an entity recognize revenue in accordance with a five-step model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The Company will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. The Company is evaluating both methods of adoption as it works through its analysis. The Company has identified all existing customer contracts that are within the scope of the new guidance and has begun to analyze individual contracts or groups of contracts to identify any significant differences and the impact on revenues as a result of implementing the new standard. As the Company continues its contract analysis, it will also quantify the impact, if any, on prior period revenues. The Company will address any system and process changes necessary to compile the information to meet the disclosure requirements of the new standard. As the Company is currently evaluating the impact of this standard, it has not yet determined the effect on its consolidated financial statements. Inventory In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements. Financial instruments In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018. 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. Leases In February 2016, the FASB issued new guidance on leases. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees may be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019, however, the Company is evaluating the option to early adopt. The Company is currently identifying existing lease agreements that may have an impact on the Company's consolidated financial statements as a result of adopting this new guidance. Derivatives and hedging In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks. This new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. Equity method investments In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. In these situations, when an increase in ownership interest in an investment qualifies it for equity method accounting, the new guidance eliminates the requirement to retroactively apply the equity method of accounting. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. Employee share-based payments In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. This new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. 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 instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Consolidation In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entity (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. Income taxes In October 2016, the FASB issued new guidance on income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied on a modified retrospective basis. Early adoption is permitted. 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. 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, and amounts generally described as restricted cash or restricted cash equivalents. The amounts of restricted cash and cash equivalents will be included in Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively. Early adoption is permitted. 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. |
SEGMENTED INFORMATION
SEGMENTED INFORMATION | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
SEGMENTED INFORMATION | SEGMENTED INFORMATION As a result of the acquisition of Columbia and the pending monetization of the U.S. Northeast power business, the Company has changed its reporting segments. TransCanada has six reportable segments, namely, Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines, Energy and Corporate. The Corporate segment is non-operational, consisting of corporate and administrative functions. This provides information that is aligned with the CODM's review of business performance and how decisions about business segments are made. Historical financial results for the years ended December 31, 2015 and 2014 have been adjusted to align with this change in the Company's segmented reporting. year ended December 31, 2016 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate Total (millions of Canadian $) Revenues 3,682 2,526 378 1,755 4,164 — 12,505 Income from equity investments 12 214 (3 ) (1 ) 292 — 514 Plant operating costs and other (1,181 ) (1,000 ) (42 ) (554 ) (834 ) (208 ) (3,819 ) Commodity purchases resold — — — — (2,172 ) — (2,172 ) Property taxes (267 ) (120 ) — (88 ) (80 ) — (555 ) Depreciation and amortization (873 ) (397 ) (43 ) (285 ) (293 ) (48 ) (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) 1,373 1,219 290 827 (1,140 ) (256 ) 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 1,525 1,517 944 810 473 33 5,302 year ended December 31, 2015 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate Total (millions of Canadian $) Revenues 3,680 1,444 259 1,879 4,038 — 11,300 Income from equity investments 12 162 5 — 261 — 440 Plant operating costs and other (1,162 ) (555 ) (49 ) (491 ) (786 ) (207 ) (3,250 ) Commodity purchases resold — — — — (2,237 ) — (2,237 ) Property taxes (272 ) (77 ) — (79 ) (89 ) — (517 ) Depreciation and amortization (845 ) (243 ) (44 ) (266 ) (336 ) (31 ) (1,765 ) Asset impairment charges — — — (3,686 ) (59 ) — (3,745 ) Loss on assets held for sale/sold — (125 ) — — — — (125 ) Segmented earnings/(losses) 1,413 606 171 (2,643 ) 792 (238 ) 101 Interest expense (1,370 ) Allowance for funds used during construction 295 Interest income and other (132 ) Loss before income taxes (1,106 ) Income tax expense (34 ) Net loss (1,140 ) Net income attributable to non-controlling interests (6 ) Net loss attributable to controlling interests (1,146 ) Preferred share dividends (94 ) Net loss attributable to common shares (1,240 ) Capital spending Capital expenditures 1,366 534 566 1,012 376 64 3,918 Capital projects in development 230 3 — 278 — — 511 1,596 537 566 1,290 376 64 4,429 year ended December 31, 2014 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate Total (millions of Canadian $) Revenues 3,557 1,159 197 1,547 3,725 — 10,185 Income from equity investments 12 143 8 — 359 — 522 Plant operating costs and other (1,028 ) (467 ) (41 ) (439 ) (934 ) (64 ) (2,973 ) Commodity purchases resold — — — — (1,836 ) — (1,836 ) Property taxes (266 ) (68 ) — (62 ) (77 ) — (473 ) Depreciation and amortization (821 ) (211 ) (31 ) (216 ) (309 ) (23 ) (1,611 ) Gain on assets held for sale/sold — — 9 — 108 — 117 Segmented earnings/(losses) 1,454 556 142 830 1,036 (87 ) 3,931 Interest expense (1,198 ) Allowance for funds used during construction 136 Interest income and other (45 ) Income before income taxes 2,824 Income tax expense (831 ) Net income 1,993 Net income attributable to non-controlling interests (153 ) Net income attributable to controlling interests 1,840 Preferred share dividends (97 ) Net income attributable to common shares 1,743 Capital spending Capital expenditures 814 237 717 1,469 206 46 3,489 Capital projects in development 327 40 1 480 — — 848 1,141 277 718 1,949 206 46 4,337 at December 31 2016 2015 (millions of Canadian $) Total Assets Canadian Natural Gas Pipelines 15,816 15,038 U.S. Natural Gas Pipelines 34,422 12,207 Mexico Natural Gas Pipelines 5,013 3,787 Liquids Pipelines 16,896 16,046 Energy 13,169 15,614 Corporate 2,735 1,706 88,051 64,398 Geographic Information year ended December 31 2016 2015 2014 (millions of Canadian $) Revenues Canada – domestic 3,655 3,877 3,956 Canada – export 1,177 1,292 1,314 United States 7,295 5,872 4,718 Mexico 378 259 197 12,505 11,300 10,185 at December 31 2016 2015 (millions of Canadian $) Plant, Property and Equipment Canada 20,531 19,287 United States 29,414 21,899 Mexico 4,530 3,631 54,475 44,817 |
ACQUISITION OF COLUMBIA
ACQUISITION OF COLUMBIA | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
ACQUISITION OF COLUMBIA | 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 17, Long-term debt for additional information on the acquisition bridge facilities and Note 20, Common shares for additional information on the subscription receipts. Columbia operates 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 of $10.1 billion ( US$7.7 billion ) 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 has been accounted for as a business combination using the acquisition method where the acquired tangible and intangible assets and assumed liabilities are 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 of Net Assets Acquired Current assets 658 856 Plant, property and equipment 7,560 9,835 Equity investments 441 574 Regulatory assets 190 248 Intangibles and other assets 135 175 Current liabilities (597 ) (777 ) Regulatory liabilities (294 ) (383 ) Other long-term liabilities (144 ) (187 ) Deferred income tax liabilities (1,613 ) (2,098 ) Long-term debt (2,981 ) (3,878 ) Non-controlling interests (808 ) (1,051 ) Fair Value of Net Assets Acquired 2,547 3,314 Goodwill (Note 11) 7,747 10,078 1 At July 1, 2016 exchange rate of $1.30 . The fair values of current assets including cash and cash equivalents, accounts receivable, and inventories and the fair values of current liabilities including notes payable and accrued interest approximate 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, have fair values equal to their carrying values. 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 ). 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 volume of gas in place which resulted in a fair value increase of $840 million ( US$646 million ). The fair value of base gas is based on preliminary information obtained and is subject to change as the Company completes it's work on the volume acquired. An adjustment to the fair value of base gas would impact the purchase price equation. 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$1000) 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 report as of the acquisition date. The fair value representing the funded status of the plans on the acquisition date resulted in an increase of $15 million ( US$12 million ) and $5 million ( US$4 million ) to Regulatory assets and Other long-term liabilities, respectively, and a decrease of $14 million ( US$11 million ) and $2 million ( US$2 million ) to Intangible and other assets and Regulatory liabilities, respectively. Temporary differences created as a result of the fair value changes described above resulted in deferred income tax assets and liabilities that were recorded at the Company's U.S. effective tax rate of 39 per cent . The fair value of Columbia’s non-controlling interest was based on the approximately 53.8 million Columbia Pipeline Partners LP (CPPL) common units outstanding to the public as of June 30, 2016 , and valued at the June 30, 2016 closing price of US$15.00 per common unit . Acquisition expenses of approximately $36 million are included in Plant operating costs and other in the Consolidated statement of income. Upon completing the acquisition, the Company began consolidating Columbia. Columbia’s significant accounting policies are consistent with TransCanada’s and continue to be applied. Columbia contributed $929 million to the Company's Revenues and $132 million to the Company's Net income from the acquisition date 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 ) |
ASSETS HELD FOR SALE
ASSETS HELD FOR SALE | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
ASSETS HELD FOR SALE | ASSETS HELD FOR SALE U.S. Northeast Power Assets The Company’s planned monetization of its U.S. Northeast power business, for the purposes of permanently financing the Columbia acquisition, includes the sale of Ravenswood, Ironwood, Kibby Wind, Ocean State Power, TC Hydro and the marketing business, TransCanada Power Marketing (TCPM). On November 1, 2016 , the Company entered into agreements to sell all of these assets except TCPM. The sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power to a third party for proceeds of approximately US$2.2 billion is expected to close in the first half of 2017. As a result, a loss of approximately $829 million ( $863 million after tax) was recorded in 2016 and was included in (Loss)/gain on assets held for sale/sold in the Consolidated statement of income and included the impact of an estimated $70 million of foreign currency translation gains to be reclassified from AOCI to Net income on close. At December 31, 2016 , the related assets and liabilities were classified as held for sale in the Energy segment and were recorded at their fair values less costs to sell based on the proceeds expected on the close of this sale. The sale of TC Hydro to another third party for proceeds of approximately US$1.1 billion is also expected to close in the first half of 2017, and is expected to result in an estimated gain of $710 million ( $440 million after tax) including the impact of an estimated $5 million of foreign currency translation gains. This gain will be recognized upon closing of the sale transaction. At December 31, 2016 , the related assets and liabilities were classified as held for sale in the Energy segment. As of December 31, 2016 , TCPM did not meet the criteria to be classified as held for sale. The following table details the assets and liabilities held for sale at December 31, 2016 . (millions of $) U.S. Canadian 1 Assets held for sale Accounts receivable 13 18 Inventories 56 75 Other current assets 90 121 Plant, property and equipment 2,229 2,993 2 Intangible and other assets 328 440 Foreign currency translation gains — 70 3 Total assets held for sale 2,716 3,717 Liabilities related to assets held for sale Accounts payable and other 32 43 Other long-term liabilities 32 43 Total liabilities related to assets held for sale 64 86 1 At December 31, 2016 exchange rate of $1.34 . 2 Includes $ 17 million (US$ 13 million ) for a gas plant held for sale in the U.S. Natural Gas Pipelines segment. 3 Foreign currency translation gains related to the investments in Ravenswood, Ironwood, Kibby Wind and Ocean State Power will be reclassified from AOCI to Net Income on close of the sale. TC Offshore LLC On March 1, 2016, the Company closed the sale of TC Offshore LLC. This resulted in an additional loss on disposal of $4 million pre-tax which is included in (Loss)/gain on assets held for sale/sold in the Consolidated statement of income. On December 18, 2015 , the Company entered into an agreement to sell TC Offshore LLC to a third party. At December 31, 2015 , the related assets and liabilities were classified as held for sale in the U.S. Natural Gas Pipelines segment and were recorded at their fair values less costs to sell. This resulted in a loss of $ 125 million pre-tax in 2015 which was included in (Loss)/gain on assets held for sale/sold in the Consolidated statement of income. The estimated fair value of these assets was based on the proceeds expected on the close of this sale. |
OTHER CURRENT ASSETS
OTHER CURRENT ASSETS | 12 Months Ended |
Dec. 31, 2016 | |
Other Assets [Abstract] | |
OTHER CURRENT ASSETS | OTHER CURRENT ASSETS at December 31 2016 2015 (millions of Canadian $) Fair value of derivative contracts (Note 24) 376 442 Cash provided as collateral 313 590 Prepaid expenses 131 132 Regulatory assets (Note 10) 33 85 Other 1 55 89 908 1,338 1 Includes current portion of note receivable from the seller of Ravenswood of $ 55 million ( US$40 million ) at December 31, 2015 . As of November 1, 2016, all Ravenswood assets including the current portion of the note receivable have been reclassified to Assets held for sale (Note 6). |
PLANT, PROPERTY AND EQUIPMENT
PLANT, PROPERTY AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
PLANT, PROPERTY AND EQUIPMENT | PLANT, PROPERTY AND EQUIPMENT 2016 2015 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 8,814 3,951 4,863 8,456 3,820 4,636 Compression 2,447 1,499 948 2,188 1,404 784 Metering and other 1,124 519 605 1,096 489 607 12,385 5,969 6,416 11,740 5,713 6,027 Under construction 1,151 — 1,151 969 — 969 13,536 5,969 7,567 12,709 5,713 6,996 Canadian Mainline Pipeline 9,502 6,221 3,281 9,164 5,966 3,198 Compression 3,537 2,361 1,176 3,433 2,220 1,213 Metering and other 605 198 407 499 192 307 13,644 8,780 4,864 13,096 8,378 4,718 Under construction 219 — 219 257 — 257 13,863 8,780 5,083 13,353 8,378 4,975 Other Canadian Natural Gas Pipelines Other 1 1,728 1,273 455 1,705 1,213 492 Under construction 112 — 112 63 — 63 1,840 1,273 567 1,768 1,213 555 29,239 16,022 13,217 27,830 15,304 12,526 U.S. Natural Gas Pipelines Columbia Gas 2 Pipeline 3,072 13 3,059 — — — Compression 1,864 7 1,857 — — — Metering and other 2,542 34 2,508 — — — 7,478 54 7,424 — — — Under construction 1,127 — 1,127 — — — 8,605 54 8,551 — — — ANR Pipeline 1,468 349 1,119 1,449 350 1,099 Compression 1,494 260 1,234 1,101 187 914 Metering and other 988 254 734 977 252 725 3,950 863 3,087 3,527 789 2,738 Under construction 232 — 232 304 — 304 4,182 863 3,319 3,831 789 3,042 2016 2015 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,221 810 1,411 2,278 765 1,513 Great Lakes 2,106 1,155 951 2,157 1,155 1,002 Midstream 2,3 1,072 23 1,049 — — — Columbia Gulf 2 880 5 875 — — — Other 2,4 2,120 567 1,553 2,124 521 1,603 8,399 2,560 5,839 6,559 2,441 4,118 Under construction 346 — 346 8 — 8 8,745 2,560 6,185 6,567 2,441 4,126 21,532 3,477 18,055 10,398 3,230 7,168 Mexico Natural Gas Pipelines Pipeline 2,734 180 2,554 1,296 162 1,134 Compression 422 19 403 183 14 169 Metering and other 502 40 462 388 27 361 3,658 239 3,419 1,867 203 1,664 Under construction 1,108 — 1,108 1,959 — 1,959 4,766 239 4,527 3,826 203 3,623 Liquids Pipelines Keystone Pipeline System Pipeline 10,572 901 9,671 9,288 718 8,570 Pumping equipment 928 121 807 1,092 108 984 Tanks and other 2,521 286 2,235 3,034 228 2,806 14,021 1,308 12,713 13,414 1,054 12,360 Under construction 1,434 — 1,434 1,826 — 1,826 15,455 1,308 14,147 15,240 1,054 14,186 Energy 5 Natural Gas – Ravenswood — — — 2,607 654 1,953 Natural Gas – Other 6,7 2,696 696 2,000 3,361 1,164 2,197 Hydro, Wind and Solar 1,180 245 935 2,417 476 1,941 Natural Gas Storage and Other 731 146 585 740 132 608 4,607 1,087 3,520 9,125 2,426 6,699 Under construction 729 — 729 430 — 430 5,336 1,087 4,249 9,555 2,426 7,129 Corporate 410 130 280 267 82 185 76,738 22,263 54,475 67,116 22,299 44,817 1 Includes Foothills and Venture LP. 2 Acquired as part of Columbia on July 1, 2016. Refer to Note 5, Acquisition of Columbia for further information. 3 Includes Midstream and mineral rights at December 31, 2016 . 4 Includes Bison, Portland Natural Gas Transmission System, North Baja, Tuscarora, and Crossroads. 5 U.S. Northeast power assets except TCPM are excluded from the Energy net book value at December 31, 2016 as they have been classified as Assets held for sale. Refer to Note 6, Assets held for sale for further information. 6 Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities was $ 1,319 million and $ 335 million , respectively, at December 31, 2016 ( 2015 – $ 1,341 million and $ 302 million , respectively). Revenues of $ 212 million were recognized in 2016 ( 2015 – $ 235 million ; 2014 – $ 223 million ) through the sale of electricity under the related PPAs. 7 Includes Halton Hills, Coolidge, Bécancour, Mackay River and other natural gas-fired facilities. Keystone XL At December 31, 2016 , the Company reviewed its remaining investment in Keystone XL and related projects with a carrying value of $526 million ( 2015 – $621 million ) and found no events or changes in circumstance indicating that the carrying value may not be recoverable. At December 31, 2015 , the Company evaluated its investment in Keystone XL and related projects, including the Keystone Hardisty Terminal (KHT), for impairment in connection with the November 6, 2015 denial of the U.S. Presidential permit. As a result of the analysis, the Company recognized a non-cash impairment charge in its Liquids Pipelines segment of $ 3,686 million ($ 2,891 million after tax) based on the excess of the carrying value over the estimated fair value of $621 million of these assets. The impairment charge included $77 million ( $56 million after tax) for certain cancellation fees that will be incurred in the future if the project is ultimately abandoned. At December 31, 2015 , included in the estimated fair value of $621 million was $463 million related to plant and equipment. The fair value of these assets was based on the price that would be received on sale of the plant and equipment in its condition at December 31, 2015 . Key assumptions used in the determination of selling price included an estimated two year disposal period and the then current weak energy market conditions. The valuation considered a variety of potential selling prices that were based on the various markets that could be used in order to dispose of these assets. At December 31, 2015 , $158 million related to terminal assets, including KHT, was included in the fair value of $621 million . The fair value was determined using a discounted cash flow approach. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. The valuation techniques above required the use of unobservable inputs. As a result, the fair value was classified within Level III of the fair value hierarchy at December 31, 2015 . Refer to Note 24, Risk management and financial instruments for further information on the fair value hierarchy. Energy Turbine Impairment Following the evaluation of specific capital project opportunities in 2015, it was determined that the carrying value of certain Energy turbine equipment was not fully recoverable. These turbines had been previously purchased for a power development project that did not proceed. As a result, at December 31, 2015 , the Company recognized a non-cash impairment charge of $ 59 million ($ 43 million after tax) in the Energy segment. This impairment charge was based on the excess of the carrying value over the estimated fair value of the turbines, which was determined based on a comparison to similar assets available for sale in the market. |
EQUITY INVESTMENTS
EQUITY INVESTMENTS | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 2014 2016 2015 Canadian Natural Gas Pipelines TQM 50.0 % 12 12 12 71 72 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 92 85 76 597 664 Iroquois 2 50.0 % 54 51 43 309 238 Millennium 3 47.5 % 33 — — 295 — Pennant Midstream 3 47.0 % 6 — — 246 — Other Various 29 26 24 93 31 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % (3 ) — — 255 — Other 5 Various — 5 8 28 42 Liquids Pipelines Grand Rapids 50.0 % (1 ) — — 876 542 Other Various — — — 39 16 Energy Bruce Power 6,7 48.5 % 293 249 314 3,356 4,200 Portlands Energy 50.0 % 33 30 36 313 321 ASTC Power Partnership 50.0 % (37 ) (23 ) 8 — 21 Other Various 3 5 1 66 67 514 440 522 6,544 6,214 1 At December 31, 2016 , the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$116 million ( 2015 – US$117 million ) due to the fair value assessment of assets at the time of acquisition. 2 After the acquisition of an additional 4.87 per cent interest on March 31, 2016 and 0.65 per cent interest on May 1, 2016, TransCanada has an ownership interest of 50.0 per cent in Iroquois. Prior to these acquisitions, TransCanada had an ownership interest of 44.5 per cent. Refer to Note 26, Other acquisitions and dispositions for further information. 3 Acquired as part of Columbia. Reflects equity earnings from the date of acquisition to December 31, 2016 . 4 TransCanada has an ownership interest of 60.0 per cent in Sur de Texas, which is a jointly controlled entity resulting in equity accounting. 5 Includes TransCanada's share of equity income from TransGas pipeline and Gas Pacifico/INNERGY. In November 2014, the Company sold its interest in Gas Pacifico/INNERGY. 6 As a result of TransCanada's increased ownership in Bruce Power L.P. (Bruce B) and the merger of Bruce Power A L.P. (Bruce A) and Bruce B to form Bruce Power in December 2015, TransCanada has an ownership interest in Bruce Power of 48.5 per cent. Prior to the acquisition and merger, TransCanada applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. TransCanada continues to apply equity accounting to Bruce Power. Refer to Note 26, Other acquisitions and dispositions for further information. 7 At December 31, 2016 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $942 million ( 2015 – $973 million ) due to the fair value assessment of assets at the time of acquisitions. On March 7, 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 is 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, at March 31, 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 received from equity investments for the year ended December 31, 2016 were $ 1,571 million ( 2015 – $ 802 million ; 2014 – $ 738 million ) of which $ 727 million ( 2015 – $ 9 million ; 2014 – $ 12 million ) were returns of capital and are included in Investing activities in the Consolidated statement of cash flows. The returns of capital were mainly for distributions received from Bruce Power in 2016 from its financing program. Undistributed earnings from equity investments were $ 198 million and $ 551 million at December 31, 2015 and December 31, 2014 respectively. Contributions made to equity investments for the year ended December 31, 2016 were $ 765 million ( 2015 – $ 493 million ; 2014 – $ 256 million ) and are included in Investing activities in the Consolidated statement of cash flows. Summarized Financial Information of Equity Investments year ended December 31 2016 2015 2014 (millions of Canadian $) Income Revenues 4,336 4,337 4,814 Operating and other expenses (3,143 ) (3,254 ) (3,489 ) Net income 1,080 1,046 1,264 Net income attributable to TransCanada 514 440 522 at December 31 2016 2015 (millions of Canadian $) Balance Sheet Current assets 1,669 1,530 Non-current assets 15,853 13,190 Current liabilities (1,120 ) (1,370 ) Non-current liabilities (5,867 ) (3,116 ) |
RATE-REGULATED BUSINESSES
RATE-REGULATED BUSINESSES | 12 Months Ended |
Dec. 31, 2016 | |
Regulated Operations [Abstract] | |
RATE-REGULATED BUSINESSES | RATE-REGULATED BUSINESSES TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain Canadian liquids pipelines. Rate-regulated businesses account for and report assets and liabilities consistent with the economic impact of the way in which regulators establish rates, provided the rates established 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 normally reflected in the income statement are deferred on the balance sheet and are recognized in the income statement as the related amounts are included in service rates and recovered from or refunded to customers. 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 that actual costs and revenues are more or less than the forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur. The Company's significant Canadian natural gas pipelines are described below. NGTL System In April 2016, the NEB approved the NGTL System’s 2016-2017 Revenue Requirement Settlement. The terms of the two -year settlement include an ROE of 10.1 per cent on 40 per cent deemed equity, a continuation of the 2015 depreciation rates, a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration (OM&A) cost amount and flow-through treatment of all other costs. The NGTL System’s 2015 results reflect the terms of the 2015 Revenue Requirement Settlement. This one year settlement included a 10.1 per cent ROE on deemed common equity of 40 per cent , a continuation of the 2014 depreciation rates, a mechanism for sharing variances above and below a fixed annual OM&A cost amount that was based on an escalation of 2014 actual costs and flow-through treatment of all other costs. The NGTL System’s 2014 results reflect the terms of the 2013-2014 Revenue Requirement Settlement Application. This settlement included fixed annual OM&A costs and a 10.1 per cent ROE on a deemed common equity of 40 per cent and a continuation of 2013 depreciation rates. Any variance between fixed OM&A costs in the settlement and actual costs accrued to TransCanada. 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 continued use of deferral accounts, namely the long-term adjustment account (LTAA) and the bridging amortization account, to capture the surplus or the shortfall between the Company's revenues and cost of service for each year over the six -year fixed toll term of the NEB 2014 Decision. A toll review filing will be required for the 2018 to 2020 period. The Canadian Mainline's 2014 results reflect the terms of the NEB 2013 Decision. The decision established an ROE of 11.5 per cent on deemed common equity of 40 per cent and included mechanisms to achieve fixed tolls through use of the LTAA as well as establishment of a Tolls Stabilization Account (TSA) to capture the surplus or the shortfall between revenues and cost of service for each year over the five -year term of the decision. In addition, the NEB 2013 Decision provided an opportunity to generate incentive earnings by increasing revenues and reducing costs. U.S. Regulated Operations TransCanada's U.S. 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. natural gas pipelines to discount or negotiate rates on a non-discriminatory basis. The Company's significant regulated U.S. natural gas pipelines, based on effective ownership and total operated pipe length, are described below. Columbia Gas Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval. In 2013, the FERC approved a modernization settlement which provides for cost recovery and return on investment of up to US$1.5 billion over a five -year period to modernize the Columbia Gas system to improve system integrity and enhance service reliability and flexibility. In March 2016, an extension of this settlement was approved by the FERC, which will allow for the cost recovery and return on additional expanded scope investment of US$1.1 billion over a three -year period through 2020. Columbia Gulf Columbia Gulf’s natural gas transportation services are provided under a tariff at rates subject to FERC approval. In September 2016, the FERC issued an order approving an uncontested settlement following a FERC-initiated rate proceeding pursuant to section 5 of the NGA, which required a reduction in Columbia Gulf’s daily maximum recourse rate and addressed treatment of post-retirement benefits other than pensions, pension expense, and regulatory expenses. The FERC order also requires Columbia Gulf to file a general rate case under section 4 of the NGA by January 31, 2020, for rates to take effect by August 1, 2020. ANR Pipeline Company ANR Pipeline Company previously operated under rates established pursuant to a settlement approved by the FERC that was effective for all periods presented, beginning in 1997 through July 31, 2016. Effective August 1, 2016, ANR Pipeline Company began operating under new rates pursuant to a FERC-approved rate settlement in September 2016. Under terms of the September 2016 settlement, neither ANR Pipeline Company nor the settling parties can file to change or modify the new settlement rates to become effective earlier than August 1, 2019. However, ANR Pipeline Company is required to file for new rates to be effective no later than August 1, 2022. Great Lakes Great Lakes operates under rates established pursuant to a settlement approved by the FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018. Mexico Regulated Operations TransCanada's Mexican operations are regulated by the CRE and operate in accordance with CRE-approved tariffs. The rates in effect on TransCanada's Mexican gas pipelines were established based on CRE-approved contracts that provide for the recovery of costs of providing services. Regulatory Assets and Liabilities at December 31 2016 2015 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 861 894 n/a Operating and debt-service regulatory assets 2 1 47 1 Pensions and other post retirement benefits 3 382 210 n/a Foreign exchange on long-term debt 1,4 37 54 1-13 Other 74 64 n/a 1,355 1,269 Less: Current portion included in Other current assets (Note 7) 33 85 1,322 1,184 Regulatory Liabilities Operating and debt-service regulatory liabilities 2 47 32 1 Pensions and other post retirement benefits 3 180 — n/a ANR related post-employment and retirement benefits other than pension 5 141 147 n/a Long term adjustment account 6 659 231 45 Pipeline abandonment costs 541 285 n/a Bridging amortization account 6 451 456 14 Cost of removal 7 226 36 n/a Other 54 16 n/a 2,299 1,203 Less: Current portion included in Accounts payable and other (Note 14) 178 44 2,121 1,159 1 These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period. 2 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar year. 3 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates. The balances are excluded from the rate base and do not earn a return on investment. 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 what ANR estimated that 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 since a 1997 rate settlement. Pursuant to a FERC-approved September 2016 rate settlement, $106 million of the regulatory liability balance that accumulated between January 2007 and July 2016 will be resolved through a refund of $53 million to its customers and ANR amortizing $53 million over a three year period that began August 1, 2016. A remaining $41 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 and stabilize tolls during the 2015-2030 settlement term. 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 subsidiaries for future costs to be incurred. |
GOODWILL
GOODWILL | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL | GOODWILL The Company has recorded the following Goodwill on its acquisitions in the U.S.: (millions of Canadian $) U.S. Natural Gas Pipelines Energy Total Balance at January 1, 2015 3,074 960 4,034 Foreign exchange rate changes 593 185 778 Balance at December 31, 2015 3,667 1,145 4,812 Acquisition of Columbia (Note 5) 10,078 — 10,078 Impairment charge — (1,085 ) (1,085 ) Foreign exchange rate changes 213 (60 ) 153 Balance at December 31, 2016 13,958 — 13,958 As a result of information received during the process to monetize the Company's U.S. Northeast power business in the third quarter 2016 , it was determined that the fair value of Ravenswood did not exceed its carrying value, including goodwill. The fair value of the reporting unit was determined using a combination of methods including a discounted cash flow approach and a range of expected consideration from a potential sale. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. As a result, 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. The impairment charge was recorded prior to reclassification to Assets held for sale. Refer to Note 6, Assets held for sale for further detail. At December 31, 2016 , TransCanada's Goodwill included US$573 million (2015 – US$573 million ) related to the Great Lakes natural gas transportation business. During 2015 , TransCanada's share of this goodwill (net of non-controlling interests) increased by US$143 million , to US$386 million , as a result of a 2015 impairment charge of US$199 million recorded by TC PipeLines, LP on its equity method goodwill related to Great Lakes. On a consolidated basis, TransCanada's carrying value of its investment in Great Lakes was proportionately lower compared to the 46.45 per cent owned through TC PipeLines, LP. As a result, the estimated fair value of Great Lakes exceeded TransCanada's consolidated carrying value of the investment and no impairment was recorded in 2015. At December 31, 2016 , 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 changing natural gas flows in its market region as well as a change in the Company's view of other strategic alternatives to increase utilization of Great Lakes. Although evolving market conditions and other factors relevant to Great Lakes’ long term financial performance have remained relatively stable, 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. At December 31, 2016 , the estimated fair value of ANR exceeded its carrying value by less than 10 per cent. The fair value of this reporting unit was measured using a discounted cash flow analysis. Assumptions regarding ANR’s ability to realize long-term value depend upon trends in value for its storage services, continued growth in its asset base and favourable outcomes of future rate proceedings. The Company reduced long-term forecast cash flows from the reporting unit as compared to those utilized in previous impairment tests thereby reflecting the continued changes in the business environment. There is a risk that continued reductions in future cash flow forecasts and adverse changes in other key assumptions could result in a future impairment of a portion of the goodwill balance relating to ANR. The goodwill balance related to ANR at December 31, 2016 was US $1.9 billion (2015 – US $1.9 billion ). |
INTANGIBLE AND OTHER ASSETS
INTANGIBLE AND OTHER ASSETS | 12 Months Ended |
Dec. 31, 2016 | |
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |
INTANGIBLES AND OTHER ASSETS | INTANGIBLE AND OTHER ASSETS at December 31 2016 2015 (millions of Canadian $) Capital projects in development 2,094 1,814 Deferred income tax assets (Note 16) 392 15 Employee post-retirement benefits (Note 23) 189 18 Fair value of derivative contracts (Note 24) 133 168 PPAs — 220 Prepaid rent 1 — 230 Loans and advances 1 — 159 Other 218 478 3,026 3,102 1 TransCanada held a note receivable from the seller of Ravenswood of $ 165 million ( US$123 million ) and $ 214 million ( US$154 million ) as at December 31, 2016 and at December 31, 2015 , respectively,which bears interest at 6.75 per cent and matures in 2040. As of November 1, 2016, all Ravenswood assets including prepaid rent and the note receivable have been reclassified to Assets held for sale (Note 6). The current portion included in Other current assets was $ 55 million ( US$40 million ) at December 31, 2015 . The following amounts related to PPAs are included in Intangible and other assets: 2016 2015 at December 31 Cost Accumulated Amortization Net Book Cost Accumulated Amortization Net Book (millions of Canadian $) Sheerness — — — 585 390 195 Sundance A — — — 225 200 25 — — — 810 590 220 On March 7, 2016 , TransCanada issued notice to the Balancing Pool of the decision to terminate its Sheerness and Sundance A PPAs. In accordance with a provision in the PPAs, a buyer is permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. As a result of recent changes in law surrounding the Alberta Specified Gas Emitters Regulation, the Company expected increasing costs related to carbon emissions to continue throughout the remaining terms of the PPAs resulting in increasing unprofitability. As such, in 2016, the Company recognized a non-cash impairment charge of $211 million ($ 155 million after tax) in its Energy segment, which represented the carrying value of the PPAs. Upon final settlement of the PPA terminations 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. Amortization expense of $ 9 million was recognized in the Consolidated statement of income for the year ended December 31, 2016 ( 2015 and 2014 – $ 52 million ), prior to the termination of the arrangements. |
NOTES PAYABLE
NOTES PAYABLE | 12 Months Ended |
Dec. 31, 2016 | |
Short-term Debt [Abstract] | |
NOTES PAYABLE | NOTES PAYABLE 2016 2015 (millions of Canadian $, unless otherwise noted) Outstanding at December 31 Weighted Average Interest Rate per Annum at December 31 Outstanding at December 31 Weighted Average Interest Rate per Annum at December 31 Canadian 509 0.9 % 697 0.8 % U.S. (2016 – US$197; 2015 – US$376) 265 0.5 % 521 1.1 % 774 1,218 At December 31, 2016, Notes payable consists of commercial paper issued by TransCanada PipeLines Limited (TCPL), TransCanada American Investments Ltd. (TAIL) and TransCanada PipeLines USA Limited (TCPL USA). In December 2016, Columbia entered into a new US$ 1.0 billion credit facility. At December 31, 2016 , total committed revolving and demand credit facilities were $ 11.1 billion ( 2015 – $8.9 billion ). When drawn, interest on these lines of credit is charged at prime rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following: year ended December 31 (millions of Canadian $) at December 31, 2016 2016 2015 2014 Amount Unused Capacity Borrower Description Matures Cost to maintain $3 billion $3 billion TCPL Committed, syndicated, revolving, extendible credit facility that supports TCPL's Canadian commercial paper program and general corporate purposes December 2021 6 6 6 US$2 billion US$2 billion TCPL Committed, syndicated, revolving, extendible credit facility that supports TCPL's U.S. commercial paper program December 2017 1 — — US$1 billion US$0.9 billion TCPL USA Committed, syndicated, revolving, extendible credit facility that is used for TCPL USA general corporate purposes, guaranteed by TCPL December 2017 1 3 2 US$1 billion US$1 billion Columbia Committed, syndicated, revolving, extendible credit facility that is issued for Columbia's general corporate purposes and provides additional liquidity, guaranteed by TCPL December 2017 — — — US$0.5 billion US$0.5 billion TAIL Committed, syndicated, revolving, extendible credit facility that supports TAIL's commercial paper program, guaranteed by TCPL December 2017 2 2 1 $2.1 billion $0.7 billion TCPL/TCPL USA Supports the issuance of letters of credit and provides additional liquidity Demand — — — At December 31, 2016, the Company's operated affiliates had an additional $ 0.6 billion (2015 – $ 0.6 billion ) of undrawn capacity on committed credit facilities. |
ACCOUNTS PAYABLE AND OTHER
ACCOUNTS PAYABLE AND OTHER | 12 Months Ended |
Dec. 31, 2016 | |
Payables and Accruals [Abstract] | |
ACCOUNTS PAYABLE AND OTHER | ACCOUNTS PAYABLE AND OTHER at December 31 2016 2015 (millions of Canadian $) Trade payables 2,443 1,506 Fair value of derivative contracts (Note 24) 607 926 Unredeemed shares of Columbia 317 — Regulatory liabilities (Note 10) 178 44 Other 316 177 3,861 2,653 |
OTHER LONG-TERM LIABILITIES
OTHER LONG-TERM LIABILITIES | 12 Months Ended |
Dec. 31, 2016 | |
Deferred Costs, Noncurrent [Abstract] | |
OTHER LONG-TERM LIABILITIES | OTHER LONG-TERM LIABILITIES at December 31 2016 2015 (millions of Canadian $) Fair value of derivative contracts (Note 24) 330 625 Employee post-retirement benefits (Note 23) 448 380 Asset retirement obligations 108 109 Guarantees (Note 27) 82 26 Other 215 120 1,183 1,260 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Provision for Income Taxes year ended December 31 2016 2015 2014 (millions of Canadian $) Current Canada 116 44 103 Foreign 40 92 42 156 136 145 Deferred Canada 101 33 309 Foreign 95 (135 ) 377 196 (102 ) 686 Income Tax Expense 352 34 831 Geographic Components of Income year ended December 31 2016 2015 2014 (millions of Canadian $) Canada 219 (624 ) 1,146 Foreign 618 (482 ) 1,678 Income/(Loss) before Income Taxes 837 (1,106 ) 2,824 Reconciliation of Income Tax Expense year ended December 31 2016 2015 2014 (millions of Canadian $) Income/(Loss) before income taxes 837 (1,106 ) 2,824 Federal and provincial statutory tax rate 27 % 26 % 25 % Expected income tax expense/(recovery) 226 (288 ) 706 Income tax differential related to regulated operations 81 159 129 Foreign tax rate differentials (196 ) 14 25 Income from equity investments and non-controlling interests (68 ) (56 ) (38 ) Asset impairment charges 1 242 170 — Non-deductible amounts 46 — — Tax rate and legislative changes — 34 — Other 21 1 9 Actual Income Tax Expense 352 34 831 1 Net of $112 million (2015 - $311 million ) attributed to higher foreign tax rates. Deferred Income Tax Assets and Liabilities at December 31 2016 2015 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 2,063 1,327 Difference in accounting and tax bases of impaired assets and assets held for sale 1,168 916 Regulatory and other deferred amounts 277 231 Unrealized foreign exchange losses on long-term debt 446 589 Financial instruments 34 111 Other 352 136 4,340 3,310 Less: valuation allowance 1 1,336 1,060 3,004 2,250 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 9,015 6,441 Equity investments 905 656 Taxes on future revenue requirement 198 227 Other 156 55 10,274 7,379 Net Deferred Income Tax Liabilities 7,270 5,129 1 In 2016, an increase to the valuation allowance of $ 276 million was recorded as the Company believes that it is more likely than not that the tax benefits related to the unrealized foreign exchange losses on long-term debt, unrealized losses on certain impaired assets, certain operating losses and capital losses will not be realized in the future. The above deferred tax amounts have been classified in the Consolidated balance sheet as follows: at December 31 2016 2015 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 12) 392 15 Deferred Income Tax Liabilities Deferred income tax liabilities 7,662 5,144 Net Deferred Income Tax Liabilities 7,270 5,129 At December 31, 2016 , the Company has recognized the benefit of unused non-capital loss carryforwards of $ 1,786 million ( 2015 – $ 1,283 million ) for federal and provincial purposes in Canada, which expire from 2029 to 2036. In addition, the Company has no t recognized the benefit of capital loss carry forwards of $654 million (2015 – $75 million ) for federal and provincial purposes in Canada. The Company also has Ontario minimum tax credits of $68 million (2015 – $57 million ), which expire from 2027 to 2036. At December 31, 2016 , the Company has recognized the benefit of unused net operating loss carryforwards of US$ 2,545 million ( 2015 – US$ 1,617 million ) for federal purposes in the U.S., which expire from 2028 to 2036. The Company has no t recognized the benefit of unused net operating loss carryforwards of US $58 million (2015 – nil ) for federal purposes in the U.S. The Company also has alternative minimum tax credits of US$37 million (2015 – US$41 million ). At December 31, 2016 , the Company has recognized the benefit of unused net operating loss carryforwards of US$ 54 million (2015 – US $70 million ) in Mexico, which expire from 2024 to 2025. 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, 2016 by approximately $ 481 million ( 2015 – $ 308 million ) if there had been a provision for these taxes. Income Tax Payments Income tax payments of $ 105 million , net of refunds, were made in 2016 ( 2015 – payments, net of refunds, of $ 162 million ; 2014 – payments, net of refunds, of $ 109 million ). Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2016 2015 2014 (millions of Canadian $) Unrecognized tax benefit at beginning of year 17 18 23 Gross increases – tax positions in prior years 3 2 3 Gross decreases – tax positions in prior years — (2 ) (8 ) Gross increases – tax positions in current year 2 1 1 Settlement (1 ) — — Lapse of statutes of limitations (3 ) (2 ) (1 ) Unrecognized Tax Benefit at End of Year 18 17 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 2008. 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, 2016 reflects nil of interest expense and nil for penalties ( 2015 – $ 1 million reversal of interest expense and nil for penalties; 2014 – $ 1 million of interest expense and nil for penalties). At December 31, 2016 , the Company had $ 4 million accrued for interest expense and nil accrued for penalties ( December 31, 2015 – $ 4 million accrued for interest expense and nil accrued for penalties). |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT 2016 2015 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Debentures Canadian 2017 to 2020 599 10.7 % 599 10.7 % U.S. (2016 and 2015 – US$400) 2021 536 9.9 % 553 9.9 % Medium Term Notes Canadian 2017 to 2046 5,787 4.6 % 5,175 5.3 % Senior Unsecured Notes U.S. (2016 – US$14,517; 2015 – US$14,641) 2017 to 2045 19,521 5.1 % 20,245 4.8 % Acquisition Bridge Facility (2016 – US$2,006) 2 2018 2,693 1.9 % — — 29,136 26,572 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 324 11.5 % U.S. (2016 and 2015 – US$200) 2023 268 7.9 % 276 7.9 % Medium Term Notes Canadian 2025 to 2030 503 7.4 % 503 7.4 % U.S. (2016 and 2015 – US$33) 2026 43 7.5 % 44 7.5 % 914 1,147 TRANSCANADA PIPELINE USA LTD. Acquisition Bridge Facility (2016 – US$1,695) 2 2018 2,276 1.9 % — — COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2016 – US$2,968) 3 2018 to 2045 3,985 3.7 % — — TC PIPELINES, LP Unsecured Loan Facility U.S. (2016 – US$158; 2015 – US$200) 2021 213 1.9 % 277 1.6 % Unsecured Term Loan U.S. (2016 and 2015 – US$670) 2018 899 1.9 % 927 1.6 % Senior Unsecured Notes U.S. (2016 and 2015 – US$694) 2021 to 2025 932 4.7 % 957 4.7 % 2,044 2,161 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2016 – US$671; 2015 – US$432) 2021 to 2026 901 7.2 % 597 8.9 % GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2016 – US$65; 2015 – US$75) 2019 87 1.6 % 104 1.4 % Senior Unsecured Notes U.S. (2016 and 2015 – US$250) 2020 to 2035 335 5.6 % 346 5.6 % 422 450 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2016 – US$278; 2015 – US$297) 2018 to 2030 373 7.7 % 411 7.8 % 2016 2015 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Secured Notes 4 U.S. (2016 – US$52; 2015 – US$69) 2018 70 6.0 % 96 6.1 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2016 – US$10) 2019 13 1.9 % — — Senior Secured Notes U.S. (2016 – US$12; 2015 – US$16) 2017 16 4.0 % 22 4.0 % 29 22 40,150 31,456 Less: Current portion of Long-term debt 1,838 2,547 38,312 28,909 1 Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates. 2 These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at London Interbank Offered Rate (LIBOR) plus an applicable margin. Proceeds from the U.S. Northeast power business monetization will be used to repay the majority of these facilities. 3 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. 4 Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements. Principal Repayments At December 31, 2016, principal repayments on the Long-term debt of the Company for the next five years are approximately as follows: (millions of Canadian $) 2017 2018 2019 2020 2021 Principal repayments on Long-term debt 1,838 8,941 1,742 2,762 2,165 Long-Term Debt Issued The Company issued Long-term debt over the three years ended December 31, 2016 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED June 2016 Acquisition Bridge Facility 1 June 2018 US 5,213 Floating June 2016 Medium Term Notes July 2023 300 3.69 % 2 June 2016 Medium Term Notes June 2046 700 4.35 % January 2016 Senior Unsecured Notes January 2026 US 850 4.875 % January 2016 Senior Unsecured Notes January 2019 US 400 3.125 % November 2015 Senior Unsecured Notes November 2017 US 1,000 1.625 % October 2015 Medium Term Notes November 2041 400 4.55 % July 2015 Medium Term Notes July 2025 750 3.30 % March 2015 Senior Unsecured Notes March 2045 US 750 4.60 % January 2015 Senior Unsecured Notes January 2018 US 500 1.875 % January 2015 Senior Unsecured Notes January 2018 US 250 Floating February 2014 Senior Unsecured Notes March 2034 US 1,250 4.63 % TRANSCANADA PIPELINE USA LTD. June 2016 Acquisition Bridge Facility 1 June 2018 US 1,700 Floating ANR PIPELINE COMPANY June 2016 Senior Unsecured Notes June 2026 US 240 4.14 % TUSCARORA GAS TRANSMISSION COMPANY April 2016 Term Loan April 2019 US 10 Floating TC PIPELINES, LP September 2015 Unsecured Term Loan October 2018 US 170 Floating March 2015 Senior Unsecured Notes March 2025 US 350 4.375 % GAS TRANSMISSION NORTHWEST LLC June 2015 Unsecured Term Loan June 2019 US 75 Floating 1 These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the monetization of the U.S. Northeast power business will be used to repay these facilities. 2 Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTN were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent. Long-Term Debt Retired/Repaid The Company retired/repaid Long-term debt over the three years ended December 31, 2016 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED November 2016 Acquisition Bridge Facility 1 US 3,200 Floating October 2016 Medium Term Notes 400 4.65 % June 2016 Senior Unsecured Notes US 84 7.69 % June 2016 Senior Unsecured Notes US 500 Floating January 2016 Senior Unsecured Notes US 750 0.75 % August 2015 Debentures 150 11.90 % June 2015 Senior Unsecured Notes US 500 3.40 % March 2015 Senior Unsecured Notes US 500 0.875 % January 2015 Senior Unsecured Notes US 300 4.875 % June 2014 Debentures 125 11.10 % February 2014 Medium Term Notes 300 5.05 % January 2014 Medium Term Notes 450 5.65 % NOVA GAS TRANSMISSION LTD. February 2016 Debentures 225 12.20 % June 2014 Debentures 53 11.20 % GAS TRANSMISSION NORTHWEST LLC June 2015 Senior Unsecured Notes US 75 5.09 % 1 Proceeds from the November 2016 common equity offering were used to partially repay the Acquisition Bridge Facility. Interest Expense Interest expense over the three years ended December 31 was as follows: year ended December 31 2016 2015 2014 (millions of Canadian $) Interest on Long-term debt 1,765 1,487 1,317 Interest on Junior subordinated notes (Note 18) 180 116 70 Interest on short-term debt 18 16 15 Capitalized interest (176 ) (280 ) (259 ) Amortization and other financial charges 1 211 31 55 1,998 1,370 1,198 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 $ 1,721 million in 2016 ( 2015 – $ 1,266 million ; 2014 – $ 1,123 million ) on long-term debt, junior subordinated notes and notes payable, net of interest capitalized. |
JUNIOR SUBORDINATED NOTES
JUNIOR SUBORDINATED NOTES | 12 Months Ended |
Dec. 31, 2016 | |
Junior Subordinated Notes [Abstract] | |
JUNIOR SUBORDINATED NOTES | JUNIOR SUBORDINATED NOTES 2016 2015 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED U.S. (2016 and 2015 – US$1,000) 1 2067 1,342 6.4 % 1,382 6.4 % U.S. (2016 and 2015 – US$742) 1, 2 2075 996 5.5 % 1,027 5.3 % U.S. (2016 – US$1,186) 1, 2 2076 1,593 6.2 % — — 3,931 2,409 1 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 2 The Junior subordinated notes were issued to TransCanada Trust (the 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 because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. In August 2016, TransCanada Trust (the Trust) issued US$1.2 billion of Trust Notes – Series 2016-A (Trust Notes) to third party investors at a fixed interest rate of 5.875 per cent for the first ten years , converting to a floating rate thereafter. All of the issuance proceeds of the Trust were loaned to TCPL for US$1.2 billion of junior subordinated notes of TCPL at an initial fixed rate of 6.125 per cent , including a 0.25 per cent administration charge. The rate will reset commencing August 2026 until August 2046 to the three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the three month LIBOR plus 5.64 per cent per annum. The junior subordinated notes are callable 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. In May 2015, the Trust issued US$750 million Trust Notes – Series 2015-A (Trust Notes) to third party investors at a fixed interest rate of 5.625 per cent for the first ten years , converting to a floating rate thereafter. All of the issuance proceeds of the Trust were loaned to TCPL for US$750 million of junior subordinated notes of TCPL at an initial fixed rate of 5.875 per cent , including a 0.25 per cent administration charge. The rate will reset commencing May 2025 until May 2045 to the three month LIBOR plus 3.778 per cent per annum; from May 2045 to May 2075 the interest rate will reset to the three month LIBOR plus 4.528 per cent per annum. The junior subordinated notes of TCPL are callable at TCPL's option at any time on or after May 20, 2025 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with other outstanding first preferred shares of TCPL. Junior subordinated notes of US$ 1.0 billion mature in May 2067 and bear interest at a fixed rate of 6.35 per cent per annum until May 15, 2017, when interest will convert to a floating rate that is reset quarterly to the three month LIBOR plus 2.21 per cent . TCPL has the option to defer payment of interest for periods of up to ten years without giving rise to a default or permitting acceleration of payment under the terms of the junior subordinated notes, however, both TransCanada and TCPL would be prohibited from paying dividends during any such deferral period. The junior subordinated notes are callable at TCPL's option at any time on or after May 15, 2017 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. The junior subordinated notes are callable earlier, in whole or in part, upon the occurrence of certain events and at the Company's option at an amount equal to the greater of 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption and an amount determined by a specified formula in accordance with their terms. |
NON-CONTROLLING INTERESTS
NON-CONTROLLING INTERESTS | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,596 1,590 Non-controlling interest in Portland Natural Gas Transmission System 130 127 1,726 1,717 The Company's Non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2016 2015 2014 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 215 (13 ) 136 Non-controlling interest in Portland Natural Gas Transmission System 20 19 15 Non-controlling interest in Columbia Pipeline Partners LP 17 — — Preferred shares of TCPL — — 2 252 6 153 During 2016 , the non-controlling interest in TC PipeLines, LP increased from 72.0 per cent to 73.2 per cent due to periodic issuances of common units in TC PipeLines, LP to third parties under an at-the-market issuance program (ATM program). In 2015 , the non-controlling interest in TC PipeLines, LP ranged between 71.7 per cent and 72.0 per cent and, in 2014 , between 71.1 per cent and 71.7 per cent . On July 1, 2016 , TransCanada acquired Columbia, which included a 53.5 per cent non-controlling interest in CPPL. On November 1, 2016 , TransCanada announced that it had entered into an agreement to acquire, for cash, all outstanding publicly held common units of CPPL. The transaction is expected to close in the first quarter of 2017 subject to receipt of CPPL unitholder approval and customary closing conditions. 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 because the potential rights of the units are not within the control of the Company. The non-controlling interest in Portland Natural Gas Transmission System (PNGTS) as at December 31, 2016 represented the 38.3 per cent interest held by third parties ( 2015 and 2014 – 38.3 per cent ). On January 1, 2016, TransCanada sold 49.9 per cent of PNGTS to TC PipeLines, LP. Refer to Note 26, Other acquisitions and disposition for further information. In 2016 , TransCanada received fees of $ 4.5 million from TC PipeLines, LP ( 2015 – $4 million and 2014 – $3 million ) and $ 8 million from PNGTS ( 2015 – $ 11 million ; 2014 – $8 million ) for services provided . At December 31, 2015 , TC PipeLines, LP recorded an impairment charge of US$199 million related to its equity investment in Great Lakes. The non-controlling interest's share of this charge was US$143 million and was included in the Net income attributable to non-controlling interests in the Consolidated statement of income. On March 5, 2014, TCPL redeemed all of its four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series Y at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends to the redemption date. Common Units of TC PipeLines, LP Subject to Rescission In connection with a late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the TC PipeLines, LP ATM program may have 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. No unitholder has claimed or attempted to exercise any rescission rights to date and these rights expire one year from the date of purchase of the unit. 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 are not within the control of the Company. |
COMMON SHARES
COMMON SHARES | 12 Months Ended |
Dec. 31, 2016 | |
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, 2014 707,441 12,149 Exercise of options 1,221 53 Outstanding at December 31, 2014 708,662 12,202 Exercise of options 737 30 Repurchase of shares (6,785 ) (130 ) Outstanding at December 31, 2015 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 1 Net of underwriting commissions and deferred income taxes. Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares without par value. Common Share Public Offering and Subscription Receipts On April 1, 2016, the Company issued 96.6 million subscription receipts to partially fund the Columbia acquisition 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 Columbia 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 was recorded as Interest expense. On November 16, 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 the offering were used to repay a portion of the US$6.9 billion acquisition bridge facilities which were used to partially fund the closing of the Columbia acquisition. 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 and Share Purchase Plan (DRP). Under this plan, eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent. Common Shares Repurchased On November 19, 2015, the Company received approval from the Toronto Stock Exchange (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 on November 22, 2016, the Company purchased these common shares through the facilities of the TSX, the New York Stock Exchange and other designated exchanges and published markets in both Canada and the U.S., 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 $ 44.9 0 for a total of $ 14 million and these shares had a weighted average cost of $ 6 million . The difference of $ 8 million between the total price paid and the weighted average cost was recorded in Additional paid-in capital. In December 2015, the Company repurchased 6,784,738 of its common shares at an average price of $ 43.29 for a total of $294 million and these shares had a weighted average cost of $130 million . The difference of $164 million between the total price paid and the weighted average cost was recorded in A dditional paid-in capital. Basic and Diluted Net Income/(Loss) per Common Share Net income/(loss) per common share is calculated by dividing Net income/(loss) attributable to common shares by the weighted average number of common shares outstanding. The higher weighted average number of shares for the diluted earnings per share calculation is due to options exercisable under TransCanada's Stock Option Plan. Weighted Average Common Shares Outstanding (millions) 2016 2015 2014 Basic 759 709 708 Diluted 760 709 710 Stock Options Number of (thousands) Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (years) Options outstanding at January 1, 2016 9,834 $46.63 Options granted 2,479 $48.44 Options exercised (1,683 ) $38.92 Options Outstanding at December 31, 2016 10,630 $48.28 4.2 Options Exercisable at December 31, 2016 5,957 $46.09 3.1 At December 31, 2016 , an additional 13,630,114 common shares were reserved for future issuance 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 33.3 per cent on the anniversary date in each of the three years following the award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation or termination of the option holder's employment. The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions: year ended December 31 2016 2015 2014 Weighted average fair value $5.67 $6.45 $5.54 Expected life (years) 5.8 5.8 6.0 Interest rate 0.7 % 1.1 % 1.8 % Volatility 1 21 % 18 % 17 % Dividend yield 4.9 % 3.7 % 3.8 % Forfeiture rate 5 % 5 % 5 % 1 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $ 15 million in 2016 ( 2015 – $ 13 million ; 2014 – $ 7 million ). The following table summarizes additional stock option information: year ended December 31 2016 2015 2014 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 31 10 21 Fair value of options that have vested 126 91 95 Total options vested 2.1 million 2.0 million 1.7 million As at December 31, 2016 , the aggregate intrinsic value of the total options exercisable was $ 86 million and the total intrinsic value of options outstanding was $ 130 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 two common shares of the Company for the then current market price of one . |
PREFERRED SHARES
PREFERRED SHARES | 12 Months Ended |
Dec. 31, 2016 | |
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 1 Redemption Price Per Share 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4,5 2016 2015 (thousands) (millions of Canadian $) 6 (millions of Canadian $) 6 Cumulative First Preferred Shares Series 1 9,498 3.266 % $0.8165 $25.00 December 31, 2019 Series 2 233 233 Series 2 12,502 Floating 7 Floating $25.00 December 31, 2019 Series 1 306 306 Series 3 8,533 2.152 % $0.538 $25.00 June 30, 2020 Series 4 209 209 Series 4 5,467 Floating 7 Floating $25.00 June 30, 2020 Series 3 134 134 Series 5 12,714 2.263 % $0.56575 $25.00 January 30, 2021 Series 6 310 342 Series 6 1,286 Floating 8 Floating $25.00 January 30, 2021 Series 5 32 — Series 7 24,000 4.00 % $1.00 $25.00 April 30, 2019 Series 8 589 589 Series 9 18,000 4.25 % $1.0625 $25.00 October 30, 2019 Series 10 442 442 Series 11 10,000 3.80 % $0.95 $25.00 November 30, 2020 Series 12 244 244 Series 13 20,000 5.50 % $1.375 $25.00 May 31, 2021 Series 14 493 — Series 15 40,000 4.90 % $1.3292 $25.00 May 31, 2022 Series 16 988 — 3,980 2,499 1 The holder is 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. 2 TransCanada may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the 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. 3 The holder will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter. 4 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. 5 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, equal to 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 per cent (Series 15). 6 Net of underwriting commissions and deferred income taxes. 7 The floating quarterly dividend rate for the Series 2 preferred shares is 2.429 per cent and for the Series 4 preferred shares is 1.789 per cent for the period starting December 30, 2016 to, but excluding, March 31, 2017. These rates will reset each quarter going forward. 8 The floating quarterly dividend rate for the Series 6 preferred shares is 2.073 per cent for the period starting October 30, 2016 to, but excluding, January 31, 2017. 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 . In March 2015, TransCanada completed a public offering of 10 million Series 11 cumulative redeemable first preferred shares at $25.00 per share, resulting in gross proceeds of $250 million . In June 2015, holders of 5,466,595 Series 3 cumulative redeemable first preferred shares exercised their option to convert to Series 4 cumulative redeemable first preferred shares. |
OTHER COMPREHENSIVE (LOSS)_INCO
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS | OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS Components of Other comprehensive (loss)/income, including the portion attributable to non-controlling interests and related tax effects, are as follows: year ended December 31, 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 to net income of actuarial loss on pension and other post-retirement benefit plans 22 (6 ) 16 Other comprehensive loss on equity investments (117 ) 30 (87 ) Other Comprehensive Loss (29 ) (3 ) (32 ) year ended December 31, 2015 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 798 15 813 Change in fair value of net investment hedges (505 ) 133 (372 ) Change in fair value of cash flow hedges (92 ) 35 (57 ) Reclassification to net income of gains and losses on cash flow hedges 144 (56 ) 88 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 74 (23 ) 51 Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans 41 (9 ) 32 Other comprehensive income on equity investments 62 (15 ) 47 Other Comprehensive Income 522 80 602 year ended December 31, 2014 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 462 55 517 Change in fair value of net investment hedges (373 ) 97 (276 ) Change in fair value of cash flow hedges (118 ) 49 (69 ) Reclassification to net income of gains and losses on cash flow hedges (95 ) 40 (55 ) Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (146 ) 44 (102 ) Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans 25 (7 ) 18 Other comprehensive loss on equity investments (272 ) 68 (204 ) Other Comprehensive Loss (517 ) 346 (171 ) 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, 2014 (629 ) (4 ) (197 ) (104 ) (934 ) Other comprehensive income/(loss) before reclassifications 2 111 (69 ) (102 ) (206 ) (266 ) Amounts reclassified from accumulated other comprehensive loss — (55 ) 18 2 (35 ) Net current period other comprehensive income/(loss) 111 (124 ) (84 ) (204 ) (301 ) AOCI balance at December 31, 2014 (518 ) (128 ) (281 ) (308 ) (1,235 ) Other comprehensive income/(loss) before reclassifications 2 135 (57 ) 51 33 162 Amounts reclassified from accumulated other comprehensive loss — 88 32 14 134 Net current period other comprehensive income 135 31 83 47 296 AOCI balance at December 31, 2015 (383 ) (97 ) (198 ) (261 ) (939 ) Other comprehensive income/(loss) before reclassifications 2 7 27 (26 ) (101 ) (93 ) Amounts reclassified from accumulated other comprehensive loss 3 — 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 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 Other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $14 million ( 2015 – $306 million gains; 2014 – $130 million gains) and gains of $3 million ( 2015 and 2014 - nil), respectively in 2016 . 3 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months are estimated to be $5 million ( $3 million , net of tax) at December 31, 2016 . These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. Details about reclassifications out of AOCI into the Consolidated statement of income are as follows: Amounts Reclassified From 1 Affected Line Item year ended December 31 2016 2015 2014 (millions of Canadian $) Cash flow hedges Commodities (57 ) (128 ) 111 Revenues (Energy) Interest (14 ) (16 ) (16 ) Interest expense (71 ) (144 ) 95 Total before tax 29 56 (40 ) Income tax expense/(recovery) (42 ) (88 ) 55 Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial loss and past service cost (22 ) (41 ) (25 ) Plant operating costs and other 2 6 9 7 Income tax expense (16 ) (32 ) (18 ) Net of tax Equity investments Equity income (19 ) (19 ) (2 ) Income from equity investments 5 5 — Income tax expense (14 ) (14 ) (2 ) Net of tax 1 All amounts in parentheses indicate expenses to the Consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost. Refer to Note 23, Employee post-retirement benefits for further information. |
EMPLOYEE POST-RETIREMENT BENEFI
EMPLOYEE POST-RETIREMENT BENEFITS | 12 Months Ended |
Dec. 31, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
EMPLOYEE POST-RETIREMENT BENEFITS | EMPLOYEE POST-RETIREMENT BENEFITS The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining service life of employees, which is approximately nine years at December 31, 2016 ( 2015 and 2014 – nine years ). The Company also provides its employees with a savings plan in Canada, DC Plans consisting of 401(k) Plans in the U.S., and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining life expectancy of former employees, which was approximately 12 years at December 31, 2016 ( 2015 – 12 years ; 2014 – 12 years ). In 2016 , the Company expensed $52 million ( 2015 – $41 million ; 2014 – $37 million ) for the savings and DC Plans. Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2016 2015 2014 (millions of Canadian $) DB Plans 111 96 73 Other post-retirement benefit plans 8 6 6 Savings and DC Plans 52 41 37 171 143 116 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 $20 million letter of credit to the Canadian DB Plan in 2016 ( 2015 – $33 million ; 2014 – $47 million ), resulting in a total of $233 million provided to the Canadian DB Plan under letters of credit at December 31, 2016 . The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2016 and the next required valuation will be as at January 1, 2017. The Company's funded status at December 31 is comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2016 2015 2016 2015 Change in Benefit Obligation 1 Benefit obligation – beginning of year 2,780 2,658 225 216 Service cost 107 108 3 3 Interest cost 127 115 13 10 Employee contributions 4 4 2 — Benefits paid (204 ) (129 ) (16 ) (7 ) Actuarial loss/(gain) 111 (57 ) (8 ) (11 ) Acquisition of Columbia 527 — 151 — Settlement loss 2 — — — Foreign exchange rate changes 2 81 2 14 Benefit obligation – end of year 3,456 2,780 372 225 Change in Plan Assets Plan assets at fair value – beginning of year 2,591 2,398 45 39 Actual return on plan assets 227 160 14 (1 ) Employer contributions 2 111 96 8 6 Employee contributions 4 4 2 — Benefits paid (204 ) (129 ) (16 ) (7 ) Acquisition of Columbia 475 — 294 — Foreign exchange rate changes 4 62 7 8 Plan assets at fair value – end of year 3,208 2,591 354 45 Funded Status – Plan Deficit (248 ) (189 ) (18 ) (180 ) 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 $233 million in letters of credit provided to the Canadian DB Plans for funding purposes ( 2015 – $214 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 $) 2016 2015 2016 2015 Intangible and other assets (Note 12) — — 189 18 Accounts payable and other — — (7 ) (7 ) Other long-term liabilities (Note 15) (248 ) (189 ) (200 ) (191 ) (248 ) (189 ) (18 ) (180 ) 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 $) 2016 2015 2016 2015 Projected benefit obligation 1 (3,456 ) (2,780 ) (207 ) (198 ) Plan assets at fair value 3,208 2,591 — — Funded Status – Plan Deficit (248 ) (189 ) (207 ) (198 ) 1 The projected benefit obligation for the pension benefit plan differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels. The funded status based on the accumulated benefit obligation for all DB Plans is as follows: at December 31 2016 2015 (millions of Canadian $) Accumulated benefit obligation (3,202 ) (2,600 ) Plan assets at fair value 3,208 2,591 Funded Status – Plan Surplus/(Deficit) 6 (9 ) 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 2016 2015 (millions of Canadian $) Accumulated benefit obligation (990 ) (807 ) Plan assets at fair value 868 680 Funded Status – Plan Deficit (122 ) (127 ) The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: Percentage of Target Allocations at December 31 2016 2015 2016 Debt securities 31 % 34 % 25% to 40% Equity securities 63 % 66 % 45% to 75% Alternatives 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 $) 2016 2015 2016 2015 Debt securities 9 2 0.2 % 0.1 % Equity securities 4 4 0.1 % 0.1 % Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities, as well as alternative assets such as infrastructure, private equity, real estate and derivatives to diversify risk. Derivatives are not used for speculative purposes and the use of leveraged derivatives is prohibited. All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted basis and by comparison to similar assets which are publicly traded. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets that the Company has the ability to access at the measurement date. In Level II, the fair value of assets is determined using valuation techniques, such as option pricing models and extrapolation using significant inputs, which are observable directly or indirectly. In Level III, the fair value of assets is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. For further information on the fair value hierarchy, refer to Note 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 $) 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 Asset Category Cash and Cash Equivalents 22 44 12 2 — — 34 46 1 2 Equity Securities: Canadian 388 317 143 147 — — 531 464 15 17 U.S. 504 589 476 40 — — 980 629 27 24 International 39 38 327 300 — — 366 338 10 13 Global — — 235 154 — — 235 154 7 6 Emerging 7 7 137 143 — — 144 150 4 6 Fixed Income Securities: Canadian Bonds: Federal — — 192 206 — — 192 206 5 8 Provincial — — 179 202 — — 179 202 5 8 Municipal — — 8 7 — — 8 7 — — Corporate — — 126 113 — — 126 113 4 4 U.S. Bonds: Federal — — 82 — — — 82 — 2 — State — — 41 50 — — 41 50 1 2 Municipal — — 39 — — — 39 — 1 — Corporate — — 188 57 — — 188 57 5 2 International: Government — — 6 — — — 6 — — — Corporate — — 21 25 — — 21 25 1 1 Mortgage backed — — 62 58 — — 62 58 2 2 Other Investments: Real Estate — — — — 133 — 133 — 4 — Infrastructure — — — — 58 — 58 — 2 — Private equity funds — — — — 8 14 8 14 — — Funds held on deposit 129 123 — — — — 129 123 4 5 1,089 1,118 2,274 1,504 199 14 3,562 2,636 100 100 The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Private Equity Funds Balance at December 31, 2014 13 Purchases and sales (1 ) Realized and unrealized gains 2 Balance at December 31, 2015 14 Purchases and sales 183 Realized and unrealized gains 2 Balance at December 31, 2016 199 The Company's expected funding contributions in 2017 are approximately $100 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $51 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $20 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 2017 178 19 2018 183 19 2019 189 20 2020 196 20 2021 200 20 2022 to 2026 1,067 97 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, 2016 . 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 2016 2015 2016 2015 Discount rate 4.00 % 4.20 % 4.15 % 4.40 % Rate of compensation increase 1.20 % 0.50 % — — 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 2016 2015 2014 2016 2015 2014 Discount rate 4.20 % 4.15 % 4.95 % 4.30 % 4.20 % 5.00 % Expected long-term rate of return on plan assets 6.70 % 6.95 % 6.90 % 5.95 % 4.60 % 4.60 % Rate of compensation increase 0.80 % 3.15 % 3.15 % — — — The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan. An eight per cent weighted average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2024 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects: (millions of Canadian $) Increase Decrease Effect on total of service and interest cost components 1 (1 ) Effect on post-retirement benefit obligation 15 (13 ) The Company's net benefit cost recognized is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2016 2015 2014 2016 2015 2014 Service cost 107 108 85 3 3 2 Interest cost 127 115 113 13 10 10 Expected return on plan assets (175 ) (155 ) (139 ) (11 ) (2 ) (2 ) Amortization of actuarial loss 20 35 21 2 3 2 Amortization of past service cost — 2 2 — 1 — Amortization of regulatory asset 27 23 18 1 1 1 Amortization of transitional obligation related to regulated business — — — 2 2 2 Net Benefit Cost Recognized 106 128 100 10 18 15 Pre-tax amounts recognized in AOCI were as follows: 2016 2015 2014 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 268 23 247 28 348 39 Prior service cost — — — — 2 1 268 23 247 28 350 40 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 2017 is $20 million and $2 million , respectively. Pre-tax amounts recognized in OCI were as follows: 2016 2015 2014 at December 31 Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits (millions of Canadian $) Amortization of net loss from AOCI to OCI (20 ) (2 ) (34 ) (4 ) (21 ) (2 ) Amortization of prior service costs from AOCI to OCI — — (2 ) (1 ) (2 ) — Funded status adjustment 43 (5 ) (67 ) (7 ) 137 9 23 (7 ) (103 ) (12 ) 114 7 |
RISK MANAGEMENT AND FINANCIAL I
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS | 12 Months Ended |
Dec. 31, 2016 | |
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 and cash flow. Risk management strategies, policies and limits are designed to ensure TransCanada's risks and related exposures are in line with the Company's business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits ultimately established by the Company's Board of Directors, implemented by senior management and monitored by the Company's risk management and internal audit groups. The Board of Directors' Audit Committee oversees how management monitors compliance with market risk and counterparty credit risk management policies and procedures, and oversees management's review of the adequacy of the risk management framework. 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 – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TransCanada enters into foreign exchange and commodity forwards and futures to manage the impact of changes in interest rates, foreign exchange rates and commodity prices • Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to manage the impact of changes in interest rates, foreign exchange rates and commodity prices • Options – contractual agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to manage the impact of changes in interest rates, foreign exchange rates and commodity prices. Commodity price risk The Company is exposed to commodity price movements as part of its normal business operations. A number of strategies are used to manage these exposures, including the following: • Subject to its overall risk management strategy, the Company commits a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to manage operational and price risks in its asset portfolio • The Company purchases a portion of the natural gas required for its power plants or enters into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin • The Company's power sales commitments are fulfilled through power generation or through purchased contracts, thereby reducing the Company's exposure to fluctuating commodity prices • The Company enters into offsetting or back-to-back positions using derivative instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points. Natural gas storage commodity price risk TransCanada manages its exposure to seasonal natural gas price spreads in its non-regulated Natural Gas Storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TransCanada simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to natural gas price movements. Unrealized gains and losses on fair value adjustments recorded each period on these forward contracts are not necessarily representative of the amounts that will be realized on settlement. Liquids marketing commodity price risk The liquids marketing business began operations in 2016. TransCanada enters into short-term or long-term pipeline and storage terminal capacity contracts, primarily on the Company's assets, increasing the utilization of those assets and earning the market value of the capacity. Derivative instruments are used to fix a portion of the variable price exposures that arise from physical liquids transactions. Foreign exchange and interest rate risk Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates. TransCanada generates revenues and incurs expenses that are denominated in currencies other than Canadian dollars. As a result, our earnings and cash flows are expected to fluctuate. A portion of TransCanada’s earnings from its U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy segments are generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TransCanada’s net income. As the Company’s U.S. dollar-denominated operations continue to grow, exposure to changes in currency rates increases. This foreign exchange impact is partially offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives. The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to other U.S. dollar-denominated transactions including those that may arise on some of the Company’s regulated assets. The realized gains and losses on these derivatives are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers. TransCanada has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk. Net investment in foreign operations The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps and foreign exchange forward contracts and foreign exchange options. U.S. Dollar-Denominated Debt Designated as a Net Investment Hedge The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2016 2015 (millions of Canadian $, unless otherwise noted) Notional amount 26,600 (US 19,800) 23,100 (US 16,700) Fair value 29,400 (US 21,900) 23,800 (US 17,200) Derivatives Designated as a Net Investment Hedge The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows: 2016 2015 at December 31 Fair 1 Notional or Fair 1 Notional or (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2017 to 2019) 2 (425 ) US 2,350 (730 ) US 3,150 U.S. dollar foreign exchange forward contracts (maturing 2017) (7 ) US 150 50 US 1,800 (432 ) US 2,500 (680 ) US 4,950 1 Fair values equal carrying values. 2 In 2016 , net realized gains of $6 million ( 2015 – gains of $8 million ) related to the interest component of cross-currency swap settlements are included in Interest expense. Counterparty Credit Risk Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the related contract or agreement with the Company. The Company manages its exposure to this potential loss by using recognized credit management techniques, including: • Dealing with creditworthy counterparties – a significant amount of the Company’s credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties • Setting limits on the amount TransCanada can transact with any one counterparty – the Company monitors and manages the concentration of risk exposure with any one counterparty, and reduces the exposure when necessary and when it is allowed under the terms of the contracts • Using contract netting arrangements and obtaining financial assurances such as guarantees, letters of credit or cash when deemed necessary. There is no guarantee that these techniques will protect the Company from material losses. TransCanada's maximum counterparty credit exposure with respect to financial instruments at December 31, 2016 , without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets, notes, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2016 , there were no significant amounts past due or impaired, and there were no significant credit losses during the year. The Company had a credit risk concentration due from a counterparty of $200 million ( US$149 million ) and $248 million ( US$179 million ) at December 31, 2016 and 2015 , respectively. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company. TransCanada has significant credit and performance exposures to financial institutions as they hold cash deposits and provide committed credit lines and letters of credit that help manage the Company's exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. For TransCanada's Canadian regulated gas pipeline assets, counterparty credit risk is managed through application of tariff provisions as approved by the NEB. Fair Value of Non-Derivative Financial Instruments The fair value of the Company's notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt and junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers. Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, 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 instruments. Balance Sheet Presentation of Non-Derivative Financial Instruments The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy: 2016 2015 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Notes receivable 1 165 211 214 265 Current and Long-term debt 2,3 (Note 17) (40,150 ) (45,047 ) (31,456 ) (34,309 ) Junior subordinated notes (Note 18) (3,931 ) (3,825 ) (2,409 ) (2,011 ) (43,916 ) (48,661 ) (33,651 ) (36,055 ) 1 Notes receivable are included in Assets held for sale on the Consolidated balance sheet at December 31, 2016 and in Other current assets and Intangible and other assets on the Consolidated balance sheet at December 31, 2015. The fair value is calculated based on the original contract terms. 2 Long-term debt is recorded at amortized cost, except for US$850 million ( 2015 – US$850 million ) that is attributed to hedged risk and recorded at fair value. 3 Consolidated net income in 2016 included unrealized gains of $2 million ( 2015 – gains of $2 million ) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of Long-term debt at December 31, 2016 ( 2015 – US$850 million ). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. Available for Sale Assets Summary The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets: 2016 2015 LMCI Restricted Investments 2 Other Restricted Investments 3 LMCI Restricted Investments 2 Other Restricted Investments 3 (millions of Canadian $) Fair values 1 Fixed income securities (maturing within 1 year) — 19 — 26 Fixed income securities (maturing within 1-5 years) — 117 — 64 Fixed income securities (maturing within 5-10 years) 9 — — — Fixed income securities (maturing after 10 years) 513 — 261 — Total fair value at December 31 522 136 261 90 Net unrealized losses for the year ended December 31 (28 ) (1 ) — — 1 Available for sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Consolidated balance sheet. 2 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. 3 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. Unrealized gains and losses on other restricted investments are included in OCI. Fair Value of Derivative Instruments The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments. In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period. 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 the derivative instruments as at December 31, 2016 is as follows: at December 31, 2016 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 6 — — 351 357 Foreign exchange — — 6 10 16 Interest rate 1 1 — 1 3 7 1 6 362 376 Intangible and other assets (Note 12) Commodities 2 4 — — 118 122 Foreign exchange — — 10 — 10 Interest rate 1 — — — 1 5 — 10 118 133 Total Derivative Assets 12 1 16 480 509 Accounts payable and other (Note 14) Commodities 2 — — — (330 ) (330 ) Foreign exchange — — (237 ) (38 ) (275 ) Interest rate (1 ) (1 ) — — (2 ) (1 ) (1 ) (237 ) (368 ) (607 ) Other long-term liabilities (Note 15) Commodities 2 — — — (118 ) (118 ) Foreign exchange — — (211 ) — (211 ) Interest rate — (1 ) — — (1 ) — (1 ) (211 ) (118 ) (330 ) Total Derivative Liabilities (1 ) (2 ) (448 ) (486 ) (937 ) 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 the derivative instruments as at December 31, 2015 is as follows: at December 31, 2015 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 46 — — 326 372 Foreign exchange — — 65 2 67 Interest rate — 1 — 2 3 46 1 65 330 442 Intangible and other assets (Note 12) Commodities 2 11 — — 126 137 Foreign exchange — — 29 — 29 Interest rate — 2 — — 2 11 2 29 126 168 Total Derivative Assets 57 3 94 456 610 Accounts payable and other (Note 14) Commodities 2 (112 ) — — (443 ) (555 ) Foreign exchange — — (313 ) (54 ) (367 ) Interest rate (1 ) (1 ) — (2 ) (4 ) (113 ) (1 ) (313 ) (499 ) (926 ) Other long-term liabilities (Note 15) Commodities 2 (31 ) — — (131 ) (162 ) Foreign exchange — — (461 ) — (461 ) Interest rate (1 ) (1 ) — — (2 ) (32 ) (1 ) (461 ) (131 ) (625 ) Total Derivative Liabilities (145 ) (2 ) (774 ) (630 ) (1,551 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power and natural gas. The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk. Notional and Maturity Summary The maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows: at December 31, 2016 Power Natural Gas Liquids Foreign Exchange Interest Purchases 1 86,887 182 6 — — Sales 1 58,561 147 6 — — Millions of dollars — — — US 2,394 US 1,550 Maturity dates 2017-2021 2017-2020 2017 2017 2017-2019 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. at December 31, 2015 Power Natural Gas Foreign Exchange Interest Purchases 1 70,331 133 — — Sales 1 54,382 70 — — Millions of dollars — — US 1,476 US 1,100 Maturity dates 2016–2020 2016–2020 2016 2016–2019 1 Volumes for power and natural gas derivatives are in GWh and Bcf, respectively . Unrealized and Realized Gains/(Losses) of Derivative Instruments The following summary does not include hedges of the net investment in foreign operations. year ended December 31 2016 2015 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 2 123 (37 ) Foreign exchange 25 (21 ) Amount of realized (losses)/gains in the year Commodities (204 ) (151 ) Foreign exchange 62 (112 ) Derivative instruments in hedging relationships Amount of realized (losses)/gains in the year Commodities (167 ) (179 ) Foreign exchange (101 ) — Interest rate 4 8 1 Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively. 2 Following the March 17, 2016 announcement of the Company's intention to sell the U.S. Northeast power assets, losses of $49 million and gains of $7 million (2015 - nil ) were recorded in net income in 2016 relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale. 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 2016 2015 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI (effective portion) 1 Commodities 2 39 (92 ) Interest rate 3 5 — 44 (92 ) Reclassification of gains on derivative instruments from AOCI to Net income (effective portion) 1 Commodities 2 57 128 Interest rate 3 14 16 71 144 Losses on derivative instruments recognized in Net income (ineffective portion) Commodities 2 — — 1 No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI. 2 Reported within Revenues on the Consolidated statement of income. 3 Reported within Interest expense on the Consolidated statement of income. Offsetting of derivative instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. 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: at December 31, 2016 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 479 (362 ) 117 Foreign exchange 26 (26 ) — Interest rate 4 (1 ) 3 509 (389 ) 120 Derivative – Liability Commodities (448 ) 362 (86 ) Foreign exchange (486 ) 26 (460 ) Interest rate (3 ) 1 (2 ) (937 ) 389 (548 ) 1 Amounts available for offset do not include cash collateral pledged or received. 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, 2015 : at December 31, 2015 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 509 (418 ) 91 Foreign exchange 96 (93 ) 3 Interest rate 5 (1 ) 4 610 (512 ) 98 Derivative – Liability Commodities (717 ) 418 (299 ) Foreign exchange (828 ) 93 (735 ) Interest rate (6 ) 1 (5 ) (1,551 ) 512 (1,039 ) 1 Amounts available for offset do not include cash collateral pledged or received. With respect to the derivative instruments presented above as at December 31, 2016 , the Company had provided cash collateral of $305 million ( 2015 – $482 million ) and letters of credit of $27 million ( 2015 – $41 million ) to its counterparties. The Company held nil ( 2015 – nil ) in cash collateral and $3 million ( 2015 – $2 million ) in letters of credit from counterparties on asset exposures at December 31, 2016 . Credit risk related contingent features of derivative instruments Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at December 31, 2016 , the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $19 million ( 2015 – $32 million ), for which the Company has provided collateral in the normal course of business of nil ( 2015 – nil ). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2016 , the Company would have been required to provide additional collateral of $19 million ( 2015 – $32 million ) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise. Fair Value Hierarchy The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. Levels How fair value has been determined Level I Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. Level II Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances. Level III Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category mainly 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 2016 , are categorized as follows: at December 31, 2016 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 134 326 19 479 Foreign exchange — 26 — 26 Interest rate — 4 — 4 Derivative Instrument Liabilities: Commodities (102 ) (343 ) (3 ) (448 ) Foreign exchange — (486 ) — (486 ) Interest rate — (3 ) — (3 ) 32 (476 ) 16 (428 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016 . The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2015 , are categorized as follows: at December 31, 2015 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 34 462 13 509 Foreign exchange — 96 — 96 Interest rate — 5 — 5 Derivative Instrument Liabilities: Commodities (102 ) (611 ) (4 ) (717 ) Foreign exchange — (828 ) — (828 ) Interest rate — (6 ) — (6 ) (68 ) (882 ) 9 (941 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2015 . The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy: (millions of Canadian $, pre-tax) 2016 2015 Balance at beginning of year 9 4 Total gains included in Net income 13 3 Sales (3 ) (2 ) Settlements (2 ) (1 ) Transfers out of Level III (1 ) 5 Balance at end of year 1 16 9 1 Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2016 of $7 million ( 2015 – $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, 2016 . |
CHANGES IN OPERATING WORKING CA
CHANGES IN OPERATING WORKING CAPITAL | 12 Months Ended |
Dec. 31, 2016 | |
CHANGES IN OPERATING WORKING CAPITAL | |
CHANGES IN OPERATING WORKING CAPITAL | CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2016 2015 2014 (millions of Canadian $) Increase in Accounts receivable (482 ) (65 ) (189 ) Increase in Inventories (87 ) (3 ) (28 ) Increase in Assets held for sale (13 ) — — Decrease/(increase) in Other current assets 328 (272 ) (385 ) Increase/(decrease) in Accounts payable and other 424 (97 ) 377 Increase in Accrued interest 62 91 36 Increase in Liabilities related to assets held for sale 16 — — Decrease/(increase) in Operating Working Capital 248 (346 ) (189 ) |
OTHER ACQUISITIONS AND DISPOSIT
OTHER ACQUISITIONS AND DISPOSITIONS | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
ACQUISITIONS AND DISPOSITIONS | ACQUISITIONS AND DISPOSITIONS U.S. Natural Gas Pipelines Portland Natural Gas Transmission System On January 1, 2016 , TransCanada completed the sale of a 49.9 per cent interest in PNGTS to TC PipeLines, LP for an aggregate purchase price of US$223 million . Proceeds were comprised of US$188 million in cash and the assumption of US$35 million of a proportional share of PNGTS debt. TC Offshore LLC On March 1, 2016, the Company closed the sale of TC Offshore LLC. This resulted in an additional loss on disposal of $4 million pre-tax which is included in (Loss)/gain on sale of assets held for sale/sold in the Consolidated statement of income. Iroquois Gas Transmission System LP On March 31, 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 . Gas Transmission Northwest LLC In April 2015 , TransCanada completed the sale of its remaining 30 per cent interest in GTN to TC PipeLines, LP for an aggregate purchase price of US$457 million . Proceeds were comprised of US$264 million in cash, the assumption of US$98 million of a proportional share of GTN debt and US$95 million of new Class B units of TC PipeLines, LP. Bison Pipeline LLC In October 2014 , TransCanada completed the sale of its remaining 30 per cent interest in Bison to TC PipeLines, LP for an aggregate purchase price of US$215 million . Mexico Natural Gas Pipelines Gas Pacifico/INNERGY In November 2014, TransCanada sold its 30 per cent equity investments in Gas Pacifico and INNERGY for aggregate gross proceeds of $9 million and recognized a gain of $9 million ( $8 million after tax). Energy Ironwood On February 1, 2016, TransCanada acquired the Ironwood natural gas fired, combined cycle power plant in Lebanon, Pennsylvania, with a capacity of 778 MW, for US$653 million in cash after post-acquisition adjustments. The Ironwood power plant delivers energy into the PJM power market. 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 has not had a material impact on the Revenues and Net income of the Company. In addition, the pro forma incremental impact on the Company’s Revenues and Net income for each of the periods presented is not material. At December 31, 2016, Ironwood is classified as an asset held for sale. Refer to Note 6, Assets held for sale for further information. Bruce Power In December 2015, TransCanada exercised its option to acquire an additional 14.89 per cent ownership interest in Bruce B from the Ontario Municipal Employees Retirement System for $236 million , increasing its ownership interest to 46.5 per cent . The difference between the purchase price and the underlying carrying value of Bruce B is primarily related to the estimated fair value of the amended agreement with Ontario's Independent Electricity System Operator to extend the oper ating life of the Bruce Power facility to 2064. In December 2015, Bruce B and Bruce A merged to form a single limited partnership, Bruce Power. This merger was accounted for as a transaction between entities under common control whereby the assets and liabilities of Bruce A and Bruce B were combined at their carrying values. Upon completion of the merger, TransCanada applied equity accounting to its resulting 48.5 per cent ownership interest in Bruce Power. Prior to the acquisition, TransCanada applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. Ontario Solar As part of a purchase agreement with Canadian Solar Solutions Inc. signed in 2011, TransCanada completed the acquisition of four Ontario solar facilities for $241 million in 2014. All power produced by the solar facilities is sold under 20 -year PPAs with the Ontario Power Authority. Cancarb In April 2014, TransCanada sold Cancarb Limited and its related power generation for aggregate gross proceeds of $190 million and recognized a gain of $108 million ( $99 million after-tax). |
COMMITMENTS, CONTINGENCIES AND
COMMITMENTS, CONTINGENCIES AND GUARANTEES | 12 Months Ended |
Dec. 31, 2016 | |
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 $) 2017 129 5 124 2018 122 4 118 2019 106 2 104 2020 69 2 67 2021 69 1 68 2022 and thereafter 621 3 618 1,116 17 1,099 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 2016 was $145 million ( 2015 – $131 million ; 2014 – $114 million ). TransCanada's commitments at December 31, 2016 include future payments related to our U.S. Northeast power business. At the close of the sale of Ravenswood, TransCanada's commitments are expected to decrease by $54 million in 2017 and 2018, $35 million in 2019 and $106 million in 2022 and beyond. TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business. Other commitments Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts. At December 31, 2016 , TransCanada was committed to Canadian Natural Gas Pipelines capital expenditures totaling approximately $0.8 billion ( 2015 – $0.5 billion ), primarily related to construction costs associated with the NGTL System natural gas pipeline projects. At December 31, 2016 , TransCanada was committed to U.S. Natural Gas Pipelines capital expenditures totaling approximately $0.1 billion ( 2015 – $0.2 billion ), primarily related to construction costs associated with the ANR natural gas pipeline projects. At December 31, 2016 , TransCanada was committed to Mexico Natural Gas Pipelines capital expenditures totaling approximately $2.1 billion ( 2015 – $0.2 billion ), primarily related to construction on the Sur de Texas, Tula and Villa de Reyes Mexico gas pipeline projects. At December 31, 2016 , the Company was committed to Liquids Pipelines capital expenditures totaling approximately $0.2 billion ( 2015 – $0.8 billion ), primarily related to construction costs of Northern Courier. At December 31, 2016 , the Company was committed to Energy capital expenditures totaling approximately $0.5 billion ( 2015 – $0.6 billion ), primarily related to construction costs of the Napanee Generating Station. At December 31, 2016 , the Company was committed to Corporate expenditures totally approximately $0.2 billion ( 2015 – $0.1 billion ), primarily related to an information technology services agreement. Contingencies TransCanada is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2016 , the Company had accrued approximately $39 million ( 2015 – $32 million ; 2014 – $31 million ) related to operating facilities, which represents the present value of the estimated future amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue. TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. 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, other than the Keystone XL legal proceeding described below, will not have a material impact on the Company's consolidated financial position or results of operations. In June 2016, TransCanada filed a Request for Arbitration in a dispute against the U.S. Government pursuant to the Convention on Settlement of Investment Disputes between States and Nationals of Other States, the Rules of Procedure for the Institution of Conciliation and Arbitration Proceedings and Chapter 11 of the North American Free Trade Agreement (NAFTA). The claim arises out of the November 6, 2015 denial of our application for a Presidential Permit to construct Keystone XL. TransCanada has requested an award of damages arising from the U.S. Government’s breaches of its NAFTA obligations in an amount of more than US$15 billion together with applicable interest and the costs of arbitration. This arbitration is in a preliminary stage and the likelihood of success and resulting impact on the Company's financial position or results of operations is unknown at this time. Guarantees TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed a contingent financial obligation of Bruce Power related to a lease agreement. The Bruce Power guarantee has a term to 2018. The Company and its partners in certain jointly owned entities, including Sur de Texas, 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 including purchase agreements and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners. The carrying value of these guarantees has been included in Other long-term liabilities. Information regarding the Company’s guarantees is as follows: 2016 2015 year ended December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas Ranging to 2040 805 53 — — Bruce Power Ranging to 2018 88 1 88 2 Other jointly owned entities Ranging to 2040 87 28 139 24 980 82 227 26 1 TransCanada's share of the potential estimated current or contingent exposure. |
CORPORATE RESTRUCTURING COSTS
CORPORATE RESTRUCTURING COSTS | 12 Months Ended |
Dec. 31, 2016 | |
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 our existing operations. Restructuring costs consist primarily of severance and expected future losses under lease commitments. In 2015, the Company incurred $122 million before tax of restructuring costs and recorded a provision of $87 million before tax related to planned severance costs in 2016 and 2017 and expected future losses under lease commitments. In 2016, an additional provision of $44 million before tax was recorded related to changes to the expected future losses under lease commitments. Approximately $157 million and $22 million was recorded in Plant operating costs and other in the Consolidated statement of income for the years ended December 31, 2015 and 2016, respectively. In 2015, $58 million was recorded in Revenues in the Consolidated statement of income related to costs that were recoverable through regulatory and tolling structures. In addition, $44 million and $22 million was recorded as a Regulatory asset on the Consolidated balance sheet at December 31, 2015 and 2016, respectively, as these amounts are expected to be recovered through regulatory and tolling structures in future periods, and $8 million was capitalized in 2015 to projects impacted by the corporate restructuring. Changes in the restructuring liability were as follows: (millions of Canadian $) Employee Severance Lease Commitments Total Restructuring liability as at December 31, 2015 60 27 87 Restructuring charges — 44 44 Cash payments (24 ) (8 ) (32 ) Restructuring Liability as at December 31, 2016 36 63 99 |
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES As a result of the implementation of the new FASB guidance on consolidation, a number of entities controlled by TransCanada are now considered to be VIEs. 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 assets and liabilities of the consolidated VIEs whose assets cannot be used for purposes other than the settlement of the VIE’s obligations are as follows: at December 31 (millions of Canadian $) 2016 2015 ASSETS Current Assets Cash and cash equivalents 77 54 Accounts receivable 71 55 Inventories 25 25 Other 10 6 183 140 Plant, Property and Equipment 3,685 3,704 Equity Investments 606 664 Goodwill 525 541 Intangible and Other Assets 1 — 5,000 5,049 LIABILITIES Current Liabilities Accounts payable and other 80 74 Accrued interest 21 21 Current portion of long-term debt 76 45 177 140 Regulatory Liabilities 34 33 Other Long-Term Liabilities 4 4 Deferred Income Tax Liabilities 7 — Long-Term Debt 2,827 2,998 3,049 3,175 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 $) 2016 2015 Balance sheet Equity investments 4,964 5,410 Off-balance sheet Potential exposure to guarantees 163 227 Maximum exposure to loss 5,127 5,637 |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | [SUBSEQUENT EVENT] |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | Related party transactions The following amounts are included in Due from affiliates: 2016 2015 (unaudited - millions of Canadian $) Maturity Date Outstanding September 30 Effective Interest Rate Outstanding December 31 Effective Interest Rate Discount Notes 1 November 2016 2,392 0.9 % 2,376 0.9 % Credit Facility 2 Demand — — 100 2.7 % 2,392 2,476 1 Issued to TransCanada. Interest on the discount notes is equivalent to current commercial paper rates. 2 Issued to TransCanada. This facility is repayable on demand and bears interest at the prime rate per annum. In 2016 , Interest income and other included $16 million as a result of inter-affiliate lending to TransCanada ( 2015 - $29 million ; 2014 - $37 million ). At December 31, 2016 , Accounts receivable included nil due from TransCanada ( December 31, 2015 - $13 million ). The following amounts are included in Due to affiliates: Insert Title Here 2016 2015 (unaudited - millions of Canadian $) Maturity Date Outstanding September 30 Effective Interest Rate Outstanding December 31 Effective Interest Rate Credit Facility 1 December 2016 — — 311 3.5 % Credit Facility 2 Demand 2,358 2.7 % — — 2,358 311 1 TransCanada has an unsecured $3.5 billion credit facility with a subsidiary of TCPL. Interest on this facility is charged at the prime rate per annum. 2 TransCanada has an unsecured $3.0 billion credit facility with TCPL. Interest on this facility is charged at prime rate per annum. This credit facility includes $1.8 billion due to TransCanada related to the acquisition of Columbia. Refer to Note 5, Acquisition of Columbia for more information. In 2016 , Interest expense included $22 million of interest charges as a result of inter-affiliate borrowing ( 2015 - $28 million ; 2014 - $37 million ). At December 31, 2016 , Accounts payable and other included $3 million due to TransCanada ( December 31, 2015 - $12 million ). The company made interest payments of $20 million to TransCanada in 2016 ( 2015 - $29 million ; 2014 - $37 million ). |
ACCOUNTING POLICIES (Policies)
ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation These consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-controlling interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation. |
Use of Estimates and Judgments | 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. Significant estimates and judgments used in the preparation of the consolidated financial statements include, but are not limited to: • fair value of assets and liabilities acquired in a business combination (Note 5) • fair value and depreciation rates of plant, property and equipment (Note 8) • carrying value of regulatory assets and liabilities (Note 10) • fair value of goodwill (Note 11) • fair value of intangible assets (Note 12) • carrying value of asset retirement obligations (Note 15) • provisions for income taxes (Note 16) • assumptions used to measure retirement and other post-retirement obligations (Note 23) • fair value of financial instruments (Note 24) and • provision for commitments, contingencies, guarantees (Note 27) and restructuring (Note 28). Actual results could differ from these estimates. |
Regulation | Regulation In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB). In the U.S., natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). The Company's Canadian, U.S. and Mexican natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls. Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TransCanada's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain of its liquids pipelines projects. RRA is not applicable to the Keystone Pipeline System as the regulators' decisions regarding operations and tolls on that system generally do not have an impact on timing of recognition of revenues and expenses. |
Revenue Recognition | Revenue Recognition Natural Gas Pipelines and Liquids Pipelines Transportation Revenues from the Company's natural gas and liquids pipelines, with the exception of Canadian natural gas pipelines which are subject to RRA, are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made. Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline tolls are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines generally are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines, at times, are subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues are recognized on firm contracted capacity ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenue are recorded when the NEB decision is received. The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. Revenues from the Company's Mexican natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and recognized ratably over the contract period. Other volumes shipped on these pipelines are subject to CRE-approved tariffs. The Company does not take ownership of the gas that it transports for others. Regulated Natural Gas Storage Revenues from the Company's regulated natural gas storage services are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the gas that it stores for others. Midstream and Other Revenues from the Company's midstream natural gas services, including gathering, treating, conditioning, processing, compression and liquids handling services, are generated from volumetric based contractual arrangements and are recognized ratably over the contract period regardless of the amount of natural gas that is subject to these services. The Company also owns mineral rights in association with certain storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest. Royalties from mineral interests are recognized when product is produced. Energy Power Revenues from the Company's Energy business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative instruments and hedging activities policy in this note. Non-Regulated Natural Gas Storage Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. |
Inventories | Inventories Inventories primarily consist of natural gas inventory in storage, crude oil in transit, materials and supplies including spare parts and fuel. Inventories are all carried at the lower of weighted average cost or market. |
Plant, Property and Equipment | Plant, Property and Equipment Natural Gas Pipelines Plant, property and equipment for natural gas pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to six per cent, and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in plant, property and equipment and the equity component of AFUDC is a non-cash expenditure with a corresponding credit recognized in Allowance for funds used during construction in the Consolidated statement of income. Interest is capitalized during construction of non-regulated natural gas pipelines. Natural gas storage base gas, which is valued at cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. Natural gas storage base gas is not depreciated. When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove a plant from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Midstream and Other Plant, property and equipment for midstream assets are 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 and amortization are derecognized and any gain or loss is recorded in net income. The Company participates as a working interest partner in the development of Marcellus and Utica acreage. The working interest allows the Company to invest in the drilling activities in addition to 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 are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction for non-regulated liquids pipelines and AFUDC for regulated pipelines. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in net income. Energy Power generation and natural gas storage plant, equipment and structures are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in net income. Natural gas storage base gas, which is valued at original cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. Natural gas storage base gas is not depreciated. Corporate Corporate plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent. Capitalized Project Costs The Company capitalizes project costs once advancement to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest for non-regulated projects in development and AFUDC for regulated projects. Capital projects in development are included in Intangible and other assets. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to Plant, property and equipment under construction. When the asset is ready for its intended use and available for operations, capitalized project costs are depreciated in accordance with the Company's depreciation policies. |
Assets Held For Sale and Impairment of Long-Lived Assets | Assets Held For Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next twelve months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, reduced for selling costs, and any losses are recognized in Net income. Depreciation expense is no longer recorded once assets are classified as held for sale. Impairment of Long-Lived Assets The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows or the estimated sale price is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset. |
Acquisitions and Goodwill | Acquisitions and Goodwill The Company accounts for business acquisitions 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 initially assesses qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the first step of the two- step impairment test is performed by comparing the fair value of the reporting unit to its carrying value, which includes goodwill. If the fair value of the reporting unit is less than its carrying value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference. |
Power Purchase Arrangements | Power Purchase Arrangements A power purchase 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. Prior to their termination, substantially all the PPAs under which TransCanada purchased power were also accounted for as operating leases, and initial payments to acquire these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts. A portion of these PPAs were subleased to third parties under terms and conditions similar to the PPAs, and were also accounted for as operating leases with the margin earned from the subleases recorded in Revenues. During 2016, the Company terminated these PPAs and recorded an impairment charge. Refer to Note 12, Intangible and other assets, for further information. |
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 during which they occur except for changes in balances related to the Canadian regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the NEB. D eferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet. Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. |
Asset Retirement Obligations | Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Operating and other expenses. The Company has recorded ARO related to its non-regulated natural gas storage operations, mineral rights and certain power generation facilities. The scope and timing of asset retirements related to most of the Company's natural gas pipelines, liquids pipelines and hydroelectric power plants is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities and certain facilities expected to be retired as part of an ongoing modernization program |
Environmental Liabilities | Environmental Liabilities The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability. Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and expensed when they are utilized. Compliance costs are expensed when incurred. Allowances granted to or internally generated by 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. The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets. |
Employee Post-Retirement Benefits | Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five -year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service life of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income/(loss) (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated other comprehensive income/(loss) (AOCI) and into Net income over the average remaining service life of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees. |
Foreign Currency Transactions and Translation | Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or reporting subsidiary operates, 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 and are designated for hedge accounting treatment, which includes fair value and cash flow hedges, and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in Net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in Net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in Net income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects Net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to Net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. In hedging the foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in Net income. The amounts recognized previously in AOCI are reclassified to Net income in the event the Company reduces its net investment in a foreign operation. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in Net income in the period of change. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as Regulatory assets or Regulatory liabilities and are refunded to or collected from the ratepayers, in subsequent years when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in Net income. |
Long-Term Debt Transaction Costs | Long-Term Debt Transaction Costs The Company records long-term debt transaction costs as a deduction from the carrying amount of the related debt and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms. |
Guarantees | Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company or partially owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments, Plant, property and equipment, or a charge to Net income, and a corresponding liability is recorded in Other long-term liabilities. |
Accounting Changes | Changes in Accounting Policies for 2016 Extraordinary and unusual income statement items In January 2015, the Financial Accounting Standards Board (FASB) issued new guidance on extraordinary and unusual income statement items. This update eliminates the concept of extraordinary items from GAAP. This new guidance was effective January 1, 2016 , was applied prospectively and did not have an impact on the Company’s consolidated financial statements. Consolidation In February 2015, the FASB issued new guidance on consolidation. This guidance requires that entities re-evaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance was effective January 1, 2016 , was applied retrospectively and did not result in any change to the Company's consolidation conclusions. Disclosure requirements outlined in the new guidance are included in Note 29, Variable interest entities. Imputation of interest In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. This guidance requires that debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of the related debt liability consistent with debt discounts or premiums. This new guidance was effective January 1, 2016 , was applied retrospectively and resulted in a reclassification of debt issuance costs previously recorded in Intangible and other assets to an offset of their respective debt liabilities on the Company’s Consolidated balance sheet. Business combinations In September 2015, the FASB issued guidance which intends to simplify the accounting measurement period adjustments in business combinations. The amended guidance requires an acquirer to recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In the period the adjustment was determined, the guidance also requires the acquirer to record the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This new guidance was effective January 1, 2016 , was applied prospectively and did not have a material impact on the Company's consolidated financial statements. Classification of certain cash receipts and cash payments In August 2016, the FASB issued new guidance to clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows. This new guidance is effective January 1, 2018, however, since early adoption is permitted, the Company elected to retrospectively apply this guidance effective December 31, 2016 . The application of this guidance did not have a material impact on the classification of debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and proceeds from the settlement of corporate owned life insurance. The Company has elected to classify distributions received from equity method investments using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investments that generated the distributions. As a result, certain comparative period distributions received from equity method investments have been reclassified from investing activities to cash generated from operations in the Consolidated statement of cash flows. Future Accounting Changes Revenue from contracts with customers In 2014, the FASB issued new guidance on revenue from contracts with customers. Current guidance allows for revenue recognition when certain criteria are met. The new guidance requires that an entity recognize revenue in accordance with a five-step model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The Company will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. The Company is evaluating both methods of adoption as it works through its analysis. The Company has identified all existing customer contracts that are within the scope of the new guidance and has begun to analyze individual contracts or groups of contracts to identify any significant differences and the impact on revenues as a result of implementing the new standard. As the Company continues its contract analysis, it will also quantify the impact, if any, on prior period revenues. The Company will address any system and process changes necessary to compile the information to meet the disclosure requirements of the new standard. As the Company is currently evaluating the impact of this standard, it has not yet determined the effect on its consolidated financial statements. Inventory In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements. Financial instruments In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018. 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. Leases In February 2016, the FASB issued new guidance on leases. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees may be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019, however, the Company is evaluating the option to early adopt. The Company is currently identifying existing lease agreements that may have an impact on the Company's consolidated financial statements as a result of adopting this new guidance. Derivatives and hedging In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks. This new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. Equity method investments In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. In these situations, when an increase in ownership interest in an investment qualifies it for equity method accounting, the new guidance eliminates the requirement to retroactively apply the equity method of accounting. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. Employee share-based payments In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. This new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. 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 instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Consolidation In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entity (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. Income taxes In October 2016, the FASB issued new guidance on income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied on a modified retrospective basis. Early adoption is permitted. 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. 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, and amounts generally described as restricted cash or restricted cash equivalents. The amounts of restricted cash and cash equivalents will be included in Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively. Early adoption is permitted. 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. |
SEGMENTED INFORMATION (Tables)
SEGMENTED INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment | year ended December 31, 2016 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate Total (millions of Canadian $) Revenues 3,682 2,526 378 1,755 4,164 — 12,505 Income from equity investments 12 214 (3 ) (1 ) 292 — 514 Plant operating costs and other (1,181 ) (1,000 ) (42 ) (554 ) (834 ) (208 ) (3,819 ) Commodity purchases resold — — — — (2,172 ) — (2,172 ) Property taxes (267 ) (120 ) — (88 ) (80 ) — (555 ) Depreciation and amortization (873 ) (397 ) (43 ) (285 ) (293 ) (48 ) (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) 1,373 1,219 290 827 (1,140 ) (256 ) 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 1,525 1,517 944 810 473 33 5,302 year ended December 31, 2015 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate Total (millions of Canadian $) Revenues 3,680 1,444 259 1,879 4,038 — 11,300 Income from equity investments 12 162 5 — 261 — 440 Plant operating costs and other (1,162 ) (555 ) (49 ) (491 ) (786 ) (207 ) (3,250 ) Commodity purchases resold — — — — (2,237 ) — (2,237 ) Property taxes (272 ) (77 ) — (79 ) (89 ) — (517 ) Depreciation and amortization (845 ) (243 ) (44 ) (266 ) (336 ) (31 ) (1,765 ) Asset impairment charges — — — (3,686 ) (59 ) — (3,745 ) Loss on assets held for sale/sold — (125 ) — — — — (125 ) Segmented earnings/(losses) 1,413 606 171 (2,643 ) 792 (238 ) 101 Interest expense (1,370 ) Allowance for funds used during construction 295 Interest income and other (132 ) Loss before income taxes (1,106 ) Income tax expense (34 ) Net loss (1,140 ) Net income attributable to non-controlling interests (6 ) Net loss attributable to controlling interests (1,146 ) Preferred share dividends (94 ) Net loss attributable to common shares (1,240 ) Capital spending Capital expenditures 1,366 534 566 1,012 376 64 3,918 Capital projects in development 230 3 — 278 — — 511 1,596 537 566 1,290 376 64 4,429 year ended December 31, 2014 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Energy Corporate Total (millions of Canadian $) Revenues 3,557 1,159 197 1,547 3,725 — 10,185 Income from equity investments 12 143 8 — 359 — 522 Plant operating costs and other (1,028 ) (467 ) (41 ) (439 ) (934 ) (64 ) (2,973 ) Commodity purchases resold — — — — (1,836 ) — (1,836 ) Property taxes (266 ) (68 ) — (62 ) (77 ) — (473 ) Depreciation and amortization (821 ) (211 ) (31 ) (216 ) (309 ) (23 ) (1,611 ) Gain on assets held for sale/sold — — 9 — 108 — 117 Segmented earnings/(losses) 1,454 556 142 830 1,036 (87 ) 3,931 Interest expense (1,198 ) Allowance for funds used during construction 136 Interest income and other (45 ) Income before income taxes 2,824 Income tax expense (831 ) Net income 1,993 Net income attributable to non-controlling interests (153 ) Net income attributable to controlling interests 1,840 Preferred share dividends (97 ) Net income attributable to common shares 1,743 Capital spending Capital expenditures 814 237 717 1,469 206 46 3,489 Capital projects in development 327 40 1 480 — — 848 1,141 277 718 1,949 206 46 4,337 at December 31 2016 2015 (millions of Canadian $) Total Assets Canadian Natural Gas Pipelines 15,816 15,038 U.S. Natural Gas Pipelines 34,422 12,207 Mexico Natural Gas Pipelines 5,013 3,787 Liquids Pipelines 16,896 16,046 Energy 13,169 15,614 Corporate 2,735 1,706 88,051 64,398 |
Revenue from External Customers by Geographic Areas | year ended December 31 2016 2015 2014 (millions of Canadian $) Revenues Canada – domestic 3,655 3,877 3,956 Canada – export 1,177 1,292 1,314 United States 7,295 5,872 4,718 Mexico 378 259 197 12,505 11,300 10,185 |
Schedule of Long-Lived Assets by Country | at December 31 2016 2015 (millions of Canadian $) Plant, Property and Equipment Canada 20,531 19,287 United States 29,414 21,899 Mexico 4,530 3,631 54,475 44,817 |
ACQUISITION OF COLUMBIA (Tables
ACQUISITION OF COLUMBIA (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The acquisition has been accounted for as a business combination using the acquisition method where the acquired tangible and intangible assets and assumed liabilities are 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 of Net Assets Acquired Current assets 658 856 Plant, property and equipment 7,560 9,835 Equity investments 441 574 Regulatory assets 190 248 Intangibles and other assets 135 175 Current liabilities (597 ) (777 ) Regulatory liabilities (294 ) (383 ) Other long-term liabilities (144 ) (187 ) Deferred income tax liabilities (1,613 ) (2,098 ) Long-term debt (2,981 ) (3,878 ) Non-controlling interests (808 ) (1,051 ) Fair Value of Net Assets Acquired 2,547 3,314 Goodwill (Note 11) 7,747 10,078 1 At July 1, 2016 exchange rate of $1.30 . |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments | The following table summarizes the acquisition date fair value of Columbia's debt acquired by 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$1000) 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 ) |
ASSETS HELD FOR SALE (Tables)
ASSETS HELD FOR SALE (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Assets To Be Disposed Of | The following table details the assets and liabilities held for sale at December 31, 2016 . (millions of $) U.S. Canadian 1 Assets held for sale Accounts receivable 13 18 Inventories 56 75 Other current assets 90 121 Plant, property and equipment 2,229 2,993 2 Intangible and other assets 328 440 Foreign currency translation gains — 70 3 Total assets held for sale 2,716 3,717 Liabilities related to assets held for sale Accounts payable and other 32 43 Other long-term liabilities 32 43 Total liabilities related to assets held for sale 64 86 1 At December 31, 2016 exchange rate of $1.34 . 2 Includes $ 17 million (US$ 13 million ) for a gas plant held for sale in the U.S. Natural Gas Pipelines segment. 3 Foreign currency translation gains related to the investments in Ravenswood, Ironwood, Kibby Wind and Ocean State Power will be reclassified from AOCI to Net Income on close of the sale. |
OTHER CURRENT ASSETS (Tables)
OTHER CURRENT ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Assets [Abstract] | |
Schedule of Other Current Assets | at December 31 2016 2015 (millions of Canadian $) Fair value of derivative contracts (Note 24) 376 442 Cash provided as collateral 313 590 Prepaid expenses 131 132 Regulatory assets (Note 10) 33 85 Other 1 55 89 908 1,338 1 Includes current portion of note receivable from the seller of Ravenswood of $ 55 million ( US$40 million ) at December 31, 2015 . As of November 1, 2016, all Ravenswood assets including the current portion of the note receivable have been reclassified to Assets held for sale (Note 6). |
PLANT, PROPERTY AND EQUIPMENT (
PLANT, PROPERTY AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Plant, Property and Equipment | 2016 2015 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 8,814 3,951 4,863 8,456 3,820 4,636 Compression 2,447 1,499 948 2,188 1,404 784 Metering and other 1,124 519 605 1,096 489 607 12,385 5,969 6,416 11,740 5,713 6,027 Under construction 1,151 — 1,151 969 — 969 13,536 5,969 7,567 12,709 5,713 6,996 Canadian Mainline Pipeline 9,502 6,221 3,281 9,164 5,966 3,198 Compression 3,537 2,361 1,176 3,433 2,220 1,213 Metering and other 605 198 407 499 192 307 13,644 8,780 4,864 13,096 8,378 4,718 Under construction 219 — 219 257 — 257 13,863 8,780 5,083 13,353 8,378 4,975 Other Canadian Natural Gas Pipelines Other 1 1,728 1,273 455 1,705 1,213 492 Under construction 112 — 112 63 — 63 1,840 1,273 567 1,768 1,213 555 29,239 16,022 13,217 27,830 15,304 12,526 U.S. Natural Gas Pipelines Columbia Gas 2 Pipeline 3,072 13 3,059 — — — Compression 1,864 7 1,857 — — — Metering and other 2,542 34 2,508 — — — 7,478 54 7,424 — — — Under construction 1,127 — 1,127 — — — 8,605 54 8,551 — — — ANR Pipeline 1,468 349 1,119 1,449 350 1,099 Compression 1,494 260 1,234 1,101 187 914 Metering and other 988 254 734 977 252 725 3,950 863 3,087 3,527 789 2,738 Under construction 232 — 232 304 — 304 4,182 863 3,319 3,831 789 3,042 2016 2015 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,221 810 1,411 2,278 765 1,513 Great Lakes 2,106 1,155 951 2,157 1,155 1,002 Midstream 2,3 1,072 23 1,049 — — — Columbia Gulf 2 880 5 875 — — — Other 2,4 2,120 567 1,553 2,124 521 1,603 8,399 2,560 5,839 6,559 2,441 4,118 Under construction 346 — 346 8 — 8 8,745 2,560 6,185 6,567 2,441 4,126 21,532 3,477 18,055 10,398 3,230 7,168 Mexico Natural Gas Pipelines Pipeline 2,734 180 2,554 1,296 162 1,134 Compression 422 19 403 183 14 169 Metering and other 502 40 462 388 27 361 3,658 239 3,419 1,867 203 1,664 Under construction 1,108 — 1,108 1,959 — 1,959 4,766 239 4,527 3,826 203 3,623 Liquids Pipelines Keystone Pipeline System Pipeline 10,572 901 9,671 9,288 718 8,570 Pumping equipment 928 121 807 1,092 108 984 Tanks and other 2,521 286 2,235 3,034 228 2,806 14,021 1,308 12,713 13,414 1,054 12,360 Under construction 1,434 — 1,434 1,826 — 1,826 15,455 1,308 14,147 15,240 1,054 14,186 Energy 5 Natural Gas – Ravenswood — — — 2,607 654 1,953 Natural Gas – Other 6,7 2,696 696 2,000 3,361 1,164 2,197 Hydro, Wind and Solar 1,180 245 935 2,417 476 1,941 Natural Gas Storage and Other 731 146 585 740 132 608 4,607 1,087 3,520 9,125 2,426 6,699 Under construction 729 — 729 430 — 430 5,336 1,087 4,249 9,555 2,426 7,129 Corporate 410 130 280 267 82 185 76,738 22,263 54,475 67,116 22,299 44,817 1 Includes Foothills and Venture LP. 2 Acquired as part of Columbia on July 1, 2016. Refer to Note 5, Acquisition of Columbia for further information. 3 Includes Midstream and mineral rights at December 31, 2016 . 4 Includes Bison, Portland Natural Gas Transmission System, North Baja, Tuscarora, and Crossroads. 5 U.S. Northeast power assets except TCPM are excluded from the Energy net book value at December 31, 2016 as they have been classified as Assets held for sale. Refer to Note 6, Assets held for sale for further information. 6 Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities was $ 1,319 million and $ 335 million , respectively, at December 31, 2016 ( 2015 – $ 1,341 million and $ 302 million , respectively). Revenues of $ 212 million were recognized in 2016 ( 2015 – $ 235 million ; 2014 – $ 223 million ) through the sale of electricity under the related PPAs. 7 Includes Halton Hills, Coolidge, Bécancour, Mackay River and other natural gas-fired facilities. |
EQUITY INVESTMENTS (Tables)
EQUITY INVESTMENTS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 2014 2016 2015 Canadian Natural Gas Pipelines TQM 50.0 % 12 12 12 71 72 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 92 85 76 597 664 Iroquois 2 50.0 % 54 51 43 309 238 Millennium 3 47.5 % 33 — — 295 — Pennant Midstream 3 47.0 % 6 — — 246 — Other Various 29 26 24 93 31 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % (3 ) — — 255 — Other 5 Various — 5 8 28 42 Liquids Pipelines Grand Rapids 50.0 % (1 ) — — 876 542 Other Various — — — 39 16 Energy Bruce Power 6,7 48.5 % 293 249 314 3,356 4,200 Portlands Energy 50.0 % 33 30 36 313 321 ASTC Power Partnership 50.0 % (37 ) (23 ) 8 — 21 Other Various 3 5 1 66 67 514 440 522 6,544 6,214 1 At December 31, 2016 , the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$116 million ( 2015 – US$117 million ) due to the fair value assessment of assets at the time of acquisition. 2 After the acquisition of an additional 4.87 per cent interest on March 31, 2016 and 0.65 per cent interest on May 1, 2016, TransCanada has an ownership interest of 50.0 per cent in Iroquois. Prior to these acquisitions, TransCanada had an ownership interest of 44.5 per cent. Refer to Note 26, Other acquisitions and dispositions for further information. 3 Acquired as part of Columbia. Reflects equity earnings from the date of acquisition to December 31, 2016 . 4 TransCanada has an ownership interest of 60.0 per cent in Sur de Texas, which is a jointly controlled entity resulting in equity accounting. 5 Includes TransCanada's share of equity income from TransGas pipeline and Gas Pacifico/INNERGY. In November 2014, the Company sold its interest in Gas Pacifico/INNERGY. 6 As a result of TransCanada's increased ownership in Bruce Power L.P. (Bruce B) and the merger of Bruce Power A L.P. (Bruce A) and Bruce B to form Bruce Power in December 2015, TransCanada has an ownership interest in Bruce Power of 48.5 per cent. Prior to the acquisition and merger, TransCanada applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. TransCanada continues to apply equity accounting to Bruce Power. Refer to Note 26, Other acquisitions and dispositions for further information. 7 At December 31, 2016 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $942 million ( 2015 – $973 million ) due to the fair value assessment of assets at the time of acquisitions. |
Summary of Financial Information of Equity Investments | year ended December 31 2016 2015 2014 (millions of Canadian $) Income Revenues 4,336 4,337 4,814 Operating and other expenses (3,143 ) (3,254 ) (3,489 ) Net income 1,080 1,046 1,264 Net income attributable to TransCanada 514 440 522 at December 31 2016 2015 (millions of Canadian $) Balance Sheet Current assets 1,669 1,530 Non-current assets 15,853 13,190 Current liabilities (1,120 ) (1,370 ) Non-current liabilities (5,867 ) (3,116 ) |
RATE-REGULATED BUSINESSES (Tabl
RATE-REGULATED BUSINESSES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets and Liabilities | at December 31 2016 2015 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 861 894 n/a Operating and debt-service regulatory assets 2 1 47 1 Pensions and other post retirement benefits 3 382 210 n/a Foreign exchange on long-term debt 1,4 37 54 1-13 Other 74 64 n/a 1,355 1,269 Less: Current portion included in Other current assets (Note 7) 33 85 1,322 1,184 Regulatory Liabilities Operating and debt-service regulatory liabilities 2 47 32 1 Pensions and other post retirement benefits 3 180 — n/a ANR related post-employment and retirement benefits other than pension 5 141 147 n/a Long term adjustment account 6 659 231 45 Pipeline abandonment costs 541 285 n/a Bridging amortization account 6 451 456 14 Cost of removal 7 226 36 n/a Other 54 16 n/a 2,299 1,203 Less: Current portion included in Accounts payable and other (Note 14) 178 44 2,121 1,159 1 These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period. 2 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar year. 3 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates. The balances are excluded from the rate base and do not earn a return on investment. 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 what ANR estimated that 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 since a 1997 rate settlement. Pursuant to a FERC-approved September 2016 rate settlement, $106 million of the regulatory liability balance that accumulated between January 2007 and July 2016 will be resolved through a refund of $53 million to its customers and ANR amortizing $53 million over a three year period that began August 1, 2016. A remaining $41 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 and stabilize tolls during the 2015-2030 settlement term. 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 subsidiaries for future costs to be incurred. |
GOODWILL (Tables)
GOODWILL (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of goodwill recorded on the entity's acquisitions in the U.S. | The Company has recorded the following Goodwill on its acquisitions in the U.S.: (millions of Canadian $) U.S. Natural Gas Pipelines Energy Total Balance at January 1, 2015 3,074 960 4,034 Foreign exchange rate changes 593 185 778 Balance at December 31, 2015 3,667 1,145 4,812 Acquisition of Columbia (Note 5) 10,078 — 10,078 Impairment charge — (1,085 ) (1,085 ) Foreign exchange rate changes 213 (60 ) 153 Balance at December 31, 2016 13,958 — 13,958 |
INTANGIBLE AND OTHER ASSETS (Ta
INTANGIBLE AND OTHER ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |
Schedule of Other Assets | at December 31 2016 2015 (millions of Canadian $) Capital projects in development 2,094 1,814 Deferred income tax assets (Note 16) 392 15 Employee post-retirement benefits (Note 23) 189 18 Fair value of derivative contracts (Note 24) 133 168 PPAs — 220 Prepaid rent 1 — 230 Loans and advances 1 — 159 Other 218 478 3,026 3,102 1 TransCanada held a note receivable from the seller of Ravenswood of $ 165 million ( US$123 million ) and $ 214 million ( US$154 million ) as at December 31, 2016 and at December 31, 2015 , respectively,which bears interest at 6.75 per cent and matures in 2040. As of November 1, 2016, all Ravenswood assets including prepaid rent and the note receivable have been reclassified to Assets held for sale (Note 6). The current portion included in Other current assets was $ 55 million ( US$40 million ) at December 31, 2015 . |
Schedule of Finite-Lived Intangible Assets | The following amounts related to PPAs are included in Intangible and other assets: 2016 2015 at December 31 Cost Accumulated Amortization Net Book Cost Accumulated Amortization Net Book (millions of Canadian $) Sheerness — — — 585 390 195 Sundance A — — — 225 200 25 — — — 810 590 220 |
NOTES PAYABLE (Tables)
NOTES PAYABLE (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Short-term Debt [Abstract] | |
Schedule of Notes Payable | 2016 2015 (millions of Canadian $, unless otherwise noted) Outstanding at December 31 Weighted Average Interest Rate per Annum at December 31 Outstanding at December 31 Weighted Average Interest Rate per Annum at December 31 Canadian 509 0.9 % 697 0.8 % U.S. (2016 – US$197; 2015 – US$376) 265 0.5 % 521 1.1 % 774 1,218 |
Schedule of Credit Facilities | hese unsecured credit facilities included the following: year ended December 31 (millions of Canadian $) at December 31, 2016 2016 2015 2014 Amount Unused Capacity Borrower Description Matures Cost to maintain $3 billion $3 billion TCPL Committed, syndicated, revolving, extendible credit facility that supports TCPL's Canadian commercial paper program and general corporate purposes December 2021 6 6 6 US$2 billion US$2 billion TCPL Committed, syndicated, revolving, extendible credit facility that supports TCPL's U.S. commercial paper program December 2017 1 — — US$1 billion US$0.9 billion TCPL USA Committed, syndicated, revolving, extendible credit facility that is used for TCPL USA general corporate purposes, guaranteed by TCPL December 2017 1 3 2 US$1 billion US$1 billion Columbia Committed, syndicated, revolving, extendible credit facility that is issued for Columbia's general corporate purposes and provides additional liquidity, guaranteed by TCPL December 2017 — — — US$0.5 billion US$0.5 billion TAIL Committed, syndicated, revolving, extendible credit facility that supports TAIL's commercial paper program, guaranteed by TCPL December 2017 2 2 1 $2.1 billion $0.7 billion TCPL/TCPL USA Supports the issuance of letters of credit and provides additional liquidity Demand — — — |
ACCOUNTS PAYABLE AND OTHER (Tab
ACCOUNTS PAYABLE AND OTHER (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Payables and Accruals [Abstract] | |
Schedule of Accounts Payable and Other | at December 31 2016 2015 (millions of Canadian $) Trade payables 2,443 1,506 Fair value of derivative contracts (Note 24) 607 926 Unredeemed shares of Columbia 317 — Regulatory liabilities (Note 10) 178 44 Other 316 177 3,861 2,653 |
OTHER LONG-TERM LIABILITIES (Ta
OTHER LONG-TERM LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Deferred Costs, Noncurrent [Abstract] | |
Schedule of Other Long-Term Liabilities | at December 31 2016 2015 (millions of Canadian $) Fair value of derivative contracts (Note 24) 330 625 Employee post-retirement benefits (Note 23) 448 380 Asset retirement obligations 108 109 Guarantees (Note 27) 82 26 Other 215 120 1,183 1,260 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of Provision for Income Taxes | year ended December 31 2016 2015 2014 (millions of Canadian $) Current Canada 116 44 103 Foreign 40 92 42 156 136 145 Deferred Canada 101 33 309 Foreign 95 (135 ) 377 196 (102 ) 686 Income Tax Expense 352 34 831 |
Schedule of Geographic Components of Income | year ended December 31 2016 2015 2014 (millions of Canadian $) Canada 219 (624 ) 1,146 Foreign 618 (482 ) 1,678 Income/(Loss) before Income Taxes 837 (1,106 ) 2,824 |
Reconciliation of Income Tax Expense | year ended December 31 2016 2015 2014 (millions of Canadian $) Income/(Loss) before income taxes 837 (1,106 ) 2,824 Federal and provincial statutory tax rate 27 % 26 % 25 % Expected income tax expense/(recovery) 226 (288 ) 706 Income tax differential related to regulated operations 81 159 129 Foreign tax rate differentials (196 ) 14 25 Income from equity investments and non-controlling interests (68 ) (56 ) (38 ) Asset impairment charges 1 242 170 — Non-deductible amounts 46 — — Tax rate and legislative changes — 34 — Other 21 1 9 Actual Income Tax Expense 352 34 831 1 Net of $112 million (2015 - $311 million ) attributed to higher foreign tax rates. |
Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet | at December 31 2016 2015 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 2,063 1,327 Difference in accounting and tax bases of impaired assets and assets held for sale 1,168 916 Regulatory and other deferred amounts 277 231 Unrealized foreign exchange losses on long-term debt 446 589 Financial instruments 34 111 Other 352 136 4,340 3,310 Less: valuation allowance 1 1,336 1,060 3,004 2,250 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 9,015 6,441 Equity investments 905 656 Taxes on future revenue requirement 198 227 Other 156 55 10,274 7,379 Net Deferred Income Tax Liabilities 7,270 5,129 1 In 2016, an increase to the valuation allowance of $ 276 million was recorded as the Company believes that it is more likely than not that the tax benefits related to the unrealized foreign exchange losses on long-term debt, unrealized losses on certain impaired assets, certain operating losses and capital losses will not be realized in the future. The above deferred tax amounts have been classified in the Consolidated balance sheet as follows: at December 31 2016 2015 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 12) 392 15 Deferred Income Tax Liabilities Deferred income tax liabilities 7,662 5,144 Net Deferred Income Tax Liabilities 7,270 5,129 |
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 2016 2015 2014 (millions of Canadian $) Unrecognized tax benefit at beginning of year 17 18 23 Gross increases – tax positions in prior years 3 2 3 Gross decreases – tax positions in prior years — (2 ) (8 ) Gross increases – tax positions in current year 2 1 1 Settlement (1 ) — — Lapse of statutes of limitations (3 ) (2 ) (1 ) Unrecognized Tax Benefit at End of Year 18 17 18 |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of Long-Term Debt | The Company issued Long-term debt over the three years ended December 31, 2016 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED June 2016 Acquisition Bridge Facility 1 June 2018 US 5,213 Floating June 2016 Medium Term Notes July 2023 300 3.69 % 2 June 2016 Medium Term Notes June 2046 700 4.35 % January 2016 Senior Unsecured Notes January 2026 US 850 4.875 % January 2016 Senior Unsecured Notes January 2019 US 400 3.125 % November 2015 Senior Unsecured Notes November 2017 US 1,000 1.625 % October 2015 Medium Term Notes November 2041 400 4.55 % July 2015 Medium Term Notes July 2025 750 3.30 % March 2015 Senior Unsecured Notes March 2045 US 750 4.60 % January 2015 Senior Unsecured Notes January 2018 US 500 1.875 % January 2015 Senior Unsecured Notes January 2018 US 250 Floating February 2014 Senior Unsecured Notes March 2034 US 1,250 4.63 % TRANSCANADA PIPELINE USA LTD. June 2016 Acquisition Bridge Facility 1 June 2018 US 1,700 Floating ANR PIPELINE COMPANY June 2016 Senior Unsecured Notes June 2026 US 240 4.14 % TUSCARORA GAS TRANSMISSION COMPANY April 2016 Term Loan April 2019 US 10 Floating TC PIPELINES, LP September 2015 Unsecured Term Loan October 2018 US 170 Floating March 2015 Senior Unsecured Notes March 2025 US 350 4.375 % GAS TRANSMISSION NORTHWEST LLC June 2015 Unsecured Term Loan June 2019 US 75 Floating 1 These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the monetization of the U.S. Northeast power business will be used to repay these facilities. 2 Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTN were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent. 2016 2015 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Debentures Canadian 2017 to 2020 599 10.7 % 599 10.7 % U.S. (2016 and 2015 – US$400) 2021 536 9.9 % 553 9.9 % Medium Term Notes Canadian 2017 to 2046 5,787 4.6 % 5,175 5.3 % Senior Unsecured Notes U.S. (2016 – US$14,517; 2015 – US$14,641) 2017 to 2045 19,521 5.1 % 20,245 4.8 % Acquisition Bridge Facility (2016 – US$2,006) 2 2018 2,693 1.9 % — — 29,136 26,572 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 324 11.5 % U.S. (2016 and 2015 – US$200) 2023 268 7.9 % 276 7.9 % Medium Term Notes Canadian 2025 to 2030 503 7.4 % 503 7.4 % U.S. (2016 and 2015 – US$33) 2026 43 7.5 % 44 7.5 % 914 1,147 TRANSCANADA PIPELINE USA LTD. Acquisition Bridge Facility (2016 – US$1,695) 2 2018 2,276 1.9 % — — COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2016 – US$2,968) 3 2018 to 2045 3,985 3.7 % — — TC PIPELINES, LP Unsecured Loan Facility U.S. (2016 – US$158; 2015 – US$200) 2021 213 1.9 % 277 1.6 % Unsecured Term Loan U.S. (2016 and 2015 – US$670) 2018 899 1.9 % 927 1.6 % Senior Unsecured Notes U.S. (2016 and 2015 – US$694) 2021 to 2025 932 4.7 % 957 4.7 % 2,044 2,161 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2016 – US$671; 2015 – US$432) 2021 to 2026 901 7.2 % 597 8.9 % GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2016 – US$65; 2015 – US$75) 2019 87 1.6 % 104 1.4 % Senior Unsecured Notes U.S. (2016 and 2015 – US$250) 2020 to 2035 335 5.6 % 346 5.6 % 422 450 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2016 – US$278; 2015 – US$297) 2018 to 2030 373 7.7 % 411 7.8 % 2016 2015 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Secured Notes 4 U.S. (2016 – US$52; 2015 – US$69) 2018 70 6.0 % 96 6.1 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2016 – US$10) 2019 13 1.9 % — — Senior Secured Notes U.S. (2016 – US$12; 2015 – US$16) 2017 16 4.0 % 22 4.0 % 29 22 40,150 31,456 Less: Current portion of Long-term debt 1,838 2,547 38,312 28,909 1 Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates. 2 These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at London Interbank Offered Rate (LIBOR) plus an applicable margin. Proceeds from the U.S. Northeast power business monetization will be used to repay the majority of these facilities. 3 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. 4 Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements. |
Schedule of Repayments of Long-Term Debt | At December 31, 2016, principal repayments on the Long-term debt of the Company for the next five years are approximately as follows: (millions of Canadian $) 2017 2018 2019 2020 2021 Principal repayments on Long-term debt 1,838 8,941 1,742 2,762 2,165 |
Schedule of Retired Long-Term Debt | The Company retired/repaid Long-term debt over the three years ended December 31, 2016 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED November 2016 Acquisition Bridge Facility 1 US 3,200 Floating October 2016 Medium Term Notes 400 4.65 % June 2016 Senior Unsecured Notes US 84 7.69 % June 2016 Senior Unsecured Notes US 500 Floating January 2016 Senior Unsecured Notes US 750 0.75 % August 2015 Debentures 150 11.90 % June 2015 Senior Unsecured Notes US 500 3.40 % March 2015 Senior Unsecured Notes US 500 0.875 % January 2015 Senior Unsecured Notes US 300 4.875 % June 2014 Debentures 125 11.10 % February 2014 Medium Term Notes 300 5.05 % January 2014 Medium Term Notes 450 5.65 % NOVA GAS TRANSMISSION LTD. February 2016 Debentures 225 12.20 % June 2014 Debentures 53 11.20 % GAS TRANSMISSION NORTHWEST LLC June 2015 Senior Unsecured Notes US 75 5.09 % 1 Proceeds from the November 2016 common equity offering were used to partially repay the Acquisition Bridge Facility. |
Schedule of Interest Expense | Interest expense over the three years ended December 31 was as follows: year ended December 31 2016 2015 2014 (millions of Canadian $) Interest on Long-term debt 1,765 1,487 1,317 Interest on Junior subordinated notes (Note 18) 180 116 70 Interest on short-term debt 18 16 15 Capitalized interest (176 ) (280 ) (259 ) Amortization and other financial charges 1 211 31 55 1,998 1,370 1,198 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, 2016 | |
Junior Subordinated Notes [Abstract] | |
Schedule of Junior Subordinated Notes | 2016 2015 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate Outstanding at December 31 Effective Interest Rate (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED U.S. (2016 and 2015 – US$1,000) 1 2067 1,342 6.4 % 1,382 6.4 % U.S. (2016 and 2015 – US$742) 1, 2 2075 996 5.5 % 1,027 5.3 % U.S. (2016 – US$1,186) 1, 2 2076 1,593 6.2 % — — 3,931 2,409 1 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 2 The Junior subordinated notes were issued to TransCanada Trust (the 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 because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. |
NON-CONTROLLING INTERESTS (Tabl
NON-CONTROLLING INTERESTS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,596 1,590 Non-controlling interest in Portland Natural Gas Transmission System 130 127 1,726 1,717 The Company's Non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2016 2015 2014 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 215 (13 ) 136 Non-controlling interest in Portland Natural Gas Transmission System 20 19 15 Non-controlling interest in Columbia Pipeline Partners LP 17 — — Preferred shares of TCPL — — 2 252 6 153 |
COMMON SHARES (Tables)
COMMON SHARES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2014 707,441 12,149 Exercise of options 1,221 53 Outstanding at December 31, 2014 708,662 12,202 Exercise of options 737 30 Repurchase of shares (6,785 ) (130 ) Outstanding at December 31, 2015 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 1 Net of underwriting commissions and deferred income taxes. |
Schedule of Weighted Average Shares | Net income/(loss) per common share is calculated by dividing Net income/(loss) attributable to common shares by the weighted average number of common shares outstanding. The higher weighted average number of shares for the diluted earnings per share calculation is due to options exercisable under TransCanada's Stock Option Plan. Weighted Average Common Shares Outstanding (millions) 2016 2015 2014 Basic 759 709 708 Diluted 760 709 710 |
Schedule of Stock Options Activity | Number of (thousands) Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (years) Options outstanding at January 1, 2016 9,834 $46.63 Options granted 2,479 $48.44 Options exercised (1,683 ) $38.92 Options Outstanding at December 31, 2016 10,630 $48.28 4.2 Options Exercisable at December 31, 2016 5,957 $46.09 3.1 |
Schedule of Options Valuation Assumptions | The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions: year ended December 31 2016 2015 2014 Weighted average fair value $5.67 $6.45 $5.54 Expected life (years) 5.8 5.8 6.0 Interest rate 0.7 % 1.1 % 1.8 % Volatility 1 21 % 18 % 17 % Dividend yield 4.9 % 3.7 % 3.8 % Forfeiture rate 5 % 5 % 5 % 1 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. |
Schedule of Additional Option Information | The following table summarizes additional stock option information: year ended December 31 2016 2015 2014 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 31 10 21 Fair value of options that have vested 126 91 95 Total options vested 2.1 million 2.0 million 1.7 million |
PREFERRED SHARES (Tables)
PREFERRED SHARES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 1 Redemption Price Per Share 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4,5 2016 2015 (thousands) (millions of Canadian $) 6 (millions of Canadian $) 6 Cumulative First Preferred Shares Series 1 9,498 3.266 % $0.8165 $25.00 December 31, 2019 Series 2 233 233 Series 2 12,502 Floating 7 Floating $25.00 December 31, 2019 Series 1 306 306 Series 3 8,533 2.152 % $0.538 $25.00 June 30, 2020 Series 4 209 209 Series 4 5,467 Floating 7 Floating $25.00 June 30, 2020 Series 3 134 134 Series 5 12,714 2.263 % $0.56575 $25.00 January 30, 2021 Series 6 310 342 Series 6 1,286 Floating 8 Floating $25.00 January 30, 2021 Series 5 32 — Series 7 24,000 4.00 % $1.00 $25.00 April 30, 2019 Series 8 589 589 Series 9 18,000 4.25 % $1.0625 $25.00 October 30, 2019 Series 10 442 442 Series 11 10,000 3.80 % $0.95 $25.00 November 30, 2020 Series 12 244 244 Series 13 20,000 5.50 % $1.375 $25.00 May 31, 2021 Series 14 493 — Series 15 40,000 4.90 % $1.3292 $25.00 May 31, 2022 Series 16 988 — 3,980 2,499 1 The holder is 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. 2 TransCanada may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the 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. 3 The holder will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter. 4 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. 5 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, equal to 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 per cent (Series 15). 6 Net of underwriting commissions and deferred income taxes. 7 The floating quarterly dividend rate for the Series 2 preferred shares is 2.429 per cent and for the Series 4 preferred shares is 1.789 per cent for the period starting December 30, 2016 to, but excluding, March 31, 2017. These rates will reset each quarter going forward. 8 The floating quarterly dividend rate for the Series 6 preferred shares is 2.073 per cent for the period starting October 30, 2016 to, but excluding, January 31, 2017. These rates will reset each quarter going forward. |
OTHER COMPREHENSIVE (LOSS)_IN58
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Components of Other Comprehensive Income/(Loss) | Components of Other comprehensive (loss)/income, including the portion attributable to non-controlling interests and related tax effects, are as follows: year ended December 31, 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 to net income of actuarial loss on pension and other post-retirement benefit plans 22 (6 ) 16 Other comprehensive loss on equity investments (117 ) 30 (87 ) Other Comprehensive Loss (29 ) (3 ) (32 ) year ended December 31, 2015 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 798 15 813 Change in fair value of net investment hedges (505 ) 133 (372 ) Change in fair value of cash flow hedges (92 ) 35 (57 ) Reclassification to net income of gains and losses on cash flow hedges 144 (56 ) 88 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 74 (23 ) 51 Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans 41 (9 ) 32 Other comprehensive income on equity investments 62 (15 ) 47 Other Comprehensive Income 522 80 602 year ended December 31, 2014 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains on net investment in foreign operations 462 55 517 Change in fair value of net investment hedges (373 ) 97 (276 ) Change in fair value of cash flow hedges (118 ) 49 (69 ) Reclassification to net income of gains and losses on cash flow hedges (95 ) 40 (55 ) Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (146 ) 44 (102 ) Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans 25 (7 ) 18 Other comprehensive loss on equity investments (272 ) 68 (204 ) Other Comprehensive Loss (517 ) 346 (171 ) |
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, 2014 (629 ) (4 ) (197 ) (104 ) (934 ) Other comprehensive income/(loss) before reclassifications 2 111 (69 ) (102 ) (206 ) (266 ) Amounts reclassified from accumulated other comprehensive loss — (55 ) 18 2 (35 ) Net current period other comprehensive income/(loss) 111 (124 ) (84 ) (204 ) (301 ) AOCI balance at December 31, 2014 (518 ) (128 ) (281 ) (308 ) (1,235 ) Other comprehensive income/(loss) before reclassifications 2 135 (57 ) 51 33 162 Amounts reclassified from accumulated other comprehensive loss — 88 32 14 134 Net current period other comprehensive income 135 31 83 47 296 AOCI balance at December 31, 2015 (383 ) (97 ) (198 ) (261 ) (939 ) Other comprehensive income/(loss) before reclassifications 2 7 27 (26 ) (101 ) (93 ) Amounts reclassified from accumulated other comprehensive loss 3 — 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 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 Other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $14 million ( 2015 – $306 million gains; 2014 – $130 million gains) and gains of $3 million ( 2015 and 2014 - nil), respectively in 2016 . 3 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months are estimated to be $5 million ( $3 million , net of tax) at December 31, 2016 . These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. |
Schedule of Reclassifications out of Accumulated Other Comprehensive Income | Details about reclassifications out of AOCI into the Consolidated statement of income are as follows: Amounts Reclassified From 1 Affected Line Item year ended December 31 2016 2015 2014 (millions of Canadian $) Cash flow hedges Commodities (57 ) (128 ) 111 Revenues (Energy) Interest (14 ) (16 ) (16 ) Interest expense (71 ) (144 ) 95 Total before tax 29 56 (40 ) Income tax expense/(recovery) (42 ) (88 ) 55 Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial loss and past service cost (22 ) (41 ) (25 ) Plant operating costs and other 2 6 9 7 Income tax expense (16 ) (32 ) (18 ) Net of tax Equity investments Equity income (19 ) (19 ) (2 ) Income from equity investments 5 5 — Income tax expense (14 ) (14 ) (2 ) Net of tax 1 All amounts in parentheses indicate expenses to the Consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost. Refer to Note 23, Employee post-retirement benefits for further information. |
EMPLOYEE POST-RETIREMENT BENE59
EMPLOYEE POST-RETIREMENT BENEFITS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Schedule of Payments for Defined Benefit Plans | Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2016 2015 2014 (millions of Canadian $) DB Plans 111 96 73 Other post-retirement benefit plans 8 6 6 Savings and DC Plans 52 41 37 171 143 116 |
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 $) 2016 2015 2016 2015 Change in Benefit Obligation 1 Benefit obligation – beginning of year 2,780 2,658 225 216 Service cost 107 108 3 3 Interest cost 127 115 13 10 Employee contributions 4 4 2 — Benefits paid (204 ) (129 ) (16 ) (7 ) Actuarial loss/(gain) 111 (57 ) (8 ) (11 ) Acquisition of Columbia 527 — 151 — Settlement loss 2 — — — Foreign exchange rate changes 2 81 2 14 Benefit obligation – end of year 3,456 2,780 372 225 Change in Plan Assets Plan assets at fair value – beginning of year 2,591 2,398 45 39 Actual return on plan assets 227 160 14 (1 ) Employer contributions 2 111 96 8 6 Employee contributions 4 4 2 — Benefits paid (204 ) (129 ) (16 ) (7 ) Acquisition of Columbia 475 — 294 — Foreign exchange rate changes 4 62 7 8 Plan assets at fair value – end of year 3,208 2,591 354 45 Funded Status – Plan Deficit (248 ) (189 ) (18 ) (180 ) 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 $233 million in letters of credit provided to the Canadian DB Plans for funding purposes ( 2015 – $214 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 $) 2016 2015 2016 2015 Intangible and other assets (Note 12) — — 189 18 Accounts payable and other — — (7 ) (7 ) Other long-term liabilities (Note 15) (248 ) (189 ) (200 ) (191 ) (248 ) (189 ) (18 ) (180 ) |
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 $) 2016 2015 2016 2015 Projected benefit obligation 1 (3,456 ) (2,780 ) (207 ) (198 ) Plan assets at fair value 3,208 2,591 — — Funded Status – Plan Deficit (248 ) (189 ) (207 ) (198 ) 1 The projected benefit obligation for the pension benefit plan differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels. |
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for All DB Plans | The funded status based on the accumulated benefit obligation for all DB Plans is as follows: at December 31 2016 2015 (millions of Canadian $) Accumulated benefit obligation (3,202 ) (2,600 ) Plan assets at fair value 3,208 2,591 Funded Status – Plan Surplus/(Deficit) 6 (9 ) |
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 2016 2015 (millions of Canadian $) Accumulated benefit obligation (990 ) (807 ) Plan assets at fair value 868 680 Funded Status – Plan Deficit (122 ) (127 ) |
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 2016 2015 2016 Debt securities 31 % 34 % 25% to 40% Equity securities 63 % 66 % 45% to 75% Alternatives 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 $) 2016 2015 2016 2015 Debt securities 9 2 0.2 % 0.1 % Equity securities 4 4 0.1 % 0.1 % |
Schedule of Plan Assets for DB Plans and Other Post-Retirement Benefits Measured at Fair Value | The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. For further information on the fair value hierarchy, refer to Note 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 $) 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 Asset Category Cash and Cash Equivalents 22 44 12 2 — — 34 46 1 2 Equity Securities: Canadian 388 317 143 147 — — 531 464 15 17 U.S. 504 589 476 40 — — 980 629 27 24 International 39 38 327 300 — — 366 338 10 13 Global — — 235 154 — — 235 154 7 6 Emerging 7 7 137 143 — — 144 150 4 6 Fixed Income Securities: Canadian Bonds: Federal — — 192 206 — — 192 206 5 8 Provincial — — 179 202 — — 179 202 5 8 Municipal — — 8 7 — — 8 7 — — Corporate — — 126 113 — — 126 113 4 4 U.S. Bonds: Federal — — 82 — — — 82 — 2 — State — — 41 50 — — 41 50 1 2 Municipal — — 39 — — — 39 — 1 — Corporate — — 188 57 — — 188 57 5 2 International: Government — — 6 — — — 6 — — — Corporate — — 21 25 — — 21 25 1 1 Mortgage backed — — 62 58 — — 62 58 2 2 Other Investments: Real Estate — — — — 133 — 133 — 4 — Infrastructure — — — — 58 — 58 — 2 — Private equity funds — — — — 8 14 8 14 — — Funds held on deposit 129 123 — — — — 129 123 4 5 1,089 1,118 2,274 1,504 199 14 3,562 2,636 100 100 |
Schedule of the Net Change in the Level III Fair Value Category | The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Private Equity Funds Balance at December 31, 2014 13 Purchases and sales (1 ) Realized and unrealized gains 2 Balance at December 31, 2015 14 Purchases and sales 183 Realized and unrealized gains 2 Balance at December 31, 2016 199 |
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 2017 178 19 2018 183 19 2019 189 20 2020 196 20 2021 200 20 2022 to 2026 1,067 97 |
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 2016 2015 2016 2015 Discount rate 4.00 % 4.20 % 4.15 % 4.40 % Rate of compensation increase 1.20 % 0.50 % — — |
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 2016 2015 2014 2016 2015 2014 Discount rate 4.20 % 4.15 % 4.95 % 4.30 % 4.20 % 5.00 % Expected long-term rate of return on plan assets 6.70 % 6.95 % 6.90 % 5.95 % 4.60 % 4.60 % Rate of compensation increase 0.80 % 3.15 % 3.15 % — — — |
Schedule of Effects of a 1% Change in Assumed Health Care Cost Trend Rates | A one per cent change in assumed health care cost trend rates would have the following effects: (millions of Canadian $) Increase Decrease Effect on total of service and interest cost components 1 (1 ) Effect on post-retirement benefit obligation 15 (13 ) |
Schedule of Net Benefit Costs | The Company's net benefit cost recognized is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2016 2015 2014 2016 2015 2014 Service cost 107 108 85 3 3 2 Interest cost 127 115 113 13 10 10 Expected return on plan assets (175 ) (155 ) (139 ) (11 ) (2 ) (2 ) Amortization of actuarial loss 20 35 21 2 3 2 Amortization of past service cost — 2 2 — 1 — Amortization of regulatory asset 27 23 18 1 1 1 Amortization of transitional obligation related to regulated business — — — 2 2 2 Net Benefit Cost Recognized 106 128 100 10 18 15 |
Schedule of the Pre-Tax Amounts Recognized in AOCI | Pre-tax amounts recognized in AOCI were as follows: 2016 2015 2014 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 268 23 247 28 348 39 Prior service cost — — — — 2 1 268 23 247 28 350 40 |
Schedule of the Pre-Tax Amounts Recognized in OCI | Pre-tax amounts recognized in OCI were as follows: 2016 2015 2014 at December 31 Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits Pension Benefits Other Post- Retirement Benefits (millions of Canadian $) Amortization of net loss from AOCI to OCI (20 ) (2 ) (34 ) (4 ) (21 ) (2 ) Amortization of prior service costs from AOCI to OCI — — (2 ) (1 ) (2 ) — Funded status adjustment 43 (5 ) (67 ) (7 ) 137 9 23 (7 ) (103 ) (12 ) 114 7 |
RISK MANAGEMENT AND FINANCIAL60
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative financial instruments | |
Schedule of Financial Instruments | s The balance sheet classification of the fair value of the derivative instruments as at December 31, 2016 is as follows: at December 31, 2016 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 6 — — 351 357 Foreign exchange — — 6 10 16 Interest rate 1 1 — 1 3 7 1 6 362 376 Intangible and other assets (Note 12) Commodities 2 4 — — 118 122 Foreign exchange — — 10 — 10 Interest rate 1 — — — 1 5 — 10 118 133 Total Derivative Assets 12 1 16 480 509 Accounts payable and other (Note 14) Commodities 2 — — — (330 ) (330 ) Foreign exchange — — (237 ) (38 ) (275 ) Interest rate (1 ) (1 ) — — (2 ) (1 ) (1 ) (237 ) (368 ) (607 ) Other long-term liabilities (Note 15) Commodities 2 — — — (118 ) (118 ) Foreign exchange — — (211 ) — (211 ) Interest rate — (1 ) — — (1 ) — (1 ) (211 ) (118 ) (330 ) Total Derivative Liabilities (1 ) (2 ) (448 ) (486 ) (937 ) 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 the derivative instruments as at December 31, 2015 is as follows: at December 31, 2015 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 46 — — 326 372 Foreign exchange — — 65 2 67 Interest rate — 1 — 2 3 46 1 65 330 442 Intangible and other assets (Note 12) Commodities 2 11 — — 126 137 Foreign exchange — — 29 — 29 Interest rate — 2 — — 2 11 2 29 126 168 Total Derivative Assets 57 3 94 456 610 Accounts payable and other (Note 14) Commodities 2 (112 ) — — (443 ) (555 ) Foreign exchange — — (313 ) (54 ) (367 ) Interest rate (1 ) (1 ) — (2 ) (4 ) (113 ) (1 ) (313 ) (499 ) (926 ) Other long-term liabilities (Note 15) Commodities 2 (31 ) — — (131 ) (162 ) Foreign exchange — — (461 ) — (461 ) Interest rate (1 ) (1 ) — — (2 ) (32 ) (1 ) (461 ) (131 ) (625 ) Total Derivative Liabilities (145 ) (2 ) (774 ) (630 ) (1,551 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power and natural gas. The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy: 2016 2015 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Notes receivable 1 165 211 214 265 Current and Long-term debt 2,3 (Note 17) (40,150 ) (45,047 ) (31,456 ) (34,309 ) Junior subordinated notes (Note 18) (3,931 ) (3,825 ) (2,409 ) (2,011 ) (43,916 ) (48,661 ) (33,651 ) (36,055 ) 1 Notes receivable are included in Assets held for sale on the Consolidated balance sheet at December 31, 2016 and in Other current assets and Intangible and other assets on the Consolidated balance sheet at December 31, 2015. The fair value is calculated based on the original contract terms. 2 Long-term debt is recorded at amortized cost, except for US$850 million ( 2015 – US$850 million ) that is attributed to hedged risk and recorded at fair value. 3 Consolidated net income in 2016 included unrealized gains of $2 million ( 2015 – gains of $2 million ) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of Long-term debt at December 31, 2016 ( 2015 – US$850 million ). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. Available for Sale Assets Summary The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets: 2016 2015 LMCI Restricted Investments 2 Other Restricted Investments 3 LMCI Restricted Investments 2 Other Restricted Investments 3 (millions of Canadian $) Fair values 1 Fixed income securities (maturing within 1 year) — 19 — 26 Fixed income securities (maturing within 1-5 years) — 117 — 64 Fixed income securities (maturing within 5-10 years) 9 — — — Fixed income securities (maturing after 10 years) 513 — 261 — Total fair value at December 31 522 136 261 90 Net unrealized losses for the year ended December 31 (28 ) (1 ) — — 1 Available for sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Consolidated balance sheet. 2 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. 3 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. Unrealized gains and losses on other restricted investments are included in OCI. |
Realized Gain (Loss) on Investments | |
Unrealized Gain (Loss) on Investments | |
Summary of Derivative Instruments | y The maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows: at December 31, 2016 Power Natural Gas Liquids Foreign Exchange Interest Purchases 1 86,887 182 6 — — Sales 1 58,561 147 6 — — Millions of dollars — — — US 2,394 US 1,550 Maturity dates 2017-2021 2017-2020 2017 2017 2017-2019 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. at December 31, 2015 Power Natural Gas Foreign Exchange Interest Purchases 1 70,331 133 — — Sales 1 54,382 70 — — Millions of dollars — — US 1,476 US 1,100 Maturity dates 2016–2020 2016–2020 2016 2016–2019 1 Volumes for power and natural gas derivatives are in GWh and Bcf, respectively . |
Summary of Unrealized and Realized Gains/(Losses) of Derivative Instruments | The following summary does not include hedges of the net investment in foreign operations. year ended December 31 2016 2015 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 2 123 (37 ) Foreign exchange 25 (21 ) Amount of realized (losses)/gains in the year Commodities (204 ) (151 ) Foreign exchange 62 (112 ) Derivative instruments in hedging relationships Amount of realized (losses)/gains in the year Commodities (167 ) (179 ) Foreign exchange (101 ) — Interest rate 4 8 1 Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively. 2 Following the March 17, 2016 announcement of the Company's intention to sell the U.S. Northeast power assets, losses of $49 million and gains of $7 million (2015 - nil ) were recorded in net income in 2016 relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale. |
Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships | s 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 2016 2015 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI (effective portion) 1 Commodities 2 39 (92 ) Interest rate 3 5 — 44 (92 ) Reclassification of gains on derivative instruments from AOCI to Net income (effective portion) 1 Commodities 2 57 128 Interest rate 3 14 16 71 144 Losses on derivative instruments recognized in Net income (ineffective portion) Commodities 2 — — 1 No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI. 2 Reported within Revenues on the Consolidated statement of income. 3 Reported within Interest expense on the Consolidated statement of incom |
Schedule of Offsetting Assets | . The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at December 31, 2016 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 479 (362 ) 117 Foreign exchange 26 (26 ) — Interest rate 4 (1 ) 3 509 (389 ) 120 Derivative – Liability Commodities (448 ) 362 (86 ) Foreign exchange (486 ) 26 (460 ) Interest rate (3 ) 1 (2 ) (937 ) 389 (548 ) 1 Amounts available for offset do not include cash collateral pledged or received. 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, 2015 : at December 31, 2015 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 509 (418 ) 91 Foreign exchange 96 (93 ) 3 Interest rate 5 (1 ) 4 610 (512 ) 98 Derivative – Liability Commodities (717 ) 418 (299 ) Foreign exchange (828 ) 93 (735 ) Interest rate (6 ) 1 (5 ) (1,551 ) 512 (1,039 ) 1 Amounts available for offset do not include cash collateral pledged or receive |
Schedule of Offsetting Liabilities | . The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at December 31, 2016 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 479 (362 ) 117 Foreign exchange 26 (26 ) — Interest rate 4 (1 ) 3 509 (389 ) 120 Derivative – Liability Commodities (448 ) 362 (86 ) Foreign exchange (486 ) 26 (460 ) Interest rate (3 ) 1 (2 ) (937 ) 389 (548 ) 1 Amounts available for offset do not include cash collateral pledged or received. 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, 2015 : at December 31, 2015 Gross Derivative Instruments Presented on the Balance Sheet Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative – Asset Commodities 509 (418 ) 91 Foreign exchange 96 (93 ) 3 Interest rate 5 (1 ) 4 610 (512 ) 98 Derivative – Liability Commodities (717 ) 418 (299 ) Foreign exchange (828 ) 93 (735 ) Interest rate (6 ) 1 (5 ) (1,551 ) 512 (1,039 ) 1 Amounts available for offset do not include cash collateral pledged or receive |
Schedule of Fair Value of Assets and Liabilities Measured on a Recurring Basis | Levels How fair value has been determined Level I Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. Level II Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances. Level III Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category mainly 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 2016 , are categorized as follows: at December 31, 2016 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 134 326 19 479 Foreign exchange — 26 — 26 Interest rate — 4 — 4 Derivative Instrument Liabilities: Commodities (102 ) (343 ) (3 ) (448 ) Foreign exchange — (486 ) — (486 ) Interest rate — (3 ) — (3 ) 32 (476 ) 16 (428 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016 . The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2015 , are categorized as follows: at December 31, 2015 Quoted Prices in Active Markets 1 Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets: Commodities 34 462 13 509 Foreign exchange — 96 — 96 Interest rate — 5 — 5 Derivative Instrument Liabilities: Commodities (102 ) (611 ) (4 ) (717 ) Foreign exchange — (828 ) — (828 ) Interest rate — (6 ) — (6 ) (68 ) (882 ) 9 (941 ) 1 There were no transfers from Level I to Level II or from Level II to Level III for the |
Schedule of Net Change in the Level III Fair Value Category | . The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy: (millions of Canadian $, pre-tax) 2016 2015 Balance at beginning of year 9 4 Total gains included in Net income 13 3 Sales (3 ) (2 ) Settlements (2 ) (1 ) Transfers out of Level III (1 ) 5 Balance at end of year 1 16 9 1 Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2016 of $7 million ( 2015 – $7 million |
Designated as a net investment hedge | |
Derivative financial instruments | |
Summary of Derivative Instruments | U.S. Dollar-Denominated Debt Designated as a Net Investment Hedge The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2016 2015 (millions of Canadian $, unless otherwise noted) Notional amount 26,600 (US 19,800) 23,100 (US 16,700) Fair value 29,400 (US 21,900) 23,800 (US 17,200) Derivatives Designated as a Net Investment Hedge The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows: 2016 2015 at December 31 Fair 1 Notional or Fair 1 Notional or (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2017 to 2019) 2 (425 ) US 2,350 (730 ) US 3,150 U.S. dollar foreign exchange forward contracts (maturing 2017) (7 ) US 150 50 US 1,800 (432 ) US 2,500 (680 ) US 4,950 1 Fair values equal carrying values. 2 In 2016 , net realized gains of $6 million ( 2015 – gains of $8 million ) related to the interest component of cross-currency swap settlements are included in Interest expense. |
CHANGES IN OPERATING WORKING 61
CHANGES IN OPERATING WORKING CAPITAL (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
CHANGES IN OPERATING WORKING CAPITAL | |
Schedule of changes in operating working capital | year ended December 31 2016 2015 2014 (millions of Canadian $) Increase in Accounts receivable (482 ) (65 ) (189 ) Increase in Inventories (87 ) (3 ) (28 ) Increase in Assets held for sale (13 ) — — Decrease/(increase) in Other current assets 328 (272 ) (385 ) Increase/(decrease) in Accounts payable and other 424 (97 ) 377 Increase in Accrued interest 62 91 36 Increase in Liabilities related to assets held for sale 16 — — Decrease/(increase) in Operating Working Capital 248 (346 ) (189 ) |
COMMITMENTS, CONTINGENCIES AN62
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 $) 2017 129 5 124 2018 122 4 118 2019 106 2 104 2020 69 2 67 2021 69 1 68 2022 and thereafter 621 3 618 1,116 17 1,099 |
Schedule of Guarantees | Information regarding the Company’s guarantees is as follows: 2016 2015 year ended December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas Ranging to 2040 805 53 — — Bruce Power Ranging to 2018 88 1 88 2 Other jointly owned entities Ranging to 2040 87 28 139 24 980 82 227 26 1 TransCanada's share of the potential estimated current or contingent exposure. |
CORPORATE RESTRUCTURING COSTS (
CORPORATE RESTRUCTURING COSTS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Restructuring and Related Activities [Abstract] | |
Restructuring and Related Costs [Table Text Block] | Changes in the restructuring liability were as follows: (millions of Canadian $) Employee Severance Lease Commitments Total Restructuring liability as at December 31, 2015 60 27 87 Restructuring charges — 44 44 Cash payments (24 ) (8 ) (32 ) Restructuring Liability as at December 31, 2016 36 63 99 |
VARIABLE INTEREST ENTITIES (Tab
VARIABLE INTEREST ENTITIES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Variable Interest Entity, Primary Beneficiary | |
Variable Interest Entity [Line Items] | |
Schedule of Variable Interest Entities | The assets and liabilities of the consolidated VIEs whose assets cannot be used for purposes other than the settlement of the VIE’s obligations are as follows: at December 31 (millions of Canadian $) 2016 2015 ASSETS Current Assets Cash and cash equivalents 77 54 Accounts receivable 71 55 Inventories 25 25 Other 10 6 183 140 Plant, Property and Equipment 3,685 3,704 Equity Investments 606 664 Goodwill 525 541 Intangible and Other Assets 1 — 5,000 5,049 LIABILITIES Current Liabilities Accounts payable and other 80 74 Accrued interest 21 21 Current portion of long-term debt 76 45 177 140 Regulatory Liabilities 34 33 Other Long-Term Liabilities 4 4 Deferred Income Tax Liabilities 7 — Long-Term Debt 2,827 2,998 3,049 3,175 |
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 $) 2016 2015 Balance sheet Equity investments 4,964 5,410 Off-balance sheet Potential exposure to guarantees 163 227 Maximum exposure to loss 5,127 5,637 |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | The following amounts are included in Due to affiliates: Insert Title Here 2016 2015 (unaudited - millions of Canadian $) Maturity Date Outstanding September 30 Effective Interest Rate Outstanding December 31 Effective Interest Rate Credit Facility 1 December 2016 — — 311 3.5 % Credit Facility 2 Demand 2,358 2.7 % — — 2,358 311 1 TransCanada has an unsecured $3.5 billion credit facility with a subsidiary of TCPL. Interest on this facility is charged at the prime rate per annum. 2 TransCanada has an unsecured $3.0 billion credit facility with TCPL. Interest on this facility is charged at prime rate per annum. This credit facility includes $1.8 billion due to TransCanada related to the acquisition of Columbia. Refer to Note 5, Acquisition of Columbia for more information. The following amounts are included in Due from affiliates: 2016 2015 (unaudited - millions of Canadian $) Maturity Date Outstanding September 30 Effective Interest Rate Outstanding December 31 Effective Interest Rate Discount Notes 1 November 2016 2,392 0.9 % 2,376 0.9 % Credit Facility 2 Demand — — 100 2.7 % 2,392 2,476 1 Issued to TransCanada. Interest on the discount notes is equivalent to current commercial paper rates. 2 Issued to TransCanada. This facility is repayable on demand and bears interest at the prime rate per annum. |
DESCRIPTION OF TRANSCANADA'S 66
DESCRIPTION OF TRANSCANADA'S BUSINESS (Details) | 12 Months Ended |
Dec. 31, 2016plantsegmentcore_businessmikmBcf | |
Segment Reporting Information [Line Items] | |
Number of core businesses | core_business | 3 |
Number of business segments in which the entity operates | segment | 6 |
Canadian Natural Gas Pipelines | |
Segment Reporting Information [Line Items] | |
Investments of regulated natural gas pipelines (in kilometers) | km | 40,111 |
Investments of regulated natural gas pipelines (in miles) | mi | 24,923 |
U.S. Natural Gas Pipelines | |
Segment Reporting Information [Line Items] | |
Investments of regulated natural gas pipelines (in kilometers) | km | 49,776 |
Investments of regulated natural gas pipelines (in miles) | mi | 30,933 |
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 | 1,617 |
Investments of regulated natural gas pipelines (in miles) | mi | 1,005 |
Liquids Pipelines | |
Segment Reporting Information [Line Items] | |
Wholly owned and operated crude oil pipeline systems (in kilometers) | km | 4,324 |
Wholly owned and operated crude oil pipeline systems (in miles) | mi | 2,687 |
Energy | |
Segment Reporting Information [Line Items] | |
Number of electrical power generation plants | plant | 18 |
Non-regulated natural gas storage facilities (in billion cubic feet) | Bcf | 118 |
Held-for-sale | Energy | |
Segment Reporting Information [Line Items] | |
Number of electrical power generation plants | plant | 5 |
Millennium Pipeline | U.S. Natural Gas Pipelines | |
Segment Reporting Information [Line Items] | |
Jointly owned utility plant, proportionate ownership share, percent | 47.50% |
Pennant Midstream | U.S. Natural Gas Pipelines | |
Segment Reporting Information [Line Items] | |
Jointly owned utility plant, proportionate ownership share, percent | 47.00% |
TransGas Pipeline Columbia | Mexico Natural Gas Pipelines | |
Segment Reporting Information [Line Items] | |
Jointly owned utility plant, proportionate ownership share, percent | 46.50% |
ACCOUNTING POLICIES (Details)
ACCOUNTING POLICIES (Details) | 12 Months Ended |
Dec. 31, 2016level | |
Annual review for goodwill impairment | |
Number of levels below operating segments level considered for measuring reporting unit level | 1 |
Employee Post-Retirement Benefits | |
Moving average period of basis used to determine expected return on plan assets (in years) | 5 years |
Corporate | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 3.00% |
Corporate | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 20.00% |
Natural Gas Pipelines | Pipeline | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 1.00% |
Natural Gas Pipelines | Pipeline | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 6.00% |
Midstream | Pipeline | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 167.00% |
Midstream | Pipeline | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 250.00% |
Liquids Pipelines | Pipeline | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 2.00% |
Liquids Pipelines | Pipeline | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 2.50% |
Energy | Power generation and natural gas storage plant, equipment and structures | Minimum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 2.00% |
Energy | Power generation and natural gas storage plant, equipment and structures | Maximum | |
Plant, property and equipment | |
Annual depreciation rate on straight-line basis (in percent) | 20.00% |
SEGMENTED INFORMATION (Details)
SEGMENTED INFORMATION (Details) CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016CADsegment | Dec. 31, 2015CAD | Dec. 31, 2014CAD | |
Segment Reporting Information [Line Items] | |||
Number of operating segments | segment | 6 | ||
Segmented information | |||
Revenues | CAD 12,505 | CAD 11,300 | CAD 10,185 |
Income from Equity Investments (Note 9) | 514 | 440 | 522 |
Plant operating costs and other | (3,819) | (3,250) | (2,973) |
Commodity purchases resold | (2,172) | (2,237) | (1,836) |
Property taxes | (555) | (517) | (473) |
Depreciation and amortization | (1,939) | (1,765) | (1,611) |
Goodwill and other asset impairment charges | (1,388) | (3,745) | 0 |
Gain on assets held for sale/sold | (833) | (125) | 117 |
Segmented earnings/(losses) | 2,313 | 101 | 3,931 |
Interest expense | (1,998) | (1,370) | (1,198) |
Allowance for funds used during construction | 419 | 295 | 136 |
Interest income and other | 103 | (132) | (45) |
Income/(Loss) before Income Taxes | 837 | (1,106) | 2,824 |
Income tax expense | (352) | (34) | (831) |
Net Income/(Loss) | 485 | (1,140) | 1,993 |
Net income attributable to non-controlling interests | (252) | (6) | (153) |
Net Income/(Loss) Attributable to Controlling Interests | 233 | (1,146) | 1,840 |
Preferred share dividends | (109) | (94) | (97) |
Net Income/(Loss) Attributable to Common Shares | 124 | (1,240) | 1,743 |
Capital spending | |||
Capital expenditures | 5,007 | 3,918 | 3,489 |
Capital projects in development | 295 | 511 | 848 |
Payments to Acquire Productive Assets | 5,302 | 4,429 | 4,337 |
Assets | 88,051 | 64,398 | |
GEOGRAPHIC INFORMATION | |||
Revenues | 12,505 | 11,300 | 10,185 |
Plant, Property and Equipment (Note 8) | 54,475 | 44,817 | |
Liquids Pipelines | 1,755 | 1,879 | 1,547 |
Energy | 4,164 | 4,038 | 3,725 |
Canada | |||
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment (Note 8) | 20,531 | 19,287 | |
Canada – domestic | |||
Segmented information | |||
Revenues | 3,655 | 3,877 | 3,956 |
GEOGRAPHIC INFORMATION | |||
Revenues | 3,655 | 3,877 | 3,956 |
Canada – export | |||
Segmented information | |||
Revenues | 1,177 | 1,292 | 1,314 |
GEOGRAPHIC INFORMATION | |||
Revenues | 1,177 | 1,292 | 1,314 |
United States | |||
Segmented information | |||
Revenues | 7,295 | 5,872 | 4,718 |
GEOGRAPHIC INFORMATION | |||
Revenues | 7,295 | 5,872 | 4,718 |
Plant, Property and Equipment (Note 8) | 29,414 | 21,899 | |
Mexico | |||
Segmented information | |||
Revenues | 378 | 259 | 197 |
GEOGRAPHIC INFORMATION | |||
Revenues | 378 | 259 | 197 |
Plant, Property and Equipment (Note 8) | 4,530 | 3,631 | |
Corporate | |||
Segmented information | |||
Plant operating costs and other | (208) | (207) | (64) |
Depreciation and amortization | (48) | (31) | (23) |
Goodwill and other asset impairment charges | 0 | ||
Gain on assets held for sale/sold | 0 | ||
Segmented earnings/(losses) | (256) | (238) | (87) |
Capital spending | |||
Capital expenditures | 33 | 64 | 46 |
Payments to Acquire Productive Assets | 33 | 64 | 46 |
Assets | 2,735 | 1,706 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment (Note 8) | 280 | 185 | |
Canadian Natural Gas Pipelines | |||
Segmented information | |||
Natural Gas Pipelines | 3,682 | 3,680 | 3,557 |
Canadian Natural Gas Pipelines | Operating segments | |||
Segmented information | |||
Natural Gas Pipelines | 3,682 | 3,680 | 3,557 |
Income from Equity Investments (Note 9) | 12 | 12 | 12 |
Plant operating costs and other | (1,181) | (1,162) | (1,028) |
Property taxes | (267) | (272) | (266) |
Depreciation and amortization | (873) | (845) | (821) |
Goodwill and other asset impairment charges | 0 | 0 | |
Gain on assets held for sale/sold | 0 | 0 | 0 |
Segmented earnings/(losses) | 1,373 | 1,413 | 1,454 |
Capital spending | |||
Capital expenditures | 1,372 | 1,366 | 814 |
Capital projects in development | 153 | 230 | 327 |
Payments to Acquire Productive Assets | 1,525 | 1,596 | 1,141 |
Assets | 15,816 | 15,038 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment (Note 8) | 13,217 | 12,526 | |
U.S. Natural Gas Pipelines | |||
Segmented information | |||
Natural Gas Pipelines | 2,526 | 1,444 | 1,159 |
U.S. Natural Gas Pipelines | Operating segments | |||
Segmented information | |||
Natural Gas Pipelines | 2,526 | 1,444 | 1,159 |
Income from Equity Investments (Note 9) | 214 | 162 | 143 |
Plant operating costs and other | (1,000) | (555) | (467) |
Property taxes | (120) | (77) | (68) |
Depreciation and amortization | (397) | (243) | (211) |
Goodwill and other asset impairment charges | 0 | 0 | |
Gain on assets held for sale/sold | (4) | (125) | 0 |
Segmented earnings/(losses) | 1,219 | 606 | 556 |
Capital spending | |||
Capital expenditures | 1,517 | 534 | 237 |
Capital projects in development | 0 | 3 | 40 |
Payments to Acquire Productive Assets | 1,517 | 537 | 277 |
Assets | 34,422 | 12,207 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment (Note 8) | 18,055 | 7,168 | |
Mexico Natural Gas Pipelines | |||
Segmented information | |||
Natural Gas Pipelines | 378 | 259 | 197 |
Mexico Natural Gas Pipelines | Operating segments | |||
Segmented information | |||
Natural Gas Pipelines | 378 | 259 | 197 |
Income from Equity Investments (Note 9) | (3) | 5 | 8 |
Plant operating costs and other | (42) | (49) | (41) |
Property taxes | 0 | 0 | 0 |
Depreciation and amortization | (43) | (44) | (31) |
Goodwill and other asset impairment charges | 0 | 0 | |
Gain on assets held for sale/sold | 0 | 0 | 9 |
Segmented earnings/(losses) | 290 | 171 | 142 |
Capital spending | |||
Capital expenditures | 944 | 566 | 717 |
Capital projects in development | 0 | 0 | 1 |
Payments to Acquire Productive Assets | 944 | 566 | 718 |
Assets | 5,013 | 3,787 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment (Note 8) | 4,527 | 3,623 | |
Liquids Pipelines | Operating segments | |||
Segmented information | |||
Income from Equity Investments (Note 9) | (1) | ||
Plant operating costs and other | (554) | (491) | (439) |
Property taxes | (88) | (79) | (62) |
Depreciation and amortization | (285) | (266) | (216) |
Goodwill and other asset impairment charges | 0 | (3,686) | |
Gain on assets held for sale/sold | 0 | ||
Segmented earnings/(losses) | 827 | (2,643) | 830 |
Capital spending | |||
Capital expenditures | 668 | 1,012 | 1,469 |
Capital projects in development | 142 | 278 | 480 |
Payments to Acquire Productive Assets | 810 | 1,290 | 1,949 |
Assets | 16,896 | 16,046 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment (Note 8) | 14,147 | 14,186 | |
Liquids Pipelines | 1,755 | 1,879 | 1,547 |
Energy | Operating segments | |||
Segmented information | |||
Income from Equity Investments (Note 9) | 292 | 261 | 359 |
Plant operating costs and other | (834) | (786) | (934) |
Commodity purchases resold | (2,172) | (2,237) | (1,836) |
Property taxes | (80) | (89) | (77) |
Depreciation and amortization | (293) | (336) | (309) |
Goodwill and other asset impairment charges | (1,388) | (59) | |
Gain on assets held for sale/sold | (829) | 0 | 108 |
Segmented earnings/(losses) | (1,140) | 792 | 1,036 |
Capital spending | |||
Capital expenditures | 473 | 376 | 206 |
Payments to Acquire Productive Assets | 473 | 376 | 206 |
Assets | 13,169 | 15,614 | |
GEOGRAPHIC INFORMATION | |||
Plant, Property and Equipment (Note 8) | 4,249 | 7,129 | |
Energy | CAD 4,164 | CAD 4,038 | CAD 3,725 |
ACQUISITION OF COLUMBIA (Detail
ACQUISITION OF COLUMBIA (Details) $ / shares in Units, shares in Millions, CAD in Millions, $ in Millions | Jul. 01, 2016CADmikmBcf | Jul. 01, 2016USD ($) | Dec. 31, 2016CAD | Dec. 31, 2016CAD | Jul. 01, 2016USD ($)mikm$ / sharesBcf | Jun. 30, 2016$ / sharesshares | Apr. 01, 2016CADshares | Dec. 31, 2015CAD | Dec. 31, 2014CAD |
Business Acquisition [Line Items] | |||||||||
Common stock, value, subscriptions | CAD 4,400 | ||||||||
Subscription receipt (in shares) | shares | 96.6 | ||||||||
Goodwill | CAD 13,958 | CAD 13,958 | CAD 4,812 | CAD 4,034 | |||||
Columbian Pipeline | |||||||||
Business Acquisition [Line Items] | |||||||||
Percentage of interests acquired | 100.00% | 100.00% | |||||||
Purchase price | $ | $ 10,300 | ||||||||
Share price (in usd per share) | $ / shares | $ 25.5 | ||||||||
Common stock, value, subscriptions | CAD 4,400 | ||||||||
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 | |||||||
Goodwill | CAD 10,078 | $ 7,700 | |||||||
Estimated increase (decrease) in fair value of acquired liabilities, long-term debt | 300 | 231 | |||||||
Common unit, outstanding | shares | 53.8 | ||||||||
Share price (in USD per share) | $ / shares | $ 15 | ||||||||
Acquisition costs | 36 | ||||||||
Pro revenue of acquiree since acquisition date | 929 | ||||||||
Pro forma information, earnings of acquiree since acquisition date | CAD 132 | ||||||||
Bridge Loan | Columbian Pipeline | |||||||||
Business Acquisition [Line Items] | |||||||||
Proceeds from lines of credit | $ | 6,900 | ||||||||
Natural Gas | Columbian Pipeline | |||||||||
Business Acquisition [Line Items] | |||||||||
Increase (decrease) in fair value of property, plant, and equipment | 840 | 646 | |||||||
Mining Properties and Mineral Rights | Columbian Pipeline | |||||||||
Business Acquisition [Line Items] | |||||||||
Increase (decrease) in fair value of property, plant, and equipment | 241 | 185 | |||||||
Pension Benefit Plans | Columbian Pipeline | |||||||||
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 | CAD 2 | $ 2 | |||||||
U.S. federal | Columbian Pipeline | |||||||||
Business Acquisition [Line Items] | |||||||||
Effective income tax rate percent | 39.00% |
ACQUISITION OF COLUMBIA - Sched
ACQUISITION OF COLUMBIA - Schedule of Assets Acquired and Liabilities Assumed (Details) CAD in Millions, $ in Millions | Jul. 01, 2016CAD | Jul. 01, 2016USD ($) | Dec. 31, 2016CAD | Jul. 01, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2014CAD |
Business Acquisition [Line Items] | ||||||
Exchange rate | 1.30 | 1.34 | 1.30 | |||
Fair Value of Net Assets Acquired | ||||||
Goodwill (Note 11) | CAD 13,958 | CAD 4,812 | CAD 4,034 | |||
Columbian Pipeline | ||||||
Business Acquisition [Line Items] | ||||||
Purchase Price Consideration | CAD 13,392 | $ 10,294 | ||||
Fair Value of Net Assets Acquired | ||||||
Current assets | 856 | $ 658 | ||||
Plant, property and equipment | 9,835 | 7,560 | ||||
Equity investments | 574 | 441 | ||||
Regulatory assets | 248 | 190 | ||||
Intangibles and other assets | 175 | 135 | ||||
Current liabilities | (777) | (597) | ||||
Regulatory liabilities | (383) | (294) | ||||
Other long-term liabilities | (187) | (144) | ||||
Deferred income tax liabilities | (2,098) | (1,613) | ||||
Long-term debt | (3,878) | (2,981) | ||||
Non-controlling interests | (1,051) | (808) | ||||
Fair Value of Net Assets Acquired | 3,314 | 2,547 | ||||
Goodwill (Note 11) | CAD 10,078 | $ 7,700 |
ACQUISITION OF COLUMBIA - Sch71
ACQUISITION OF COLUMBIA - Schedule of Fair Value of Debt Acquired (Details) CAD in Millions | Dec. 31, 2016 | Jul. 01, 2016CAD | Jul. 01, 2016USD ($) |
Senior Unsecured Notes, 2.45% Interest Rate | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 500,000,000 | ||
Senior Unsecured Notes, 3.30% Interest Rate | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | 750,000,000 | ||
Senior Unsecured Notes, 4.50% Interest Rate | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | 1,000,000,000 | ||
Senior Unsecured Notes, 5.80% Interest Rate | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | 500,000,000 | ||
Columbian Pipeline | |||
Debt Instrument [Line Items] | |||
Fair Value | CAD 3,878 | 2,981,000,000 | |
Columbian Pipeline | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Fair Value | 2,981,000,000 | ||
Columbian Pipeline | Senior Unsecured Notes, 2.45% Interest Rate | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Fair Value | 506,000,000 | ||
Interest Rate | 2.45% | ||
Columbian Pipeline | Senior Unsecured Notes, 3.30% Interest Rate | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Fair Value | 779,000,000 | ||
Interest Rate | 3.30% | ||
Columbian Pipeline | Senior Unsecured Notes, 4.50% Interest Rate | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Fair Value | 1,092,000,000 | ||
Interest Rate | 4.50% | ||
Columbian Pipeline | Senior Unsecured Notes, 5.80% Interest Rate | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Fair Value | $ 604,000,000 | ||
Interest Rate | 5.80% |
ACQUISITION OF COLUMBIA - Pro F
ACQUISITION OF COLUMBIA - Pro Forma Information (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Business Combinations [Abstract] | ||
Revenues | CAD 13,404 | CAD 13,007 |
Net Income/(Loss) | 627 | (820) |
Net Income/(Loss) Attributable to Common Shares | CAD 234 | CAD (971) |
ASSETS HELD FOR SALE (Details)
ASSETS HELD FOR SALE (Details) CAD in Millions, $ in Millions | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Jul. 01, 2016 |
Assets Held for Sale | |||
Accounts receivable | CAD 18 | $ 13 | |
Inventories | 75 | 56 | |
Other current assets | 121 | 90 | |
Plant, property and equipment | 2,993 | 2,229 | |
Intangible and other assets | 440 | 328 | |
Foreign currency translation gains | 70 | 0 | |
Total assets held for sale | 3,717 | 2,716 | |
Liabilities Related to Assets Held for Sale | |||
Accounts payable and other | 43 | 32 | |
Other long-term liabilities | 43 | 32 | |
Total Liabilities Related to Assets Held for Sale (included in Accounts payable and other, Note 13) | CAD 86 | $ 64 | |
Exchange rate | 1.34 | 1.34 | 1.30 |
U.S. Natural Gas Pipelines | Gas Plant | |||
Assets Held for Sale | |||
Plant, property and equipment | CAD 17 | $ 13 |
ASSETS HELD FOR SALE - Narrativ
ASSETS HELD FOR SALE - Narrative (Details) CAD in Millions, $ in Billions | Nov. 01, 2016USD ($) | Mar. 01, 2016CAD | Jun. 30, 2017CAD | Jun. 30, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2014CAD |
Long Lived Assets Held-for-sale [Line Items] | |||||||
Proceeds from sale of assets, net of transaction costs | CAD 6 | CAD 0 | CAD 196 | ||||
Gain (loss) on disposal | (833) | (125) | CAD 117 | ||||
Disposal group, not discontinued operations | Ravenswood, Ironwood, Kibby Wind and Ocean State Power | |||||||
Long Lived Assets Held-for-sale [Line Items] | |||||||
Proceeds from sale of assets, net of transaction costs | $ | $ 2.2 | ||||||
Gain (Loss) on Disposition of Property Plant Equipment | 829 | ||||||
Gain (Loss) on Disposition of Property Plant Equipment, Net of Tax | 863 | ||||||
Foreign currency translation gain on assets held for sale | CAD 70 | ||||||
Disposal group, not discontinued operations | TC Offshore LLC | |||||||
Long Lived Assets Held-for-sale [Line Items] | |||||||
Gain (loss) on disposal | CAD (4) | CAD (125) | |||||
Scenario, Forecast | Disposal group, not discontinued operations | TC Hydro | |||||||
Long Lived Assets Held-for-sale [Line Items] | |||||||
Proceeds from sale of assets, net of transaction costs | $ | $ 1.1 | ||||||
Gain (Loss) on Disposition of Property Plant Equipment | CAD 710 | ||||||
Gain (Loss) on Disposition of Property Plant Equipment, Net of Tax | 440 | ||||||
Foreign currency translation gain on assets held for sale | CAD 5 |
OTHER CURRENT ASSETS (Details)
OTHER CURRENT ASSETS (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Other Assets [Abstract] | ||
Fair value of derivative contracts (Note 24) | CAD 376 | CAD 442 |
Cash provided as collateral | 313 | 590 |
Prepaid expenses | 131 | 132 |
Regulatory assets (Note 10) | 33 | 85 |
Other1 | 55 | 89 |
Other current assets, total | CAD 908 | CAD 1,338 |
PLANT, PROPERTY AND EQUIPMENT76
PLANT, PROPERTY AND EQUIPMENT (Details) - CAD CAD in Millions | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Plant, property and equipment | ||||
Cost | CAD 67,116 | CAD 76,738 | CAD 67,116 | |
Accumulated Depreciation | 22,299 | 22,263 | 22,299 | |
Net Book Value | 44,817 | 54,475 | 44,817 | |
Proceeds from sale of assets, net of transaction costs | 6 | 0 | CAD 196 | |
Energy Turbine | ||||
Plant, property and equipment | ||||
Impairment charge, pre-tax | 59 | |||
Impairment charge, after-tax | 43 | |||
Keystone XL | ||||
Plant, property and equipment | ||||
Net Book Value | 621 | CAD 526 | 621 | |
Impairment charge, pre-tax | 3,686 | |||
Impairment charge, after-tax | 2,891 | |||
Keystone XL | Significant Unobservable Inputs (Level III) | ||||
Plant, property and equipment | ||||
Estimated fair value | 621 | 621 | ||
Keystone XL | Plant and equipment | Market Approach Valuation Technique | Significant Unobservable Inputs (Level III) | ||||
Plant, property and equipment | ||||
Estimated fair value | 463 | 463 | ||
Disposal period (in years) | 2 years | |||
Keystone XL | Terminals, including KHT | Significant Unobservable Inputs (Level III) | ||||
Plant, property and equipment | ||||
Estimated fair value | 158 | 158 | ||
Keystone XL | Future cancellation costs | ||||
Plant, property and equipment | ||||
Impairment charge, pre-tax | 77 | |||
Impairment charge, after-tax | 56 | |||
Energy | Facilities under PPAs | ||||
Plant, property and equipment | ||||
Cost | 1,341 | CAD 1,319 | 1,341 | |
Accumulated Depreciation | 302 | 335 | 302 | |
Revenues recognized through the sale of electricity | 212 | 235 | CAD 223 | |
Operating segments | Canadian Natural Gas Pipelines | ||||
Plant, property and equipment | ||||
Cost | 27,830 | 29,239 | 27,830 | |
Accumulated Depreciation | 15,304 | 16,022 | 15,304 | |
Net Book Value | 12,526 | 13,217 | 12,526 | |
Operating segments | Canadian Natural Gas Pipelines | NGTL System | ||||
Plant, property and equipment | ||||
Cost | 12,709 | 13,536 | 12,709 | |
Accumulated Depreciation | 5,713 | 5,969 | 5,713 | |
Net Book Value | 6,996 | 7,567 | 6,996 | |
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Pipeline | ||||
Plant, property and equipment | ||||
Cost | 8,456 | 8,814 | 8,456 | |
Accumulated Depreciation | 3,820 | 3,951 | 3,820 | |
Net Book Value | 4,636 | 4,863 | 4,636 | |
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Compression | ||||
Plant, property and equipment | ||||
Cost | 2,188 | 2,447 | 2,188 | |
Accumulated Depreciation | 1,404 | 1,499 | 1,404 | |
Net Book Value | 784 | 948 | 784 | |
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Metering and other | ||||
Plant, property and equipment | ||||
Cost | 1,096 | 1,124 | 1,096 | |
Accumulated Depreciation | 489 | 519 | 489 | |
Net Book Value | 607 | 605 | 607 | |
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Property, plant and equipment excluding under construction | ||||
Plant, property and equipment | ||||
Cost | 11,740 | 12,385 | 11,740 | |
Accumulated Depreciation | 5,713 | 5,969 | 5,713 | |
Net Book Value | 6,027 | 6,416 | 6,027 | |
Operating segments | Canadian Natural Gas Pipelines | NGTL System | Under construction | ||||
Plant, property and equipment | ||||
Cost | 969 | 1,151 | 969 | |
Net Book Value | 969 | 1,151 | 969 | |
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | ||||
Plant, property and equipment | ||||
Cost | 13,353 | 13,863 | 13,353 | |
Accumulated Depreciation | 8,378 | 8,780 | 8,378 | |
Net Book Value | 4,975 | 5,083 | 4,975 | |
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Pipeline | ||||
Plant, property and equipment | ||||
Cost | 9,164 | 9,502 | 9,164 | |
Accumulated Depreciation | 5,966 | 6,221 | 5,966 | |
Net Book Value | 3,198 | 3,281 | 3,198 | |
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Compression | ||||
Plant, property and equipment | ||||
Cost | 3,433 | 3,537 | 3,433 | |
Accumulated Depreciation | 2,220 | 2,361 | 2,220 | |
Net Book Value | 1,213 | 1,176 | 1,213 | |
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Metering and other | ||||
Plant, property and equipment | ||||
Cost | 499 | 605 | 499 | |
Accumulated Depreciation | 192 | 198 | 192 | |
Net Book Value | 307 | 407 | 307 | |
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Property, plant and equipment excluding under construction | ||||
Plant, property and equipment | ||||
Cost | 13,096 | 13,644 | 13,096 | |
Accumulated Depreciation | 8,378 | 8,780 | 8,378 | |
Net Book Value | 4,718 | 4,864 | 4,718 | |
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline | Under construction | ||||
Plant, property and equipment | ||||
Cost | 257 | 219 | 257 | |
Net Book Value | 257 | 219 | 257 | |
Operating segments | Canadian Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | ||||
Plant, property and equipment | ||||
Cost | 1,768 | 1,840 | 1,768 | |
Accumulated Depreciation | 1,213 | 1,273 | 1,213 | |
Net Book Value | 555 | 567 | 555 | |
Operating segments | Canadian Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | Under construction | ||||
Plant, property and equipment | ||||
Cost | 63 | 112 | 63 | |
Accumulated Depreciation | 0 | 0 | 0 | |
Net Book Value | 63 | 112 | 63 | |
Operating segments | Canadian Natural Gas Pipelines | Other | ||||
Plant, property and equipment | ||||
Cost | 1,705 | 1,728 | 1,705 | |
Accumulated Depreciation | 1,213 | 1,273 | 1,213 | |
Net Book Value | 492 | 455 | 492 | |
Operating segments | U.S. Natural Gas Pipelines | ||||
Plant, property and equipment | ||||
Cost | 10,398 | 21,532 | 10,398 | |
Accumulated Depreciation | 3,230 | 3,477 | 3,230 | |
Net Book Value | 7,168 | 18,055 | 7,168 | |
Operating segments | U.S. Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | ||||
Plant, property and equipment | ||||
Cost | 6,567 | 8,745 | 6,567 | |
Accumulated Depreciation | 2,441 | 2,560 | 2,441 | |
Net Book Value | 4,126 | 6,185 | 4,126 | |
Operating segments | U.S. Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | ||||
Plant, property and equipment | ||||
Cost | 6,559 | 8,399 | 6,559 | |
Accumulated Depreciation | 2,441 | 2,560 | 2,441 | |
Net Book Value | 4,118 | 5,839 | 4,118 | |
Operating segments | U.S. Natural Gas Pipelines | Other Canadian Natural Gas Pipelines | Under construction | ||||
Plant, property and equipment | ||||
Cost | 8 | 346 | 8 | |
Accumulated Depreciation | 0 | 0 | 0 | |
Net Book Value | 8 | 346 | 8 | |
Operating segments | U.S. Natural Gas Pipelines | GTN | ||||
Plant, property and equipment | ||||
Cost | 2,278 | 2,221 | 2,278 | |
Accumulated Depreciation | 765 | 810 | 765 | |
Net Book Value | 1,513 | 1,411 | 1,513 | |
Operating segments | U.S. Natural Gas Pipelines | Great Lakes | ||||
Plant, property and equipment | ||||
Cost | 2,157 | 2,106 | 2,157 | |
Accumulated Depreciation | 1,155 | 1,155 | 1,155 | |
Net Book Value | 1,002 | 951 | 1,002 | |
Operating segments | U.S. Natural Gas Pipelines | Midstream | ||||
Plant, property and equipment | ||||
Cost | 0 | 1,072 | 0 | |
Accumulated Depreciation | 0 | 23 | 0 | |
Net Book Value | 0 | 1,049 | 0 | |
Operating segments | U.S. Natural Gas Pipelines | Columbia Gulf | ||||
Plant, property and equipment | ||||
Cost | 0 | 880 | 0 | |
Accumulated Depreciation | 0 | 5 | 0 | |
Net Book Value | 0 | 875 | 0 | |
Operating segments | U.S. Natural Gas Pipelines | Other | ||||
Plant, property and equipment | ||||
Cost | 2,124 | 2,120 | 2,124 | |
Accumulated Depreciation | 521 | 567 | 521 | |
Net Book Value | 1,603 | 1,553 | 1,603 | |
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | ||||
Plant, property and equipment | ||||
Cost | 0 | 8,605 | 0 | |
Accumulated Depreciation | 0 | 54 | 0 | |
Net Book Value | 0 | 8,551 | 0 | |
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Pipeline | ||||
Plant, property and equipment | ||||
Cost | 0 | 3,072 | 0 | |
Accumulated Depreciation | 0 | 13 | 0 | |
Net Book Value | 0 | 3,059 | 0 | |
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Compression | ||||
Plant, property and equipment | ||||
Cost | 0 | 1,864 | 0 | |
Accumulated Depreciation | 0 | 7 | 0 | |
Net Book Value | 0 | 1,857 | 0 | |
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Metering and other | ||||
Plant, property and equipment | ||||
Cost | 0 | 2,542 | 0 | |
Accumulated Depreciation | 0 | 34 | 0 | |
Net Book Value | 0 | 2,508 | 0 | |
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Property, plant and equipment excluding under construction | ||||
Plant, property and equipment | ||||
Cost | 0 | 7,478 | 0 | |
Accumulated Depreciation | 0 | 54 | 0 | |
Net Book Value | 0 | 7,424 | 0 | |
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas | Under construction | ||||
Plant, property and equipment | ||||
Cost | 0 | 1,127 | 0 | |
Accumulated Depreciation | 0 | 0 | 0 | |
Net Book Value | 0 | 1,127 | 0 | |
Operating segments | U.S. Natural Gas Pipelines | ANR | ||||
Plant, property and equipment | ||||
Cost | 3,831 | 4,182 | 3,831 | |
Accumulated Depreciation | 789 | 863 | 789 | |
Net Book Value | 3,042 | 3,319 | 3,042 | |
Operating segments | U.S. Natural Gas Pipelines | ANR | Pipeline | ||||
Plant, property and equipment | ||||
Cost | 1,449 | 1,468 | 1,449 | |
Accumulated Depreciation | 350 | 349 | 350 | |
Net Book Value | 1,099 | 1,119 | 1,099 | |
Operating segments | U.S. Natural Gas Pipelines | ANR | Compression | ||||
Plant, property and equipment | ||||
Cost | 1,101 | 1,494 | 1,101 | |
Accumulated Depreciation | 187 | 260 | 187 | |
Net Book Value | 914 | 1,234 | 914 | |
Operating segments | U.S. Natural Gas Pipelines | ANR | Metering and other | ||||
Plant, property and equipment | ||||
Cost | 977 | 988 | 977 | |
Accumulated Depreciation | 252 | 254 | 252 | |
Net Book Value | 725 | 734 | 725 | |
Operating segments | U.S. Natural Gas Pipelines | ANR | Property, plant and equipment excluding under construction | ||||
Plant, property and equipment | ||||
Cost | 3,527 | 3,950 | 3,527 | |
Accumulated Depreciation | 789 | 863 | 789 | |
Net Book Value | 2,738 | 3,087 | 2,738 | |
Operating segments | U.S. Natural Gas Pipelines | ANR | Under construction | ||||
Plant, property and equipment | ||||
Cost | 304 | 232 | 304 | |
Net Book Value | 304 | 232 | 304 | |
Operating segments | Mexico Natural Gas Pipelines | ||||
Plant, property and equipment | ||||
Cost | 3,826 | 4,766 | 3,826 | |
Accumulated Depreciation | 203 | 239 | 203 | |
Net Book Value | 3,623 | 4,527 | 3,623 | |
Operating segments | Mexico Natural Gas Pipelines | Pipeline | ||||
Plant, property and equipment | ||||
Cost | 1,296 | 2,734 | 1,296 | |
Accumulated Depreciation | 162 | 180 | 162 | |
Net Book Value | 1,134 | 2,554 | 1,134 | |
Operating segments | Mexico Natural Gas Pipelines | Compression | ||||
Plant, property and equipment | ||||
Cost | 183 | 422 | 183 | |
Accumulated Depreciation | 14 | 19 | 14 | |
Net Book Value | 169 | 403 | 169 | |
Operating segments | Mexico Natural Gas Pipelines | Metering and other | ||||
Plant, property and equipment | ||||
Cost | 388 | 502 | 388 | |
Accumulated Depreciation | 27 | 40 | 27 | |
Net Book Value | 361 | 462 | 361 | |
Operating segments | Mexico Natural Gas Pipelines | Property, plant and equipment excluding under construction | ||||
Plant, property and equipment | ||||
Cost | 1,867 | 3,658 | 1,867 | |
Accumulated Depreciation | 203 | 239 | 203 | |
Net Book Value | 1,664 | 3,419 | 1,664 | |
Operating segments | Mexico Natural Gas Pipelines | Under construction | ||||
Plant, property and equipment | ||||
Cost | 1,959 | 1,108 | 1,959 | |
Net Book Value | 1,959 | 1,108 | 1,959 | |
Operating segments | Liquids Pipelines | ||||
Plant, property and equipment | ||||
Cost | 15,240 | 15,455 | 15,240 | |
Accumulated Depreciation | 1,054 | 1,308 | 1,054 | |
Net Book Value | 14,186 | 14,147 | 14,186 | |
Operating segments | Liquids Pipelines | Under construction | ||||
Plant, property and equipment | ||||
Cost | 1,826 | 1,434 | 1,826 | |
Net Book Value | 1,826 | 1,434 | 1,826 | |
Operating segments | Liquids Pipelines | Keystone Pipeline System | Pipeline | ||||
Plant, property and equipment | ||||
Cost | 9,288 | 10,572 | 9,288 | |
Accumulated Depreciation | 718 | 901 | 718 | |
Net Book Value | 8,570 | 9,671 | 8,570 | |
Operating segments | Liquids Pipelines | Keystone Pipeline System | Property, plant and equipment excluding under construction | ||||
Plant, property and equipment | ||||
Cost | 13,414 | 14,021 | 13,414 | |
Accumulated Depreciation | 1,054 | 1,308 | 1,054 | |
Net Book Value | 12,360 | 12,713 | 12,360 | |
Operating segments | Liquids Pipelines | Keystone Pipeline System | Pumping equipment | ||||
Plant, property and equipment | ||||
Cost | 1,092 | 928 | 1,092 | |
Accumulated Depreciation | 108 | 121 | 108 | |
Net Book Value | 984 | 807 | 984 | |
Operating segments | Liquids Pipelines | Keystone Pipeline System | Tanks and other | ||||
Plant, property and equipment | ||||
Cost | 3,034 | 2,521 | 3,034 | |
Accumulated Depreciation | 228 | 286 | 228 | |
Net Book Value | 2,806 | 2,235 | 2,806 | |
Operating segments | Energy | ||||
Plant, property and equipment | ||||
Cost | 9,555 | 5,336 | 9,555 | |
Accumulated Depreciation | 2,426 | 1,087 | 2,426 | |
Net Book Value | 7,129 | 4,249 | 7,129 | |
Operating segments | Energy | Property, plant and equipment excluding under construction | ||||
Plant, property and equipment | ||||
Cost | 9,125 | 4,607 | 9,125 | |
Accumulated Depreciation | 2,426 | 1,087 | 2,426 | |
Net Book Value | 6,699 | 3,520 | 6,699 | |
Operating segments | Energy | Under construction | ||||
Plant, property and equipment | ||||
Cost | 430 | 729 | 430 | |
Net Book Value | 430 | 729 | 430 | |
Operating segments | Energy | Natural Gas – Ravenswood | ||||
Plant, property and equipment | ||||
Cost | 2,607 | 0 | 2,607 | |
Accumulated Depreciation | 654 | 0 | 654 | |
Net Book Value | 1,953 | 0 | 1,953 | |
Operating segments | Energy | Natural Gas - Other | ||||
Plant, property and equipment | ||||
Cost | 3,361 | 2,696 | 3,361 | |
Accumulated Depreciation | 1,164 | 696 | 1,164 | |
Net Book Value | 2,197 | 2,000 | 2,197 | |
Operating segments | Energy | Hydro, Wind and Solar | ||||
Plant, property and equipment | ||||
Cost | 2,417 | 1,180 | 2,417 | |
Accumulated Depreciation | 476 | 245 | 476 | |
Net Book Value | 1,941 | 935 | 1,941 | |
Operating segments | Energy | Natural Gas Storage and Other | ||||
Plant, property and equipment | ||||
Cost | 740 | 731 | 740 | |
Accumulated Depreciation | 132 | 146 | 132 | |
Net Book Value | 608 | 585 | 608 | |
Corporate | ||||
Plant, property and equipment | ||||
Cost | 267 | 410 | 267 | |
Accumulated Depreciation | 82 | 130 | 82 | |
Net Book Value | CAD 185 | CAD 280 | CAD 185 |
EQUITY INVESTMENTS - Schedule a
EQUITY INVESTMENTS - Schedule and Narrative (Details) CAD in Millions, $ in Millions | May 01, 2016USD ($) | Mar. 31, 2016CAD | Mar. 31, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2014CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Nov. 30, 2015 |
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | CAD 514 | CAD 440 | CAD 522 | |||||||
Equity Investments | CAD 6,214 | 6,544 | 6,214 | |||||||
Distributions received from equity investments | 1,571 | 802 | 738 | |||||||
Returns of capital | 727 | 9 | 12 | |||||||
Undistributed earnings | 198 | 551 | ||||||||
Contributions made to equity investments | CAD 765 | CAD 493 | 256 | |||||||
Northern Border | ||||||||||
Equity Investments | ||||||||||
Difference between the carrying value of the investment and the underlying equity in the net assets | $ | $ 116 | $ 117 | ||||||||
Iroquois | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 50.00% | 49.35% | 49.35% | |||||||
Additional ownership acquired (percent) | 0.65% | 4.87% | 4.87% | |||||||
Contributions made to equity investments | $ | $ 7 | $ 54 | ||||||||
Bruce Power | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 48.50% | 48.50% | 48.50% | 48.50% | 48.50% | |||||
Difference between the carrying value of the investment and the underlying equity in the net assets | CAD 973 | CAD 942 | CAD 973 | |||||||
Bruce A | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 48.90% | 48.90% | 48.90% | 48.90% | ||||||
Bruce B | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 46.50% | 46.50% | 46.50% | 31.60% | ||||||
Additional ownership acquired (percent) | 14.89% | 14.89% | 14.89% | |||||||
Contributions made to equity investments | CAD 236 | |||||||||
Canadian Natural Gas Pipelines | TQM | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | CAD 12 | CAD 12 | 12 | |||||||
Equity Investments | 72 | CAD 71 | 72 | |||||||
U.S. Natural Gas Pipelines | Northern Border | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | CAD 92 | 85 | 76 | |||||||
Equity Investments | CAD 664 | CAD 597 | CAD 664 | |||||||
U.S. Natural Gas Pipelines | Iroquois | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 44.50% | 50.00% | 44.50% | 50.00% | 44.50% | |||||
Income/(Loss) from Equity Investments | CAD 54 | CAD 51 | 43 | |||||||
Equity Investments | CAD 238 | CAD 309 | 238 | |||||||
Additional ownership acquired (percent) | 0.65% | 4.87% | 4.87% | |||||||
U.S. Natural Gas Pipelines | Millennium | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 47.50% | 47.50% | ||||||||
Income/(Loss) from Equity Investments | CAD 33 | |||||||||
Equity Investments | CAD 295 | |||||||||
U.S. Natural Gas Pipelines | Pennant Midstream | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 47.00% | 47.00% | ||||||||
Income/(Loss) from Equity Investments | CAD 6 | |||||||||
Equity Investments | 246 | |||||||||
U.S. Natural Gas Pipelines | Other | ||||||||||
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | 29 | 26 | 24 | |||||||
Equity Investments | 31 | 93 | 31 | |||||||
Mexico Natural Gas Pipelines | Other | ||||||||||
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | 5 | 8 | ||||||||
Equity Investments | 42 | CAD 28 | 42 | |||||||
Mexico Natural Gas Pipelines | Sur de Texas | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 60.00% | 60.00% | ||||||||
Income/(Loss) from Equity Investments | CAD (3) | |||||||||
Equity Investments | 255 | |||||||||
Liquids Pipelines | Other | ||||||||||
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | 0 | 0 | 0 | |||||||
Equity Investments | 16 | CAD 39 | 16 | |||||||
Liquids Pipelines | Grand Rapids | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | CAD (1) | 0 | 0 | |||||||
Equity Investments | 542 | 876 | 542 | |||||||
Energy | Other | ||||||||||
Equity Investments | ||||||||||
Income/(Loss) from Equity Investments | 3 | 5 | 1 | |||||||
Equity Investments | 67 | CAD 66 | 67 | |||||||
Energy | Bruce Power | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 48.50% | 48.50% | ||||||||
Income/(Loss) from Equity Investments | CAD 293 | 249 | 314 | |||||||
Equity Investments | 4,200 | CAD 3,356 | 4,200 | |||||||
Energy | Portlands Energy | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | CAD 33 | 30 | 36 | |||||||
Equity Investments | 321 | CAD 313 | 321 | |||||||
Energy | ASTC Power Partnership | ||||||||||
Equity Investments | ||||||||||
Ownership interest (percent) | 50.00% | 50.00% | ||||||||
Income/(Loss) from Equity Investments | CAD (37) | (23) | CAD 8 | |||||||
Equity Investments | CAD 21 | CAD 21 | ||||||||
Energy | Sundance B PPA | ||||||||||
Equity Investments | ||||||||||
Asset impairment charges | CAD 29 | |||||||||
Asset impairment charge, after tax | CAD 21 |
EQUITY INVESTMENTS - Summarized
EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income | |||
Revenues | CAD 4,336 | CAD 4,337 | CAD 4,814 |
Operating and other expenses | (3,143) | (3,254) | (3,489) |
Net income | 1,080 | 1,046 | 1,264 |
Net income attributable to TransCanada | 514 | 440 | CAD 522 |
Balance Sheet | |||
Current assets | 1,669 | 1,530 | |
Non-current assets | 15,853 | 13,190 | |
Current liabilities | (1,120) | (1,370) | |
Non-current liabilities | CAD (5,867) | CAD (3,116) |
RATE-REGULATED BUSINESSES - Nar
RATE-REGULATED BUSINESSES - Narrative (Details) CAD in Millions, $ in Billions | Nov. 28, 2014CAD | Apr. 30, 2016 | Mar. 31, 2016USD ($) | Mar. 31, 2013 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013USD ($) |
Public Utilities, General Disclosures [Line Items] | ||||||||
After-tax annual contribution to reduce revenue requirement | CAD | CAD 20 | |||||||
Fixed toll term (in years) | 6 years | |||||||
National Energy Board | 2015 Revenue Requirement Settlement | NGTL System | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Approved ROE on deemed common equity (percent) | 10.10% | |||||||
Deemed common equity (percent) | 40.00% | |||||||
Period of settlement (in years) | 2 years | 1 year | ||||||
Canadian Regulated Operations | National Energy Board | 2015 Revenue Requirement Settlement | NGTL System | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Approved ROE on deemed common equity (percent) | 10.10% | |||||||
Deemed common equity (percent) | 40.00% | 40.00% | ||||||
Canadian Mainline | Canadian Regulated Operations | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Approved ROE on deemed common equity (percent) | 10.10% | 11.50% | ||||||
Deemed common equity (percent) | 40.00% | 40.00% | ||||||
Term of regulatory decision (in years) | 5 years | |||||||
Columbia Gas Transmission | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Maximum cost recovery and return on investment | $ | $ 1.1 | $ 1.5 | ||||||
Cost recovery and return on investment, recognition period (in years) | 5 years | |||||||
Cost recovery and return on investment, additional period (in years) | 3 years |
RATE-REGULATED BUSINESSES - Ass
RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) - CAD CAD in Millions | 1 Months Ended | 5 Months Ended | 12 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | |
Regulatory Assets | ||||
Regulatory Assets | CAD 1,355 | CAD 1,355 | CAD 1,269 | |
Less: Current portion included in Other current assets (Note 7) | 33 | 33 | 85 | |
Regulatory assets, noncurrent | 1,322 | 1,322 | 1,184 | |
Regulatory Liabilities | ||||
Regulatory Liabilities | 2,299 | 2,299 | 1,203 | |
Less: Current portion included in Accounts payable and other (Note 14) | 178 | 178 | 44 | |
Regulated liabilities, noncurrent | 2,121 | 2,121 | 1,159 | |
Operating and debt-service regulatory liabilities | ||||
Regulatory Liabilities | ||||
Regulatory Liabilities | 47 | CAD 47 | 32 | |
Remaining Recovery/ Settlement Period (years) | 1 year | |||
Long term adjustment account | ||||
Regulatory Liabilities | ||||
Regulatory Liabilities | 659 | CAD 659 | 231 | |
Remaining Recovery/ Settlement Period (years) | 46 years | |||
Pipeline abandonment costs | ||||
Regulatory Liabilities | ||||
Regulatory Liabilities | 541 | CAD 541 | 285 | |
Bridging amortization account | ||||
Regulatory Liabilities | ||||
Regulatory Liabilities | 451 | CAD 451 | 456 | |
Remaining Recovery/ Settlement Period (years) | 14 years | |||
Cost of removal | ||||
Regulatory Liabilities | ||||
Regulatory Liabilities | 226 | CAD 226 | 36 | |
Other | ||||
Regulatory Liabilities | ||||
Regulatory Liabilities | CAD 54 | 54 | 16 | |
Postretirement benefit costs | ||||
Other disclosures pertaining to regulated assets and liabilities | ||||
Regulatory liability settlement | CAD 106 | |||
Refund to customers | 53 | |||
Amount to be amortized | 53 | |||
Amortization period (in years) | 3 years | |||
Amount to be addressed In next settlement | CAD 41 | |||
Deferred income taxes | ||||
Regulatory Assets | ||||
Regulatory Assets | CAD 861 | 861 | 894 | |
Operating and debt-service regulatory assets | ||||
Regulatory Assets | ||||
Regulatory Assets | 1 | CAD 1 | 47 | |
Remaining Recovery/ Settlement Period (years) | 1 year | |||
Foreign exchange on long-term debt | ||||
Regulatory Assets | ||||
Regulatory Assets | 37 | CAD 37 | 54 | |
Foreign exchange on long-term debt | Minimum | ||||
Regulatory Assets | ||||
Remaining Recovery/ Settlement Period (years) | 1 year | |||
Foreign exchange on long-term debt | Maximum | ||||
Regulatory Assets | ||||
Remaining Recovery/ Settlement Period (years) | 13 years | |||
Other | ||||
Regulatory Assets | ||||
Regulatory Assets | 74 | CAD 74 | 64 | |
Pensions and other post retirement benefits | ||||
Regulatory Assets | ||||
Regulatory Assets | 382 | 382 | 210 | |
Regulatory Liabilities | ||||
Regulatory Liabilities | 180 | 180 | 0 | |
ANR | Pensions and other post retirement benefits | ||||
Regulatory Liabilities | ||||
Regulatory Liabilities | CAD 141 | CAD 141 | CAD 147 |
GOODWILL (Details)
GOODWILL (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Goodwill | ||
Balance at the beginning of the period | CAD 4,812 | CAD 4,034 |
Asset impairment charges | (1,085) | |
Foreign exchange rate changes | 153 | 778 |
Balance at the end of the period | 13,958 | 4,812 |
U.S. Natural Gas Pipelines | ||
Goodwill | ||
Balance at the beginning of the period | 3,667 | 3,074 |
Asset impairment charges | 0 | |
Foreign exchange rate changes | 213 | 593 |
Balance at the end of the period | 13,958 | 3,667 |
Energy | ||
Goodwill | ||
Balance at the beginning of the period | 1,145 | 960 |
Asset impairment charges | (1,085) | |
Foreign exchange rate changes | (60) | 185 |
Balance at the end of the period | 0 | CAD 1,145 |
Columbian Pipeline | ||
Goodwill | ||
Acquisition of Columbia | 10,078 | |
Columbian Pipeline | U.S. Natural Gas Pipelines | ||
Goodwill | ||
Acquisition of Columbia | 10,078 | |
Columbian Pipeline | Energy | ||
Goodwill | ||
Acquisition of Columbia | CAD 0 |
GOODWILL - Narrative (Details)
GOODWILL - Narrative (Details) CAD in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Sep. 30, 2016CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | Dec. 31, 2014CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Goodwill recorded on Company's acquisitions in the U.S. | |||||||
Asset impairment charges | CAD 1,388 | CAD 3,745 | CAD 0 | ||||
Goodwill (Note 11) | 13,958 | 4,812 | 4,034 | ||||
Goodwill, impairment loss | 1,085 | ||||||
Energy | |||||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||||
Goodwill (Note 11) | 0 | CAD 1,145 | CAD 960 | ||||
Goodwill, impairment loss | CAD 1,085 | ||||||
Great Lakes | |||||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||||
Goodwill (Note 11) | $ | $ 573 | $ 573 | |||||
Percentage of fair value in excess of carrying amount (less than) | 10.00% | 10.00% | |||||
ANR | |||||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||||
Goodwill (Note 11) | $ | $ 1,900 | 1,900 | |||||
Percentage of fair value in excess of carrying amount (less than) | 1000.00% | 1000.00% | |||||
TRANSCANADA PIPELINES LIMITED | Great Lakes | |||||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||||
Goodwill, impairment loss | $ | $ 199 | ||||||
Ownership interest (percent) | 46.45% | 46.45% | |||||
Equity Attributable to Controlling Interests | Great Lakes | |||||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||||
Goodwill (Note 11) | $ | $ 386 | ||||||
Goodwill, period increase | $ | $ 143 | ||||||
Natural Gas – Ravenswood | Energy | |||||||
Goodwill recorded on Company's acquisitions in the U.S. | |||||||
Asset impairment charges | CAD 1,085 | ||||||
Asset impairment charge, after tax | CAD 656 |
INTANGIBLE AND OTHER ASSETS (De
INTANGIBLE AND OTHER ASSETS (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Goodwill and Intangible Assets Disclosure [Abstract] | ||
Capital projects in development | CAD 2,094 | CAD 1,814 |
Deferred income tax assets (Note 16) | 392 | 15 |
Employee post-retirement benefits (Note 23) | 189 | 18 |
Fair value of derivative contracts (Note 24) | 133 | 168 |
PPAs | 0 | 220 |
Prepaid rent1 | 0 | 230 |
Loans and advances | 0 | 159 |
Other | 218 | 478 |
Intangible and other assets | CAD 3,026 | CAD 3,102 |
INTANGIBLE AND OTHER ASSETS - N
INTANGIBLE AND OTHER ASSETS - Narrative (Details) CAD in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2014CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Finite-Lived Intangible Assets [Line Items] | ||||||
Notes receivable | CAD 165 | CAD 165 | CAD 214 | $ 123 | $ 154 | |
Interest rate on notes receivable (percent) | 6.75% | |||||
Current portion of note receivable | 55 | $ 40 | ||||
Asset impairment charges | CAD 1,388 | 3,745 | CAD 0 | |||
Amortization expense | 9 | CAD 52 | CAD 52 | |||
Sundance A (expires 2017) | Energy | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Asset impairment charges | 92 | 211 | ||||
Asset impairment charge, after tax | CAD 68 | CAD 155 |
INTANGIBLE AND OTHER ASSETS - S
INTANGIBLE AND OTHER ASSETS - Schedule of PPA intangible and other assets (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Finite-Lived Intangible Assets [Line Items] | ||
Cost | CAD 0 | CAD 810 |
Accumulated Amortization | 0 | 590 |
Net Book Value | 0 | 220 |
Sheerness (expires 2020) | ||
Finite-Lived Intangible Assets [Line Items] | ||
Cost | 0 | 585 |
Accumulated Amortization | 0 | 390 |
Net Book Value | 0 | 195 |
Sundance A (expires 2017) | ||
Finite-Lived Intangible Assets [Line Items] | ||
Cost | 0 | 225 |
Accumulated Amortization | 0 | 200 |
Net Book Value | CAD 0 | CAD 25 |
NOTES PAYABLE (Details)
NOTES PAYABLE (Details) | 12 Months Ended | ||||
Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2014CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Notes payable | |||||
Outstanding at December 31 | CAD 774,000,000 | CAD 1,218,000,000 | |||
Operated affiliates | |||||
Notes payable | |||||
Amount | 3,500,000,000 | ||||
Unused Capacity | 600,000,000 | 600,000,000 | |||
Notes payable | U.S. dollars | |||||
Notes payable | |||||
Outstanding at December 31 | $ | $ 197,000,000 | $ 376,000,000 | |||
Revolving and demand credit facilities | |||||
Notes payable | |||||
Amount | 11,100,000,000 | 8,900,000,000 | |||
TRANSCANADA PIPELINES LIMITED | Revolving credit facility | Maturing December 2021 | |||||
Notes payable | |||||
Amount | 3,000,000,000 | ||||
Unused Capacity | 3,000,000,000 | ||||
Cost to maintain | 6,000,000 | 6,000,000 | CAD 6,000,000 | ||
TRANSCANADA PIPELINES LIMITED | Revolving credit facility | Maturing December 2017 | |||||
Notes payable | |||||
Amount | $ | 2,000,000,000 | ||||
Unused Capacity | $ | $ 2,000,000,000 | ||||
Cost to maintain | 1,000,000 | ||||
TRANSCANADA PIPELINES LIMITED | Notes payable | |||||
Notes payable | |||||
Outstanding at December 31 | CAD 509,000,000 | CAD 697,000,000 | |||
Weighted Average Interest Rate per Annum at December 31 | 0.90% | 0.80% | 0.90% | 0.80% | |
TCPL USA | Revolving credit facility | Maturing December 2017 | |||||
Notes payable | |||||
Amount | $ | $ 1,000,000,000 | ||||
Unused Capacity | $ | 900,000,000 | ||||
Cost to maintain | CAD 1,000,000 | CAD 3,000,000 | 2,000,000 | ||
Columbia | Revolving credit facility | Maturing December 2017 | |||||
Notes payable | |||||
Amount | 1,000,000,000 | ||||
Unused Capacity | 1,000,000,000 | ||||
Columbia | Revolving credit facility | U.S. dollars | |||||
Notes payable | |||||
Amount | $ | 1,000,000,000 | ||||
TAIL | Revolving credit facility | Maturing December 2017 | |||||
Notes payable | |||||
Amount | $ | 500,000,000 | ||||
Unused Capacity | $ | $ 500,000,000 | ||||
Cost to maintain | 2,000,000 | 2,000,000 | CAD 1,000,000 | ||
TAIL | Notes payable | |||||
Notes payable | |||||
Outstanding at December 31 | CAD 265,000,000 | CAD 521,000,000 | |||
Weighted Average Interest Rate per Annum at December 31 | 0.50% | 1.10% | 0.50% | 1.10% | |
TCPL/TCPL USA | Revolving credit facility | |||||
Notes payable | |||||
Amount | CAD 2,100,000,000 | ||||
Unused Capacity | CAD 700,000,000 |
ACCOUNTS PAYABLE AND OTHER (Det
ACCOUNTS PAYABLE AND OTHER (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Payables and Accruals [Abstract] | ||
Trade payables | CAD 2,443 | CAD 1,506 |
Fair value of derivative contracts (Note 24) | 607 | 926 |
Unredeemed shares of Columbia | 317 | 0 |
Regulatory liabilities (Note 10) | 178 | 44 |
Other | 316 | 177 |
Accounts payable and other | CAD 3,861 | CAD 2,653 |
OTHER LONG-TERM LIABILITIES (De
OTHER LONG-TERM LIABILITIES (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred Costs, Noncurrent [Abstract] | ||
Fair value of derivative contracts (Note 24) | CAD 330 | CAD 625 |
Employee post-retirement benefits (Note 23) | 448 | 380 |
Asset retirement obligations | 108 | 109 |
Guarantees (Note 27) | 82 | 26 |
Other | 215 | 120 |
Other Long-Term Liabilities | CAD 1,183 | CAD 1,260 |
INCOME TAXES - Provision (Detai
INCOME TAXES - Provision (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Current | |||
Canada | CAD 116 | CAD 44 | CAD 103 |
Foreign | 40 | 92 | 42 |
Total | 156 | 136 | 145 |
Deferred | |||
Canada | 101 | 33 | 309 |
Foreign | 95 | (135) | 377 |
Total | 196 | (102) | 686 |
Total Income Tax Expense/(Recovery) | CAD 352 | CAD 34 | CAD 831 |
INCOME TAXES - Geographic Compo
INCOME TAXES - Geographic Components of Income (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Contingency [Line Items] | |||
Canada | CAD 219 | CAD (624) | CAD 1,146 |
Foreign | 618 | (482) | 1,678 |
Income/(Loss) before Income Taxes | CAD 837 | CAD (1,106) | CAD 2,824 |
INCOME TAXES - Reconciliation o
INCOME TAXES - Reconciliation of Expense (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |||
Income/(Loss) before income taxes | CAD 837 | CAD (1,106) | CAD 2,824 |
Federal and provincial statutory tax rate (percent) | 27.00% | 26.00% | 25.00% |
Expected income tax expense/(recovery) | CAD 226 | CAD (288) | CAD 706 |
Income tax differential related to regulated operations | 81 | 159 | 129 |
Foreign tax rate differentials | (196) | 14 | 25 |
Income from equity investments and non-controlling interests | (68) | (56) | (38) |
Asset impairment charges | 242 | 170 | 0 |
Non-deductible amounts | 46 | 0 | 0 |
Tax rate and legislative changes | 34 | ||
Other | 21 | 1 | 9 |
Total Income Tax Expense/(Recovery) | 352 | 34 | CAD 831 |
Foreign tax rate differential related to asset impairments, amount | CAD 112 | CAD 311 |
INCOME TAXES - Deferred Assets
INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | ||
Increase (decrease) to the valuation allowance | CAD 276 | |
Deferred Tax Assets, Net [Abstract] | ||
Tax loss and credit carryforwards | 2,063 | CAD 1,327 |
Difference in accounting and tax bases of impaired assets and assets held for sale | 1,168 | 916 |
Regulatory and other deferred amounts | 277 | 231 |
Unrealized foreign exchange losses on long-term debt | 446 | 589 |
Financial instruments | 34 | 111 |
Other | 352 | 136 |
Deferred tax assets, gross | 4,340 | 3,310 |
Less: Valuation allowance | 1,336 | 1,060 |
Deferred tax assets, net of Valuation allowance | 3,004 | 2,250 |
Deferred Tax Liabilities, Net [Abstract] | ||
Difference in accounting and tax bases of plant, property and equipment and PPAs | 9,015 | 6,441 |
Equity investments | 905 | 656 |
Taxes on future revenue requirement | 198 | 227 |
Other | 156 | 55 |
Deferred tax liabilities, gross | 10,274 | 7,379 |
Net Deferred Income Tax Liabilities | 7,270 | 5,129 |
Deferred Income Tax Assets | ||
Intangible and other assets (Note 12) | 392 | 15 |
Deferred Income Tax Liabilities | ||
Deferred income tax liabilities | CAD 7,662 | CAD 5,144 |
INCOME TAXES - Reconciliation93
INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Unrecognized tax benefit at beginning of year | CAD 17 | CAD 18 | CAD 23 |
Gross increases – tax positions in prior years | 3 | 2 | 3 |
Gross decreases – tax positions in prior years | 0 | (2) | (8) |
Gross increases – tax positions in current year | 2 | 1 | 1 |
Settlement | (1) | 0 | 0 |
Lapse of statutes of limitations | (3) | (2) | (1) |
Unrecognized Tax Benefit at End of Year | CAD 18 | CAD 17 | CAD 18 |
INCOME TAXES - Narrative (Detai
INCOME TAXES - Narrative (Details) | 12 Months Ended | ||||
Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2014CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Net operating loss carryforwards | |||||
Tax loss and credit carryforwards | CAD 2,063,000,000 | CAD 1,327,000,000 | |||
Deferred income tax liabilities on the unremitted earnings of foreign investments | 481,000,000 | 308,000,000 | |||
Income tax payments, net of refunds | 105,000,000 | 162,000,000 | CAD 109,000,000 | ||
Interest expense (reversal) reflected within net tax expense | 0 | (1,000,000) | 1,000,000 | ||
Income tax penalties expense | 0 | 0 | CAD 0 | ||
Accrued interest expense | 4,000,000 | 4,000,000 | |||
Income tax penalties accrued | 0 | 0 | |||
Canada federal and provincial | |||||
Net operating loss carryforwards | |||||
Unused net operating loss carryforwards | 1,786,000,000 | 1,283,000,000 | |||
Capital loss carryforwards | 0 | 0 | |||
Ccapital loss carryforwards unrecognized | 654,000,000 | 75,000,000 | |||
Canada federal and provincial | Alternative minimum tax | |||||
Net operating loss carryforwards | |||||
Minimum tax credits | 68,000,000 | 57,000,000 | |||
U.S. federal | |||||
Net operating loss carryforwards | |||||
Unused net operating loss carryforwards | $ | $ 2,545,000,000 | $ 1,617,000,000 | |||
Tax loss and credit carryforwards | CAD 0 | CAD 0 | |||
Operating loss carryforward unrecognized | $ | 58,000,000 | 0 | |||
U.S. federal | Alternative minimum tax | |||||
Net operating loss carryforwards | |||||
Minimum tax credits | $ | 37,000,000 | 41,000,000 | |||
Mexican Tax Authority | |||||
Net operating loss carryforwards | |||||
Tax loss and credit carryforwards | $ | $ 54,000,000 | $ 70,000,000 |
LONG-TERM DEBT - Schedule of Ac
LONG-TERM DEBT - Schedule of Activity and Summary of Principal Repayments (Details) CAD in Millions, $ in Millions | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) |
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 40,150 | CAD 31,456 | ||
Less: Current portion of Long-term debt | 1,838 | 2,547 | ||
Long-term debt, excluding current maturities | 38,312 | 28,909 | ||
Repayments of Long-term Debt [Abstract] | ||||
2,017 | 1,838 | |||
2,018 | 8,941 | |||
2,019 | 1,742 | |||
2,020 | 2,762 | |||
2,021 | 2,165 | |||
TRANSCANADA PIPELINES LIMITED | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | 29,136 | 26,572 | ||
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Dates Between 2017 and 2020 | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 599 | CAD 599 | ||
Interest Rate | 10.70% | 10.70% | 10.70% | 10.70% |
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Date of 2021 | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 536 | $ 400 | CAD 553 | $ 400 |
Interest Rate | 9.90% | 9.90% | 9.90% | 9.90% |
TRANSCANADA PIPELINES LIMITED | Medium Term Notes | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 5,787 | CAD 5,175 | ||
Interest Rate | 4.60% | 4.60% | 5.30% | 5.30% |
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 19,521 | $ 14,517 | CAD 20,245 | $ 14,641 |
Interest Rate | 5.10% | 5.10% | 4.80% | 4.80% |
TRANSCANADA PIPELINES LIMITED | Bridge Facility | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 2,693 | $ 2,006 | CAD 0 | |
Interest Rate | 1.90% | 1.90% | 0.00% | 0.00% |
NOVA GAS TRANSMISSION LTD. | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 914 | CAD 1,147 | ||
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Dates between 2016 and 2024 | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 100 | CAD 324 | ||
Interest Rate | 9.90% | 9.90% | 11.50% | 11.50% |
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Date of 2023 | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 268 | $ 200 | CAD 276 | $ 200 |
Interest Rate | 7.90% | 7.90% | 7.90% | 7.90% |
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity between 2025 and 2030 | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 503 | CAD 503 | ||
Interest Rate | 7.40% | 7.40% | 7.40% | 7.40% |
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity Date of 2026 | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 43 | $ 33 | CAD 44 | $ 33 |
Interest Rate | 7.50% | 7.50% | 7.50% | 7.50% |
TRANSCANADA PIPELINE USA LTD. | Bridge Facility | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 2,276 | $ 1,695 | CAD 0 | |
Interest Rate | 1.90% | 1.90% | 0.00% | 0.00% |
COLUMBIA PIPELINE GROUP, INC. | Senior Unsecured Notes | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 3,985 | $ 2,968 | CAD 0 | |
Interest Rate | 3.70% | 3.70% | 0.00% | 0.00% |
ANR PIPELINE COMPANY | Senior Unsecured Notes | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 901 | $ 671 | CAD 597 | $ 432 |
Interest Rate | 7.20% | 7.20% | 8.90% | 8.90% |
GAS TRANSMISSION NORTHWEST LLC | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 422 | CAD 450 | ||
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 335 | $ 250 | CAD 346 | $ 250 |
Interest Rate | 5.60% | 5.60% | 5.60% | 5.60% |
GAS TRANSMISSION NORTHWEST LLC | Unsecured Term Loan | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 87 | $ 65 | CAD 104 | $ 75 |
Interest Rate | 1.60% | 1.60% | 1.40% | 1.40% |
TC PIPELINES, LP | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 2,044 | CAD 2,161 | ||
TC PIPELINES, LP | Senior Unsecured Notes | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 932 | $ 694 | CAD 957 | $ 694 |
Interest Rate | 4.70% | 4.70% | 4.70% | 4.70% |
TC PIPELINES, LP | Unsecured Loan Facility | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 213 | $ 158 | CAD 277 | $ 200 |
Interest Rate | 1.90% | 1.90% | 1.60% | 1.60% |
TC PIPELINES, LP | Unsecured Term Loan | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 899 | $ 670 | CAD 927 | $ 670 |
Interest Rate | 1.90% | 1.90% | 1.60% | 1.60% |
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 373 | $ 278 | CAD 411 | $ 297 |
Interest Rate | 7.70% | 7.70% | 7.80% | 7.80% |
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Senior Secured Notes | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 70 | $ 52 | CAD 96 | $ 69 |
Interest Rate | 6.00% | 6.00% | 6.10% | 6.10% |
TUSCARORA GAS TRANSMISSION COMPANY | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 29 | CAD 22 | ||
TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 13 | $ 10 | ||
Interest Rate | 1.90% | 1.90% | 0.00% | 0.00% |
TUSCARORA GAS TRANSMISSION COMPANY | Senior Secured Notes | ||||
Debt Instrument [Line Items] | ||||
Current and Long-Term Debt, Outstanding December 31 | CAD 16 | $ 12 | CAD 22 | $ 16 |
Interest Rate | 4.00% | 4.00% | 4.00% | 4.00% |
LONG-TERM DEBT - Long-Term Debt
LONG-TERM DEBT - Long-Term Debt Issued (Details) CAD in Millions, $ in Millions | Nov. 16, 2016USD ($) | Jun. 30, 2016CAD | Jun. 30, 2016USD ($) | Apr. 30, 2016USD ($) | Jan. 31, 2016USD ($) | Nov. 30, 2015USD ($) | Oct. 31, 2015CAD | Sep. 30, 2015USD ($) | Jul. 31, 2015CAD | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Jan. 31, 2015USD ($) | Feb. 28, 2014USD ($) |
Bridge facility, floating rates | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 6,900 | ||||||||||||
TRANSCANADA PIPELINES LIMITED | Bridge facility, floating rates | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 5,213 | ||||||||||||
TRANSCANADA PIPELINES LIMITED | 3.69% medium term notes, due July 2023 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | CAD | CAD 300 | ||||||||||||
Interest Rate | 3.69% | 3.69% | |||||||||||
Long-term debt, re-issuance yield, percent | 2.69% | 2.69% | |||||||||||
TRANSCANADA PIPELINES LIMITED | 4.350% medium term notes, due June 2046 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | CAD | CAD 700 | ||||||||||||
Interest Rate | 4.35% | 4.35% | |||||||||||
TRANSCANADA PIPELINES LIMITED | 4.875% senior unsecured notes, due January 2026 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 850 | ||||||||||||
Interest Rate | 4.875% | 4.875% | |||||||||||
TRANSCANADA PIPELINES LIMITED | 3.125% senior unsecured notes, due January 2019 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 400 | ||||||||||||
Interest Rate | 3.125% | ||||||||||||
TRANSCANADA PIPELINES LIMITED | 1.625% senior unsecured notes, due November 2017 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 1,000 | ||||||||||||
Interest Rate | 1.625% | ||||||||||||
TRANSCANADA PIPELINES LIMITED | 4.55% medium-term notes, due November 2041 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | CAD | CAD 400 | ||||||||||||
Interest Rate | 4.55% | ||||||||||||
TRANSCANADA PIPELINES LIMITED | 3.30% medium-term notes, due July 2025 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | CAD | CAD 750 | ||||||||||||
Interest Rate | 3.30% | ||||||||||||
TRANSCANADA PIPELINES LIMITED | 4.60% senior unsecured notes, due March 2045 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 750 | ||||||||||||
Interest Rate | 4.60% | ||||||||||||
TRANSCANADA PIPELINES LIMITED | 1.875% senior unsecured notes, due January 2018 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 500 | ||||||||||||
Interest Rate | 1.875% | ||||||||||||
TRANSCANADA PIPELINES LIMITED | Senior unsecured notes, floating rates, due in January 2018 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 250 | ||||||||||||
TRANSCANADA PIPELINES LIMITED | 4.63% senior unsecured notes, due March 2034 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 1,250 | ||||||||||||
Interest Rate | 4.63% | ||||||||||||
ANR | 4.14% senior unsecured notes, due June 2026 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 240 | ||||||||||||
Interest Rate | 4.14% | 4.14% | |||||||||||
TRANSCANADA PIPELINE USA LTD. | Bridge facility, floating rates | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 1,700 | ||||||||||||
TUSCARORA GAS TRANSMISSION COMPANY | Term loan, floating interest rate | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 10 | ||||||||||||
TC PIPELINES, LP | Unsecured term loan, floating rate, due October 2018 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 170 | ||||||||||||
TC PIPELINES, LP | 4.375% senior unsecured notes, due March 2025 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 350 | ||||||||||||
Interest Rate | 4.375% | ||||||||||||
GAS TRANSMISSION NORTHWEST LLC | Unsecured term loan, floating interest rate, due June 2019 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Amount | $ 75 |
LONG-TERM DEBT - Retired (Detai
LONG-TERM DEBT - Retired (Details) CAD in Millions, $ in Millions | 1 Months Ended | |||||||||||
Nov. 30, 2016USD ($) | Oct. 31, 2016CAD | Jun. 30, 2016USD ($) | Feb. 29, 2016CAD | Jan. 31, 2016USD ($) | Aug. 31, 2015CAD | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Jan. 31, 2015USD ($) | Jun. 30, 2014CAD | Feb. 28, 2014CAD | Jan. 31, 2014CAD | |
TRANSCANADA PIPELINES LIMITED | Bridge facility, floating rates | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | $ 3,200 | |||||||||||
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes at 4.65% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | CAD | CAD 400 | |||||||||||
Interest Rate | 4.65% | |||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 7.65% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | $ 84 | |||||||||||
Interest Rate | 7.69% | |||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, Floating Rate | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | $ 500 | |||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Notes 0.75% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | $ 750 | |||||||||||
Interest Rate | 0.75% | |||||||||||
TRANSCANADA PIPELINES LIMITED | Debentures, 11.90% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | CAD | CAD 150 | |||||||||||
Interest Rate | 11.90% | |||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 3.40% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | $ 500 | |||||||||||
Interest Rate | 3.40% | |||||||||||
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 0.875% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | $ 500 | |||||||||||
Interest Rate | 0.875% | |||||||||||
TRANSCANADA PIPELINES LIMITED | 4.875% senior unsecured notes, due January 2026 | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | $ 300 | |||||||||||
Interest Rate | 4.875% | 4.875% | ||||||||||
TRANSCANADA PIPELINES LIMITED | Debentures, 11.10% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | CAD | CAD 125 | |||||||||||
Interest Rate | 11.10% | |||||||||||
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes at 5.05% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | CAD | CAD 300 | |||||||||||
Interest Rate | 5.05% | |||||||||||
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes, 5.65% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | CAD | CAD 450 | |||||||||||
Interest Rate | 5.65% | |||||||||||
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes, 5.09% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | $ 75 | |||||||||||
Interest Rate | 5.09% | |||||||||||
NOVA GAS TRANSMISSION LTD. | Debentures, 12.20% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | CAD | CAD 225 | |||||||||||
Interest Rate | 12.20% | |||||||||||
NOVA GAS TRANSMISSION LTD. | Debentures, 11.20% | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Amount | CAD | CAD 53 | |||||||||||
Interest Rate | 11.20% |
LONG-TERM DEBT - Interest Expe
LONG-TERM DEBT - Interest Expense and Payments (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Interest Expense [Abstract] | |||
Capitalized interest | CAD (176) | CAD (280) | CAD (259) |
Amortization and other financial charges | 211 | 31 | 55 |
Interest expense | 1,998 | 1,370 | 1,198 |
Interest payments on long-term debt and junior subordinated notes, net of interest capitalized on construction projects | 1,721 | 1,266 | 1,123 |
Short-term debt | |||
Interest Expense [Abstract] | |||
Interest on debt | 18 | 16 | 15 |
Total long-term debt (excluding junior subordinated notes) | |||
Interest Expense [Abstract] | |||
Interest on debt | 1,765 | 1,487 | 1,317 |
Junior subordinated notes | |||
Interest Expense [Abstract] | |||
Interest on debt | 180 | CAD 116 | CAD 70 |
Interest Expense | |||
Interest Expense [Abstract] | |||
Dividend equivalent payments recorded as interest expense | CAD 109 |
JUNIOR SUBORDINATED NOTES (Deta
JUNIOR SUBORDINATED NOTES (Details) CAD in Millions | 1 Months Ended | 12 Months Ended | ||||
Aug. 31, 2016USD ($) | May 31, 2015USD ($) | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | |
Debt Instrument [Line Items] | ||||||
Outstanding at December 31 | CAD | CAD 3,931 | CAD 2,409 | ||||
TRANSCANADA PIPELINES LIMITED | ||||||
Debt Instrument [Line Items] | ||||||
Outstanding at December 31 | CAD | CAD 3,931 | 2,409 | ||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes | ||||||
Debt Instrument [Line Items] | ||||||
Outstanding at December 31 | $ 1,000,000,000 | |||||
Stated interest rate | 6.35% | 6.35% | ||||
Redemption price as a percentage of principal amount plus accrued and unpaid interest | 100.00% | |||||
Optional period for which payment of interest can be deferred (in years) | 10 years | |||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes | LIBOR | ||||||
Debt Instrument [Line Items] | ||||||
Basis points (percent) | 2.21% | |||||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067 | ||||||
Debt Instrument [Line Items] | ||||||
Outstanding at December 31 | CAD 1,342 | $ 1,000,000,000 | CAD 1,382 | $ 1,000,000,000 | ||
Effective Interest Rate | 6.40% | 6.40% | 6.40% | 6.40% | ||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2075 | ||||||
Debt Instrument [Line Items] | ||||||
Outstanding at December 31 | CAD 996 | $ 742,000,000 | CAD 1,027 | $ 742,000,000 | ||
Effective Interest Rate | 5.50% | 5.50% | 5.30% | 5.30% | ||
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2076 | ||||||
Debt Instrument [Line Items] | ||||||
Outstanding at December 31 | CAD 1,593 | $ 1,186,000,000 | ||||
Effective Interest Rate | 6.20% | 6.20% | ||||
TRANSCANADA PIPELINES LIMITED | TransCanada Trust loan, due in August 2076 | Junior subordinated notes | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 1,200,000,000 | |||||
Stated interest rate | 6.125% | |||||
Administrative charge (percent) | 0.25% | |||||
Redemption price as a percentage of principal amount plus accrued and unpaid interest | 100.00% | |||||
TRANSCANADA PIPELINES LIMITED | TransCanada Trust loan, due in August 2076 | August 2026 until August 2046 | Junior subordinated notes | LIBOR | ||||||
Debt Instrument [Line Items] | ||||||
Basis points (percent) | 4.89% | |||||
TRANSCANADA PIPELINES LIMITED | TransCanada Trust loan, due in August 2076 | August 2046 to August 2076 | Junior subordinated notes | LIBOR | ||||||
Debt Instrument [Line Items] | ||||||
Basis points (percent) | 5.64% | |||||
TRANSCANADA PIPELINES LIMITED | TransCanada Trust loan, due in May 2075 | Junior subordinated notes | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 750,000,000 | |||||
Stated interest rate | 5.875% | |||||
Administrative charge (percent) | 0.25% | |||||
Redemption price as a percentage of principal amount plus accrued and unpaid interest | 100.00% | |||||
TRANSCANADA PIPELINES LIMITED | TransCanada Trust loan, due in May 2075 | May 2025 until May 2045 | Junior subordinated notes | LIBOR | ||||||
Debt Instrument [Line Items] | ||||||
Basis points (percent) | 3.778% | |||||
TRANSCANADA PIPELINES LIMITED | TransCanada Trust loan, due in May 2075 | May 2045 to May 2075 | Junior subordinated notes | LIBOR | ||||||
Debt Instrument [Line Items] | ||||||
Basis points (percent) | 4.528% | |||||
TransCanada Trust | Trust Notes - Series 2016-A | Notes payable | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 1,200,000,000 | |||||
Stated interest rate, period of time (in years) | 10 years | |||||
TransCanada Trust | Trust Notes - Series 2016-A | First Ten Years | Notes payable | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.875% | |||||
TransCanada Trust | Trust Notes - Series 2015-A | Notes payable | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 750,000,000 | |||||
Stated interest rate | 5.625% | |||||
Stated interest rate, period of time (in years) | 10 years |
NON-CONTROLLING INTERESTS (Deta
NON-CONTROLLING INTERESTS (Details) - CAD CAD in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Non-controlling interest included in the Consolidated Balance Sheet | ||||
Non-controlling interest | CAD 1,726 | CAD 1,717 | ||
Non-controlling interests included in the Consolidated Statement of Income | ||||
Non-controlling interest | 252 | 6 | CAD 153 | |
Noncontrolling Interest | ||||
Non-controlling interest included in the Consolidated Balance Sheet | ||||
Non-controlling interest | 1,726 | 1,717 | 1,583 | CAD 1,611 |
Noncontrolling Interest | TC PipeLines, LP | ||||
Non-controlling interest included in the Consolidated Balance Sheet | ||||
Non-controlling interest | 1,596 | 1,590 | ||
Non-controlling interests included in the Consolidated Statement of Income | ||||
Non-controlling interest | 215 | (13) | 136 | |
Noncontrolling Interest | Non-controlling interest in Columbia Pipeline Partners LP | ||||
Non-controlling interests included in the Consolidated Statement of Income | ||||
Non-controlling interest | 17 | 0 | 0 | |
Noncontrolling Interest | PORTLAND NATURAL GAS TRANSMISSION SYSTEM | ||||
Non-controlling interest included in the Consolidated Balance Sheet | ||||
Non-controlling interest | 130 | 127 | ||
Non-controlling interests included in the Consolidated Statement of Income | ||||
Non-controlling interest | 20 | 19 | 15 | |
Noncontrolling Interest | TRANSCANADA PIPELINES LIMITED | ||||
Non-controlling interests included in the Consolidated Statement of Income | ||||
Preferred shares of TCPL | CAD 0 | CAD 0 | CAD 2 |
NON-CONTROLLING INTERESTS - Nar
NON-CONTROLLING INTERESTS - Narrative (Details) CAD / shares in Units, shares in Millions, CAD in Millions, $ in Millions | Jan. 01, 2016 | Mar. 05, 2014CAD / sharesshares | May 19, 2016shares | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | Dec. 31, 2014CAD | Dec. 31, 2016USD ($) | Jul. 01, 2016 | Dec. 31, 2013 |
Non-controlling interests | ||||||||||
Asset impairment charges | CAD 1,388 | CAD 3,745 | CAD 0 | |||||||
Common units outstanding, subject to rescission, amount | 1,179 | 0 | ||||||||
TC PipeLines, LP | ||||||||||
Non-controlling interests | ||||||||||
Fees received for services provided | 4.5 | CAD 4 | 3 | |||||||
Asset impairment charges | $ | $ 199 | |||||||||
Reclassification to Common Units of CPPL, subject to redemption | shares | 1.6 | |||||||||
Common units outstanding, subject to rescission, amount | CAD 106 | $ 82 | ||||||||
TC PipeLines, LP | Noncontrolling Interest | ||||||||||
Non-controlling interests | ||||||||||
Percentage of non-controlling interests | 73.20% | 72.00% | 73.20% | |||||||
Asset impairment charges | $ | $ 143 | |||||||||
COLUMBIA PIPELINE GROUP, INC. | Noncontrolling Interest | ||||||||||
Non-controlling interests | ||||||||||
Percentage of non-controlling interests | 53.50% | |||||||||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | ||||||||||
Non-controlling interests | ||||||||||
Fees received for services provided | CAD 8 | CAD 11 | CAD 8 | |||||||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Noncontrolling Interest | ||||||||||
Non-controlling interests | ||||||||||
Percentage of non-controlling interests | 38.30% | 38.30% | 38.30% | 38.30% | ||||||
Ownership interest before transaction, percent | 49.90% | |||||||||
Columbia Pipeline Partners LP | ||||||||||
Non-controlling interests | ||||||||||
Common units outstanding, subject to rescission, amount | CAD 1,073 | $ 799 | ||||||||
Series Y Preferred Stock | TRANSCANADA PIPELINES LIMITED | ||||||||||
Non-controlling interests | ||||||||||
Number of shares outstanding (in shares) | shares | 4 | |||||||||
Preferred stock dividend rate, percent | 5.60% | |||||||||
Redemption price per share (in Canadian dollars per share) | CAD / shares | CAD 50 | |||||||||
Accrued and unpaid dividends (in Canadian dollars per share) | CAD / shares | CAD 0.2455 | |||||||||
Maximum | TC PipeLines, LP | Noncontrolling Interest | ||||||||||
Non-controlling interests | ||||||||||
Percentage of non-controlling interests | 72.00% | 71.70% | ||||||||
Minimum | TC PipeLines, LP | Noncontrolling Interest | ||||||||||
Non-controlling interests | ||||||||||
Percentage of non-controlling interests | 71.70% | 71.10% |
COMMON SHARES - Reconciliation
COMMON SHARES - Reconciliation (Details) - CAD CAD in Millions | Nov. 16, 2016 | Jan. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Number of Shares | ||||||
Outstanding at the beginning of the period (in shares) | 703,000,000 | 703,000,000 | ||||
Exercise of options (in shares) | 1,683 | |||||
Repurchase of shares (in shares) | (305,407) | (6,784,738) | ||||
Issued under public offerings (in shares) | 60,200,000 | |||||
Outstanding at the end of the period (in shares) | 703,000,000 | 864,000,000 | 703,000,000 | |||
Amount | ||||||
Outstanding at the beginning of the period | CAD 12,102 | CAD 12,102 | ||||
Repurchase of shares | CAD (14) | CAD (294) | ||||
Outstanding at the end of the period | CAD 12,102 | CAD 20,099 | CAD 12,102 | |||
Weighted Average Common Shares Outstanding | ||||||
Basic (in shares) | 759,000,000 | 709,000,000 | 708,000,000 | |||
Diluted (in shares) | 760,000,000 | 709,000,000 | 710,000,000 | |||
Common Shares | ||||||
Number of Shares | ||||||
Outstanding at the beginning of the period (in shares) | 702,614,000 | 702,614,000 | 708,662,000 | 707,441,000 | ||
Exercise of options (in shares) | 1,683,000 | 737,000 | 1,221,000 | |||
Repurchase of shares (in shares) | (305,000) | (6,785,000) | ||||
Issued under public offerings (in shares) | 156,825,000 | |||||
Dividend reinvestment and share purchase plan (in shares) | 2,942,000 | |||||
Outstanding at the end of the period (in shares) | 702,614,000 | 863,759,000 | 702,614,000 | 708,662,000 | ||
Amount | ||||||
Outstanding at the beginning of the period | CAD 12,102 | CAD 12,102 | CAD 12,202 | CAD 12,149 | ||
Exercise of options | 74 | 30 | 53 | |||
Repurchase of shares | CAD (6) | CAD (130) | (6) | (130) | 0 | |
Gross proceeds from public offering of preferred shares | 7,752 | 0 | 0 | |||
Dividend reinvestment and share purchase plan | 177 | 0 | 0 | |||
Outstanding at the end of the period | CAD 12,102 | CAD 20,099 | CAD 12,102 | CAD 12,202 | ||
Weighted Average Common Shares Outstanding | ||||||
Basic (in shares) | 759,000,000 | 709,000,000 | 708,000,000 | |||
Diluted (in shares) | 760,000,000 | 709,000,000 | 710,000,000 |
COMMON SHARES - Public Offering
COMMON SHARES - Public Offering and Subscription Receipts (Details) CAD / shares in Units, CAD in Millions, $ in Billions | Nov. 16, 2016CADCAD / sharesshares | Nov. 16, 2016USD ($)shares | Apr. 30, 2016shares | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2014CAD | Apr. 01, 2016CADCAD / sharesshares |
Class of Stock [Line Items] | |||||||
Issued under public offerings (in shares) | shares | 60,200,000 | 60,200,000 | |||||
Sale of stock, price per share (in USD per share) | CAD / shares | CAD 58.50 | ||||||
Common shares issued, net of issue costs | CAD | CAD 3,500 | CAD 7,747 | CAD 27 | CAD 47 | |||
Subscription receipt (in shares) | shares | 96,600,000 | ||||||
Share price (in CAD per share) | CAD / shares | CAD 45.75 | ||||||
Common stock, value, subscriptions | CAD | CAD 4,400 | ||||||
Common stock subscriptions, number of common shares issuable per subscription | shares | 1 | ||||||
Bridge facility, floating rates | |||||||
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 | CAD | CAD 109 |
COMMON SHARES - Repurchased (De
COMMON SHARES - Repurchased (Details) - CAD CAD / shares in Units, CAD in Millions | Nov. 19, 2015 | Jan. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
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 | 6,784,738 | ||||
Average price per share of common shares repurchased (in Canadian dollars per share) | CAD 44.90 | CAD 43.29 | ||||
Value recorded for common stock repurchased | CAD 14 | CAD 294 | ||||
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 | 6,785,000 | ||||
Value recorded for common stock repurchased | 6 | 130 | CAD 6 | CAD 130 | CAD 0 | |
Additional Paid-In Capital | ||||||
Class of Stock [Line Items] | ||||||
Value recorded for common stock repurchased | CAD 8 | CAD 164 | CAD 8 | CAD 164 | CAD 0 |
COMMON SHARES - Options (Detail
COMMON SHARES - Options (Details) | 12 Months Ended |
Dec. 31, 2016CAD / sharesshares | |
Number of Options (thousands) | |
Outstanding at the beginning of the period (in shares) | 9,834 |
Granted (in shares) | 2,479 |
Exercised (in shares) | (1,683) |
Outstanding at the end of the period (in shares) | 10,630 |
Options Exercisable (in shares) | 5,957 |
Weighted Average Exercise Prices | |
Outstanding at the beginning of the period (in Canadian dollars per share) | CAD / shares | CAD 46.63 |
Granted (in Canadian dollars per share) | CAD / shares | 48.44 |
Exercised (in Canadian dollars per share) | CAD / shares | 38.92 |
Outstanding at the end of the period (in Canadian dollars per share) | CAD / shares | 48.28 |
Options Exercisable at December 31, 2016 (in Canadian dollars per share) | CAD / shares | CAD 46.09 |
Weighted Average Remaining Contractual Life (years) | |
Options Outstanding (in years) | 4 years 2 months 12 days |
Options Exercisable (in years) | 3 years 1 month 6 days |
Number of shares available for grant | 13,630,114 |
Options expiration term | 7 years |
Vesting rights percentage | 33.30% |
Award vesting period | 3 years |
COMMON SHARES - Dividend Reinve
COMMON SHARES - Dividend Reinvestment and Share Purchase Plan (Details) | 6 Months Ended |
Dec. 31, 2016 | |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |
Stock Issued During Period, Dividend Reinvestment Plan, Shares Issued From Treasury, Discount, Percent | 2.00% |
COMMON SHARES - Stock Options A
COMMON SHARES - Stock Options Assumptions Used (Details) - CAD CAD / shares in Units, CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plan, Assumptions Used in Calculations [Abstract] | |||
Weighted average fair value | CAD 5.67 | CAD 6.45 | CAD 5.54 |
Expected life (years) | 5 years 9 months 9 days | 5 years 9 months | 6 years |
Interest rate | 0.70% | 1.10% | 1.80% |
Volatility | 21.00% | 18.00% | 17.00% |
Dividend yield | 4.90% | 3.70% | 3.80% |
Forfeiture rate | 5.00% | 5.00% | 5.00% |
Expense for stock options | CAD 15 | CAD 13 | CAD 7 |
COMMON SHARES - Summary of Addi
COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD shares in Millions, CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Equity [Abstract] | |||
Total intrinsic value of options exercised | CAD 31 | CAD 10 | CAD 21 |
Fair value of options that have vested | CAD 126 | CAD 91 | CAD 95 |
Total options vested | 2.1 | 2 | 1.7 |
Options, exercisable, intrinsic value | CAD 86 | ||
Options, outstanding, intrinsic value | CAD 130 |
COMMON SHARES - Shareholder Rig
COMMON SHARES - Shareholder Rights Plan (Details) | Dec. 31, 2016shares |
Shareholder Rights Plan | |
Number of rights entitled to each common share | 1 |
Number of common shares entitled to be purchased under each right | 2 |
PREFERRED SHARES (Details)
PREFERRED SHARES (Details) - CAD CAD / shares in Units, CAD in Millions | Nov. 16, 2016 | Dec. 31, 2015 | Nov. 30, 2016 | Apr. 30, 2016 | Feb. 29, 2016 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 |
Preferred Shares [Line Items] | ||||||||
Preferred Shares | CAD 2,499 | CAD 3,980 | ||||||
Number of shares issued | 60,200,000 | |||||||
Series 1 | ||||||||
Preferred Shares [Line Items] | ||||||||
Preferred shares, authorized (in shares) | 9,498,000 | |||||||
Preferred shares, outstanding (in shares) | 9,498,000 | |||||||
Current Yield | 3.266% | |||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | CAD 0.8165 | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 233 | CAD 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, authorized (in shares) | 12,502,000 | |||||||
Preferred shares, outstanding (in shares) | 12,502,000 | |||||||
Current Yield | 2.429% | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 306 | CAD 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, authorized (in shares) | 8,533,000 | |||||||
Preferred shares, outstanding (in shares) | 8,533,000 | |||||||
Current Yield | 2.152% | |||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | CAD 0.538 | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 209 | CAD 209 | ||||||
Number of shares converted | 5,466,595 | |||||||
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, authorized (in shares) | 5,467,000 | |||||||
Preferred shares, outstanding (in shares) | 5,467,000 | |||||||
Current Yield | 1.789% | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 134 | CAD 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, authorized (in shares) | 12,714,000 | |||||||
Preferred shares, outstanding (in shares) | 12,714,000 | |||||||
Current Yield | 2.263% | |||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | CAD 0.56575 | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 342 | CAD 310 | ||||||
Number of shares converted | 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, authorized (in shares) | 1,286,000 | |||||||
Preferred shares, outstanding (in shares) | 1,286,000 | |||||||
Current Yield | 2.073% | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 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, authorized (in shares) | 24,000,000 | |||||||
Preferred shares, outstanding (in shares) | 24,000,000 | |||||||
Current Yield | 4.00% | |||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | CAD 1 | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 589 | CAD 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, authorized (in shares) | 18,000,000 | |||||||
Preferred shares, outstanding (in shares) | 18,000,000 | |||||||
Current Yield | 4.25% | |||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | CAD 1.0625 | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | 442 | CAD 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, authorized (in shares) | 10,000,000 | |||||||
Preferred shares, outstanding (in shares) | 10,000,000 | |||||||
Current Yield | 3.80% | |||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | CAD 0.95 | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 244 | CAD 244 | ||||||
Number of shares issued | 10,000,000 | |||||||
Price per share (in Canadian dollars per share) | CAD 25 | |||||||
Gross proceeds from public offering of preferred shares | CAD 250 | |||||||
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, authorized (in shares) | 20,000,000 | |||||||
Preferred shares, outstanding (in shares) | 20,000,000 | |||||||
Current Yield | 5.50% | |||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | CAD 1.375 | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 493 | |||||||
Number of shares issued | 20,000,000 | |||||||
Price per share (in Canadian dollars per share) | CAD 25 | |||||||
Gross proceeds from public offering of preferred shares | CAD 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 | 550.00% | |||||||
Series 15 | ||||||||
Preferred Shares [Line Items] | ||||||||
Preferred shares, authorized (in shares) | 40,000,000 | |||||||
Preferred shares, outstanding (in shares) | 40,000,000 | |||||||
Current Yield | 4.90% | |||||||
Annual Dividend Rate per Share (in Canadian dollars per share) | CAD 1.3292 | |||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25 | |||||||
Preferred Shares | CAD 988 | |||||||
Number of shares issued | 40,000,000 | |||||||
Price per share (in Canadian dollars per share) | CAD 25 | |||||||
Gross proceeds from public offering of preferred shares | CAD 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 | 490.00% | |||||||
Series 2 and Series 4 | ||||||||
Preferred Shares [Line Items] | ||||||||
Redemption Price Per Share (in Canadian dollars per share) | CAD 25.50 | |||||||
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 |
OTHER COMPREHENSIVE (LOSS)_I111
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components - (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Before Tax Amount | |||
Other Comprehensive Income (Loss) | CAD (29) | CAD 522 | CAD (517) |
Income Tax Recovery/(Expense) | |||
Other Comprehensive Income (Loss) | (3) | 80 | 346 |
Net of Tax Amount | |||
Other comprehensive (loss)/income (Note 22) | (32) | 602 | (171) |
Foreign currency translation gains on net investment in foreign operations | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | 3 | 798 | 462 |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 0 | 15 | 55 |
Net of Tax Amount | |||
Other comprehensive income (loss), before reclassifications | 3 | 813 | 517 |
Other comprehensive income (loss), before reclassifications | 3 | 798 | 462 |
Change in fair value of net investment hedges | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (14) | (505) | (373) |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 4 | 133 | 97 |
Net of Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (10) | (372) | (276) |
Other comprehensive income (loss), before reclassifications | (14) | (505) | (373) |
Cash flow hedge | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | 44 | (92) | (118) |
Reclassification from accumulated other comprehensive Income | 71 | 144 | (95) |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | (14) | 35 | 49 |
Reclassification from AOCI | (29) | (56) | 40 |
Net of Tax Amount | |||
Other comprehensive income (loss), before reclassifications | 30 | (57) | (69) |
Reclassification from accumulated other comprehensive income | 42 | 88 | (55) |
Other comprehensive income (loss), before reclassifications | 44 | (92) | (118) |
Pension and other post-retirement benefits | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (38) | 74 | (146) |
Reclassification from accumulated other comprehensive Income | 22 | 41 | 25 |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 12 | (23) | 44 |
Reclassification from AOCI | (6) | (9) | (7) |
Net of Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (26) | 51 | (102) |
Reclassification from accumulated other comprehensive income | 16 | 32 | 18 |
Other comprehensive income (loss), before reclassifications | (38) | 74 | (146) |
Other comprehensive loss on equity investments | |||
Before Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (117) | 62 | (272) |
Income Tax Recovery/(Expense) | |||
Other comprehensive income (loss) before reclassifications | 30 | (15) | 68 |
Net of Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (87) | 47 | (204) |
Other comprehensive income (loss), before reclassifications | (117) | 62 | (272) |
Accumulated Other Comprehensive Loss | |||
Net of Tax Amount | |||
Other comprehensive income (loss), before reclassifications | (93) | 162 | (266) |
Reclassification from accumulated other comprehensive income | 72 | 134 | (35) |
Other comprehensive (loss)/income (Note 22) | CAD (21) | CAD 296 | CAD (301) |
OTHER COMPREHENSIVE (LOSS)_I112
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at the beginning of the period | CAD 18,155,000,000 | CAD 20,653,000,000 | |
Net current period other comprehensive income/(loss) | (32,000,000) | 602,000,000 | CAD (171,000,000) |
Balance at the end of the period | 25,983,000,000 | 18,155,000,000 | 20,653,000,000 |
Cash flow hedge reported in AOCI and expected to be reclassified to Net income in the next 12 months, net of tax | 5,000,000 | ||
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months, Net Of Tax | 3,000,000 | ||
Currency Translation Adjustments | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at the beginning of the period | (383,000,000) | (518,000,000) | (629,000,000) |
Other comprehensive income (loss), before reclassifications | 7,000,000 | 135,000,000 | 111,000,000 |
Amounts reclassified from accumulated other comprehensive loss | 0 | 0 | 0 |
Net current period other comprehensive income/(loss) | 7,000,000 | 135,000,000 | 111,000,000 |
Balance at the end of the period | (376,000,000) | (383,000,000) | (518,000,000) |
Cash Flow Hedges | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at the beginning of the period | (97,000,000) | (128,000,000) | (4,000,000) |
Other comprehensive income (loss), before reclassifications | 27,000,000 | (57,000,000) | (69,000,000) |
Amounts reclassified from accumulated other comprehensive loss | 42,000,000 | 88,000,000 | (55,000,000) |
Net current period other comprehensive income/(loss) | 69,000,000 | 31,000,000 | (124,000,000) |
Balance at the end of the period | (28,000,000) | (97,000,000) | (128,000,000) |
Pension and Other Post-Retirement Benefit Plan Adjustments | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at the beginning of the period | (198,000,000) | (281,000,000) | (197,000,000) |
Other comprehensive income (loss), before reclassifications | (26,000,000) | 51,000,000 | (102,000,000) |
Amounts reclassified from accumulated other comprehensive loss | 16,000,000 | 32,000,000 | 18,000,000 |
Net current period other comprehensive income/(loss) | (10,000,000) | 83,000,000 | (84,000,000) |
Balance at the end of the period | (208,000,000) | (198,000,000) | (281,000,000) |
Equity Investments | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at the beginning of the period | (261,000,000) | (308,000,000) | (104,000,000) |
Other comprehensive income (loss), before reclassifications | (101,000,000) | 33,000,000 | (206,000,000) |
Amounts reclassified from accumulated other comprehensive loss | 14,000,000 | 14,000,000 | 2,000,000 |
Net current period other comprehensive income/(loss) | (87,000,000) | 47,000,000 | (204,000,000) |
Balance at the end of the period | (348,000,000) | (261,000,000) | (308,000,000) |
Accumulated Other Comprehensive Loss | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Balance at the beginning of the period | (939,000,000) | (1,235,000,000) | (934,000,000) |
Other comprehensive income (loss), before reclassifications | (93,000,000) | 162,000,000 | (266,000,000) |
Amounts reclassified from accumulated other comprehensive loss | 72,000,000 | 134,000,000 | (35,000,000) |
Net current period other comprehensive income/(loss) | (21,000,000) | 296,000,000 | (301,000,000) |
Balance at the end of the period | (960,000,000) | (939,000,000) | (1,235,000,000) |
Accumulated net gain (loss) from cash flow hedges attributable to noncontrolling interest | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Other comprehensive income (loss), before reclassifications | 3,000,000 | 0 | 0 |
Accumulated foreign currency adjustment attributable to noncontrolling interest | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Other comprehensive income (loss), before reclassifications | CAD (14,000,000) | CAD (306,000,000) | CAD (130,000,000) |
OTHER COMPREHENSIVE (LOSS)_I113
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Interest expense | CAD 1,476 | CAD 1,207 | CAD 1,107 |
Income tax expense/(recovery) | (352) | (34) | (831) |
Net Income/(Loss) Attributable to Common Shares | 124 | (1,240) | 1,743 |
Cash Flow Hedges | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Net of tax | (42) | (88) | 55 |
Pension and Other Post-Retirement Benefit Plan Adjustments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Plant operating costs and other | (22) | (41) | (25) |
Income tax expense | 6 | 9 | 7 |
Net of tax | (16) | (32) | (18) |
Equity Investments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Net of tax | (14) | (14) | (2) |
Other comprehensive income on equity investments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Net Income/(Loss) Attributable to Common Shares | (14) | (14) | (2) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash Flow Hedges | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Income/(Loss) before Income Taxes | (71) | (144) | 95 |
Income tax expense/(recovery) | 29 | 56 | (40) |
Net Income/(Loss) Attributable to Common Shares | (42) | (88) | 55 |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash Flow Hedges | Commodities | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Revenues (Energy) | (57) | (128) | 111 |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash Flow Hedges | Interest | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Interest expense | (14) | (16) | (16) |
Amounts Reclassified From Accumulated Other Comprehensive Loss | Other comprehensive income on equity investments | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Income tax expense/(recovery) | 5 | 5 | 0 |
Income from equity investments | CAD (19) | CAD (19) | CAD (2) |
EMPLOYEE POST-RETIREMENT BEN114
EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments and Changes (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Employee post-retirement benefits | |||
Expected average remaining life expectancy of former employees over which past service costs are amortized (in years) | 12 years | 12 years | 12 years |
Expense for savings plan and DC Plans | CAD 52 | CAD 41 | CAD 37 |
Cash Payments for Employee Post-Retirement Benefits [Abstract] | |||
Savings and DC Plans | 52 | 41 | 37 |
Total cash contributions | 171 | 143 | CAD 116 |
Change in Plan Assets | |||
Plan assets at fair value – beginning of year | 2,636 | ||
Plan assets at fair value – end of year | 3,562 | 2,636 | |
Amounts recognized in the Balance Sheet | |||
Intangible and other assets (Note 12) | 189 | 18 | |
Other long-term liabilities (Note 15) | CAD (448) | CAD (380) | |
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 |
Cash Payments for Employee Post-Retirement Benefits [Abstract] | |||
DB Plans and Other post-retirement benefit plans | CAD 111 | CAD 96 | CAD 73 |
Change in Benefit Obligation | |||
Benefit obligation – beginning of year | 2,780 | 2,658 | |
Service cost | 107 | 108 | 85 |
Interest cost | 127 | 115 | 113 |
Employee contributions | 4 | 4 | |
Benefits paid | (204) | (129) | |
Actuarial loss/(gain) | 111 | (57) | |
Acquisition of Columbia | 527 | 0 | |
Settlement loss | 2 | 0 | |
Foreign exchange rate changes | 2 | 81 | |
Benefit obligation – end of year | 3,456 | 2,780 | 2,658 |
Change in Plan Assets | |||
Plan assets at fair value – beginning of year | 2,591 | 2,398 | |
Actual return on plan assets | 227 | 160 | |
Employer contributions | 111 | 96 | 73 |
Employee contributions | 4 | 4 | |
Benefits paid | (204) | (129) | |
Acquisition of Columbia | 475 | 0 | |
Foreign exchange rate changes | 4 | 62 | |
Plan assets at fair value – end of year | 3,208 | 2,591 | 2,398 |
Funded Status – Plan Deficit | (248) | (189) | |
Amounts recognized in the Balance Sheet | |||
Other long-term liabilities (Note 15) | (248) | (189) | |
Net | (248) | (189) | |
Pension Benefit Plans | Canada | |||
Employee post-retirement benefits | |||
Letter of credit to the DB Plan | 20 | 33 | 47 |
Total amount outstanding under letters of credit | 233 | 214 | |
Other Post-Retirement Benefit Plans | |||
Cash Payments for Employee Post-Retirement Benefits [Abstract] | |||
DB Plans and Other post-retirement benefit plans | 8 | 6 | 6 |
Change in Benefit Obligation | |||
Benefit obligation – beginning of year | 225 | 216 | |
Service cost | 3 | 3 | 2 |
Interest cost | 13 | 10 | 10 |
Employee contributions | 2 | 0 | |
Benefits paid | (16) | (7) | |
Actuarial loss/(gain) | (8) | (11) | |
Acquisition of Columbia | 151 | 0 | |
Settlement loss | 0 | 0 | |
Foreign exchange rate changes | 2 | 14 | |
Benefit obligation – end of year | 372 | 225 | 216 |
Change in Plan Assets | |||
Plan assets at fair value – beginning of year | 45 | 39 | |
Actual return on plan assets | 14 | (1) | |
Employer contributions | 8 | 6 | 6 |
Employee contributions | 2 | 0 | |
Benefits paid | (16) | (7) | |
Acquisition of Columbia | 294 | 0 | |
Foreign exchange rate changes | 7 | 8 | |
Plan assets at fair value – end of year | 354 | 45 | CAD 39 |
Funded Status – Plan Deficit | (18) | (180) | |
Amounts recognized in the Balance Sheet | |||
Intangible and other assets (Note 12) | 189 | 18 | |
Accounts payable and other | (7) | (7) | |
Other long-term liabilities (Note 15) | (200) | (191) | |
Net | CAD (18) | CAD (180) |
EMPLOYEE POST-RETIREMENT BEN115
EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Funded status based on accumulated benefit obligation | |||
Plan assets at fair value | CAD 3,562 | CAD 2,636 | |
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 100.00% | 100.00% | |
Pension Benefit Plans | |||
Benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Projected benefit obligation | CAD (3,456) | CAD (2,780) | |
Plan assets at fair value | 3,208 | 2,591 | |
Funded Status – Plan Deficit | (248) | (189) | |
Funded status based on accumulated benefit obligation | |||
Accumulated benefit obligation | (3,202) | (2,600) | |
Plan assets at fair value | 3,208 | 2,591 | CAD 2,398 |
Funded Status – Plan Surplus/(Deficit) | 6 | (9) | |
Accumulated benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Accumulated benefit obligation | (990) | (807) | |
Plan assets at fair value | 868 | 680 | |
Funded Status – Plan Deficit | CAD (122) | CAD (127) | |
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 | 31.00% | 34.00% | |
Amount of debt or common shares included in plan assets | CAD 9 | CAD 2 | |
Percentage of Plan Assets | 0.20% | 0.10% | |
Pension Benefit Plans | Debt securities | Minimum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 25.00% | ||
Pension Benefit Plans | Debt securities | Maximum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 40.00% | ||
Pension Benefit Plans | Equity securities | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 63.00% | 66.00% | |
Amount of debt or common shares included in plan assets | CAD 4 | CAD 4 | |
Percentage of Plan Assets | 0.10% | 0.10% | |
Pension Benefit Plans | Equity securities | Minimum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 45.00% | ||
Pension Benefit Plans | Equity securities | Maximum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 75.00% | ||
Pension Benefit Plans | Alternatives | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Percentage of Plan Assets | 6.00% | 0.00% | |
Pension Benefit Plans | Alternatives | Minimum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 5.00% | ||
Pension Benefit Plans | Alternatives | Maximum | |||
Pension plans' weighted average asset allocations and target allocations by asset category | |||
Target Allocations | 15.00% | ||
Other Post-Retirement Benefit Plans | |||
Benefit obligation and fair value of plan assets for plans that are not fully funded | |||
Projected benefit obligation | CAD (207) | CAD (198) | |
Plan assets at fair value | 0 | 0 | |
Funded Status – Plan Deficit | (207) | (198) | |
Funded status based on accumulated benefit obligation | |||
Plan assets at fair value | CAD 354 | CAD 45 | CAD 39 |
EMPLOYEE POST-RETIREMENT BEN116
EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 3,562 | CAD 2,636 | |
Percentage of Total Portfolio | 100.00% | 100.00% | |
Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 1,089 | CAD 1,118 | |
Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 2,274 | 1,504 | |
Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 199 | 14 | CAD 13 |
Cash and Cash Equivalents | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 34 | CAD 46 | |
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 | CAD 22 | CAD 44 | |
Cash and Cash Equivalents | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 12 | 2 | |
Equity securities | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 531 | CAD 464 | |
Percentage of Total Portfolio | 15.00% | 17.00% | |
Equity securities | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 980 | CAD 629 | |
Percentage of Total Portfolio | 27.00% | 24.00% | |
Equity securities | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 366 | CAD 338 | |
Percentage of Total Portfolio | 10.00% | 13.00% | |
Equity securities | Global | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 235 | CAD 154 | |
Percentage of Total Portfolio | 7.00% | 6.00% | |
Equity securities | Emerging | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 144 | CAD 150 | |
Percentage of Total Portfolio | 4.00% | 6.00% | |
Equity securities | Quoted Prices in Active Markets (Level I) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 388 | CAD 317 | |
Equity securities | Quoted Prices in Active Markets (Level I) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 504 | 589 | |
Equity securities | Quoted Prices in Active Markets (Level I) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 39 | 38 | |
Equity securities | Quoted Prices in Active Markets (Level I) | Global | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Equity securities | Quoted Prices in Active Markets (Level I) | Emerging | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 7 | 7 | |
Equity securities | Significant Other Observable Inputs (Level II) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 143 | 147 | |
Equity securities | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 476 | 40 | |
Equity securities | Significant Other Observable Inputs (Level II) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 327 | 300 | |
Equity securities | Significant Other Observable Inputs (Level II) | Global | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 235 | 154 | |
Equity securities | Significant Other Observable Inputs (Level II) | Emerging | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 137 | 143 | |
Federal | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 192 | CAD 206 | |
Percentage of Total Portfolio | 5.00% | 8.00% | |
Federal | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 82 | ||
Percentage of Total Portfolio | 2.00% | 0.00% | |
Federal | Quoted Prices in Active Markets (Level I) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Federal | Significant Other Observable Inputs (Level II) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 192 | 206 | |
Federal | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 82 | ||
Provincial | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 179 | CAD 202 | |
Percentage of Total Portfolio | 5.00% | 8.00% | |
Provincial | Quoted Prices in Active Markets (Level I) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Provincial | Significant Other Observable Inputs (Level II) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 179 | 202 | |
Municipal | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 8 | CAD 7 | |
Percentage of Total Portfolio | 0.00% | 0.00% | |
Municipal | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 39 | ||
Percentage of Total Portfolio | 1.00% | 0.00% | |
Municipal | Quoted Prices in Active Markets (Level I) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Municipal | Significant Other Observable Inputs (Level II) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 8 | 7 | |
Municipal | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 39 | ||
Corporate | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 126 | CAD 113 | |
Percentage of Total Portfolio | 4.00% | 4.00% | |
Corporate | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 188 | CAD 57 | |
Percentage of Total Portfolio | 5.00% | 2.00% | |
Corporate | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 21 | CAD 25 | |
Percentage of Total Portfolio | 1.00% | 1.00% | |
Corporate | Quoted Prices in Active Markets (Level I) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Corporate | Significant Other Observable Inputs (Level II) | Canada | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 126 | 113 | |
Corporate | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 188 | 57 | |
Corporate | Significant Other Observable Inputs (Level II) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 21 | CAD 25 | |
Government | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 6 | ||
Percentage of Total Portfolio | 0.00% | 0.00% | |
Government | Significant Other Observable Inputs (Level II) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 6 | ||
State | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 41 | CAD 50 | |
Percentage of Total Portfolio | 1.00% | 2.00% | |
State | Significant Other Observable Inputs (Level II) | U.S. | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 41 | CAD 50 | |
Mortgage backed | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 62 | CAD 58 | |
Percentage of Total Portfolio | 2.00% | 2.00% | |
Mortgage backed | Significant Other Observable Inputs (Level II) | International | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 62 | CAD 58 | |
Real Estate | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 133 | ||
Percentage of Total Portfolio | 4.00% | 0.00% | |
Real Estate | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Real Estate | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | CAD 0 | |
Real Estate | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 133 | ||
Infrastructure | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 58 | ||
Percentage of Total Portfolio | 2.00% | 0.00% | |
Infrastructure | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Infrastructure | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Infrastructure | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 58 | ||
Private equity funds | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 8 | CAD 14 | |
Percentage of Total Portfolio | 0.00% | 0.00% | |
Private equity funds | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 | |
Private equity funds | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 0 | 0 | |
Private equity funds | Significant Unobservable Inputs (Level III) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | 8 | 14 | |
Funds held on deposit | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 129 | CAD 123 | |
Percentage of Total Portfolio | 4.00% | 5.00% | |
Funds held on deposit | Quoted Prices in Active Markets (Level I) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 129 | CAD 123 | |
Funds held on deposit | Significant Other Observable Inputs (Level II) | |||
Employee post-retirement benefits | |||
Fair value of plan assets | CAD 0 | CAD 0 |
EMPLOYEE POST-RETIREMENT BEN117
EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Net change in the Level III fair value category | ||
Plan assets at fair value – beginning of year | CAD 2,636 | |
Plan assets at fair value – end of year | 3,562 | CAD 2,636 |
Significant Unobservable Inputs (Level III) | ||
Net change in the Level III fair value category | ||
Plan assets at fair value – beginning of year | 14 | 13 |
Purchases and sales | 183 | (1) |
Realized and unrealized gains | 2 | 2 |
Plan assets at fair value – end of year | 199 | 14 |
Private Equity Funds | ||
Net change in the Level III fair value category | ||
Plan assets at fair value – beginning of year | 14 | |
Plan assets at fair value – end of year | 8 | 14 |
Private Equity Funds | Significant Unobservable Inputs (Level III) | ||
Net change in the Level III fair value category | ||
Plan assets at fair value – beginning of year | 14 | |
Plan assets at fair value – end of year | CAD 8 | CAD 14 |
EMPLOYEE POST-RETIREMENT BEN118
EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Other post-retirement benefit plans, Savings Plan and DC Plans | |||
Company's expected funding contributions for savings plan and DC Plans | CAD 51 | ||
Health care benefits | |||
Assumed average annual rate of increase in the per capita cost of covered health care benefits | 8.00% | ||
Percentage level to which average annual rate was assumed to decrease | 5.00% | ||
Effects of a one per cent change in assumed health care cost trend rates | |||
Effect on total of service and interest cost components, Increase | CAD 1 | ||
Effect on total of service and interest cost components, Decrease | (1) | ||
Effect on post-retirement benefit obligation, Increase | 15 | ||
Effect on post-retirement benefit obligation, Decrease | (13) | ||
Pension Benefit Plans | |||
DB Plans | |||
Company's expected funding contributions | 100 | ||
Estimated future benefit payments, which reflect expected future service | |||
2,017 | 178 | ||
2,018 | 183 | ||
2,019 | 189 | ||
2,020 | 196 | ||
2,021 | 200 | ||
2022 to 2026 | CAD 1,067 | ||
Weighted average actuarial assumptions adopted in measuring the benefit obligations | |||
Discount rate | 4.00% | 4.20% | |
Rate of compensation increase | 1.20% | 0.50% | |
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs | |||
Discount rate | 4.20% | 4.15% | 4.95% |
Expected long-term rate of return on plan assets | 6.70% | 6.95% | 6.90% |
Rate of compensation increase | 0.80% | 3.15% | 3.15% |
Net benefit cost | |||
Service cost | CAD 107 | CAD 108 | CAD 85 |
Interest cost | 127 | 115 | 113 |
Expected return on plan assets | (175) | (155) | (139) |
Amortization of actuarial loss | 20 | 35 | 21 |
Amortization of past service cost | 0 | 2 | 2 |
Amortization of regulatory asset | 27 | 23 | 18 |
Amortization of transitional obligation related to regulated business | 0 | 0 | 0 |
Net Benefit Cost Recognized | 106 | 128 | 100 |
Pre-tax amounts recognized in AOCI | |||
Net loss | 268 | 247 | 348 |
Prior service cost | 0 | 0 | 2 |
Total pre-tax amounts recognized in AOCI | 268 | 247 | 350 |
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year | |||
Estimated net loss that will be amortized | 20 | ||
Pre-tax amounts recognized in OCI | |||
Amortization of net loss from AOCI to OCI | (20) | (34) | (21) |
Amortization of prior service costs from AOCI to OCI | 0 | (2) | (2) |
Funded status adjustment | 43 | (67) | 137 |
Total pre-tax amounts recognized in OCI | 23 | (103) | CAD 114 |
Pension Benefit Plans | Canada | |||
Other post-retirement benefit plans, Savings Plan and DC Plans | |||
Expected estimated additional letter of credit | 233 | CAD 214 | |
Pension Benefit Plans | Canada | Scenario, Plan | |||
Other post-retirement benefit plans, Savings Plan and DC Plans | |||
Expected estimated additional letter of credit | 20 | ||
Other Post-Retirement Benefit Plans | |||
DB Plans | |||
Company's expected funding contributions | 7 | ||
Estimated future benefit payments, which reflect expected future service | |||
2,017 | 19 | ||
2,018 | 19 | ||
2,019 | 20 | ||
2,020 | 20 | ||
2,021 | 20 | ||
2022 to 2026 | CAD 97 | ||
Weighted average actuarial assumptions adopted in measuring the benefit obligations | |||
Discount rate | 4.15% | 4.40% | |
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs | |||
Discount rate | 4.30% | 4.20% | 5.00% |
Expected long-term rate of return on plan assets | 5.95% | 4.60% | 4.60% |
Net benefit cost | |||
Service cost | CAD 3 | CAD 3 | CAD 2 |
Interest cost | 13 | 10 | 10 |
Expected return on plan assets | (11) | (2) | (2) |
Amortization of actuarial loss | 2 | 3 | 2 |
Amortization of past service cost | 0 | 1 | 0 |
Amortization of regulatory asset | 1 | 1 | 1 |
Amortization of transitional obligation related to regulated business | 2 | 2 | 2 |
Net Benefit Cost Recognized | 10 | 18 | 15 |
Pre-tax amounts recognized in AOCI | |||
Net loss | 23 | 28 | 39 |
Prior service cost | 0 | 0 | 1 |
Total pre-tax amounts recognized in AOCI | 23 | 28 | 40 |
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 OCI | (2) | (4) | (2) |
Amortization of prior service costs from AOCI to OCI | 0 | (1) | 0 |
Funded status adjustment | (5) | (7) | 9 |
Total pre-tax amounts recognized in OCI | CAD (7) | CAD (12) | CAD 7 |
RISK MANAGEMENT AND FINANCIA119
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge CAD in Millions, $ in Millions | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) |
Derivative [Line Items] | ||||
Debt carrying value | CAD | CAD 26,600 | CAD 23,100 | ||
Debt fair value | CAD | CAD 29,400 | CAD 23,800 | ||
US$ denominated | ||||
Derivative [Line Items] | ||||
Debt carrying value | $ | $ 19,800 | $ 16,700 | ||
Debt fair value | $ | $ 21,900 | $ 17,200 |
RISK MANAGEMENT AND FINANCIA120
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) - Designated as a net investment hedge CAD in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Derivative [Line Items] | ||||
Fair value | CAD (432) | CAD (680) | ||
US$ denominated | ||||
Derivative [Line Items] | ||||
Notional or Principal Amount | $ | $ 2,500 | $ 4,950 | ||
Cross-currency interest rate swaps | ||||
Derivative [Line Items] | ||||
Fair value | (425) | (730) | ||
Cross-currency interest rate swaps | US$ denominated | ||||
Derivative [Line Items] | ||||
Notional or Principal Amount | $ | 2,350 | 3,150 | ||
Net realized gains related to the interest component | 6 | 8 | ||
Forward foreign exchange contracts | ||||
Derivative [Line Items] | ||||
Fair value | CAD (7) | CAD 50 | ||
Forward foreign exchange contracts | US$ denominated | ||||
Derivative [Line Items] | ||||
Notional or Principal Amount | $ | $ 150 | $ 1,800 |
RISK MANAGEMENT AND FINANCIA121
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) CAD in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | |
Concentration Risk [Line Items] | ||||
Financing receivable, recorded investment, past due | CAD 0 | |||
Provision for other credit losses | 0 | |||
Customer Concentration Risk | ||||
Concentration Risk [Line Items] | ||||
Credit risk concentration | CAD 200 | $ 149 | CAD 248 | $ 179 |
RISK MANAGEMENT AND FINANCIA122
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) CAD in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Carrying and fair values of non-derivative financial instruments | ||||
Current and Long-term debt | CAD (40,150) | CAD (31,456) | ||
Junior subordinated notes (Note 18) | (3,931) | (2,409) | ||
Long-term debt | $ | $ 850 | $ 850 | ||
Interest rate swap agreements | ||||
Carrying and fair values of non-derivative financial instruments | ||||
Fair value adjustments - gains (losses) | 2 | 2 | ||
Long-term debt hedged | $ | $ 850 | $ 850 | ||
Level II | Carrying Amount | ||||
Carrying and fair values of non-derivative financial instruments | ||||
Notes receivable | 165 | 214 | ||
Current and Long-term debt | (40,150) | (31,456) | ||
Junior subordinated notes (Note 18) | (3,931) | (2,409) | ||
Total liabilities | (43,916) | (33,651) | ||
Level II | Fair Value | ||||
Carrying and fair values of non-derivative financial instruments | ||||
Notes receivable | 211 | 265 | ||
Current and Long-term debt | (45,047) | (34,309) | ||
Junior subordinated notes (Note 18) | (3,825) | (2,011) | ||
Total liabilities | CAD (48,661) | CAD (36,055) |
RISK MANAGEMENT AND FINANCIA123
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) CAD in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016CADGWhBcfMMBbls | Dec. 31, 2015CADGWhBcf | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | CAD 509 | CAD 610 | ||
Gross Derivative Instruments Presented on the Balance Sheet | (937) | (1,551) | ||
Total trading activity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 480 | 456 | ||
Gross Derivative Instruments Presented on the Balance Sheet | (486) | (630) | ||
Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 12 | 57 | ||
Gross Derivative Instruments Presented on the Balance Sheet | (1) | (145) | ||
Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 1 | 3 | ||
Gross Derivative Instruments Presented on the Balance Sheet | (2) | (2) | ||
Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 16 | 94 | ||
Gross Derivative Instruments Presented on the Balance Sheet | (448) | (774) | ||
Commodities | Power | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 479 | 509 | ||
Gross Derivative Instruments Presented on the Balance Sheet | CAD (448) | CAD (717) | ||
Commodities | Power | Not designated as hedging instrument | Purchases | ||||
Derivatives, Fair Value [Line Items] | ||||
Power (in GWH) | GWh | 86,887 | 70,331 | ||
Commodities | Power | Not designated as hedging instrument | Sales | ||||
Derivatives, Fair Value [Line Items] | ||||
Power (in GWH) | GWh | 58,561 | 54,382 | ||
Commodities | Natural Gas | Not designated as hedging instrument | Purchases | ||||
Derivatives, Fair Value [Line Items] | ||||
Natural gas (in BCF) | Bcf | 182 | 133 | ||
Commodities | Natural Gas | Not designated as hedging instrument | Sales | ||||
Derivatives, Fair Value [Line Items] | ||||
Natural gas (in BCF) | Bcf | 147 | 70 | ||
Commodities | Liquids | Not designated as hedging instrument | Purchases | ||||
Derivatives, Fair Value [Line Items] | ||||
Natural gas (in BCF) | MMBbls | 6 | |||
Commodities | Liquids | Not designated as hedging instrument | Sales | ||||
Derivatives, Fair Value [Line Items] | ||||
Natural gas (in BCF) | MMBbls | 6 | |||
Foreign exchange | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | CAD 26 | CAD 96 | ||
Gross Derivative Instruments Presented on the Balance Sheet | (486) | (828) | ||
Notional or Principal Amount | $ | $ 2,394 | $ 1,476 | ||
Interest rate | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 4 | 5 | ||
Gross Derivative Instruments Presented on the Balance Sheet | (3) | (6) | ||
Notional or Principal Amount | $ | $ 1,550 | $ 1,100 | ||
Other current assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 376 | 442 | ||
Other current assets | Total trading activity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 362 | 330 | ||
Other current assets | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 7 | 46 | ||
Other current assets | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 1 | 1 | ||
Other current assets | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 6 | 65 | ||
Other current assets | Commodities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 357 | 372 | ||
Other current assets | Commodities | Commodities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 351 | 326 | ||
Other current assets | Commodities | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 6 | 46 | ||
Other current assets | Foreign exchange | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 16 | 67 | ||
Other current assets | Foreign exchange | Foreign exchange | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 10 | 2 | ||
Other current assets | Foreign exchange | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 6 | 65 | ||
Other current assets | Interest rate | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 3 | 3 | ||
Other current assets | Interest rate | Interest rate | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 1 | 2 | ||
Other current assets | Interest rate | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 1 | |||
Other current assets | Interest rate | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 1 | 1 | ||
Intangible and other assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 133 | 168 | ||
Intangible and other assets | Total trading activity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 118 | 126 | ||
Intangible and other assets | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 5 | 11 | ||
Intangible and other assets | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 2 | |||
Intangible and other assets | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 10 | 29 | ||
Intangible and other assets | Commodities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 122 | 137 | ||
Intangible and other assets | Commodities | Commodities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 118 | 126 | ||
Intangible and other assets | Commodities | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 4 | 11 | ||
Intangible and other assets | Commodities | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 0 | |||
Intangible and other assets | Commodities | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 0 | |||
Intangible and other assets | Foreign exchange | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 10 | 29 | ||
Intangible and other assets | Foreign exchange | Foreign exchange | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 0 | |||
Intangible and other assets | Foreign exchange | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 0 | |||
Intangible and other assets | Foreign exchange | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 0 | |||
Intangible and other assets | Foreign exchange | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 10 | 29 | ||
Intangible and other assets | Interest rate | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 1 | 2 | ||
Intangible and other assets | Interest rate | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 1 | |||
Intangible and other assets | Interest rate | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 2 | |||
Intangible and other assets | Interest rate | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Instrument Assets: | 0 | |||
Accounts payable and other | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (607) | (926) | ||
Accounts payable and other | Total trading activity | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (368) | (499) | ||
Accounts payable and other | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (1) | (113) | ||
Accounts payable and other | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (1) | (1) | ||
Accounts payable and other | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (237) | (313) | ||
Accounts payable and other | Commodities | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (330) | (555) | ||
Accounts payable and other | Commodities | Commodities | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (330) | (443) | ||
Accounts payable and other | Commodities | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (112) | |||
Accounts payable and other | Commodities | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
Accounts payable and other | Commodities | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
Accounts payable and other | Foreign exchange | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (275) | (367) | ||
Accounts payable and other | Foreign exchange | Foreign exchange | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (38) | (54) | ||
Accounts payable and other | Foreign exchange | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
Accounts payable and other | Foreign exchange | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
Accounts payable and other | Foreign exchange | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (237) | (313) | ||
Accounts payable and other | Interest rate | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (2) | (4) | ||
Accounts payable and other | Interest rate | Interest rate | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (2) | |||
Accounts payable and other | Interest rate | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (1) | (1) | ||
Accounts payable and other | Interest rate | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (1) | (1) | ||
Accounts payable and other | Interest rate | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
Other long-term liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (330) | (625) | ||
Other long-term liabilities | Total trading activity | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (118) | (131) | ||
Other long-term liabilities | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (32) | |||
Other long-term liabilities | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (1) | (1) | ||
Other long-term liabilities | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (211) | (461) | ||
Other long-term liabilities | Commodities | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (118) | (162) | ||
Other long-term liabilities | Commodities | Commodities | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (118) | (131) | ||
Other long-term liabilities | Commodities | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (31) | |||
Other long-term liabilities | Commodities | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
Other long-term liabilities | Commodities | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
Other long-term liabilities | Foreign exchange | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (211) | (461) | ||
Other long-term liabilities | Foreign exchange | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
Other long-term liabilities | Foreign exchange | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
Other long-term liabilities | Foreign exchange | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (211) | (461) | ||
Other long-term liabilities | Interest rate | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (1) | (2) | ||
Other long-term liabilities | Interest rate | Cash Flow Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | (1) | ||
Other long-term liabilities | Interest rate | Fair Value Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | (1) | (1) | ||
Other long-term liabilities | Interest rate | Net Investment Hedges | ||||
Derivatives, Fair Value [Line Items] | ||||
Gross Derivative Instruments Presented on the Balance Sheet | 0 | |||
LMCI Restricted Investments | ||||
Derivatives, Fair Value [Line Items] | ||||
Net unrealized losses for the year ended December 31 | (28) | 0 | ||
Other Restricted Investments | ||||
Derivatives, Fair Value [Line Items] | ||||
Net unrealized losses for the year ended December 31 | (1) | 0 | ||
Fixed income securities | LMCI Restricted Investments | ||||
Derivatives, Fair Value [Line Items] | ||||
Fixed income securities (maturing within 5-10 years) | 9 | |||
Fixed income securities (maturing after 10 years) | 513 | 261 | ||
Fixed income securities | 522 | 261 | ||
Fixed income securities | Other Restricted Investments | ||||
Derivatives, Fair Value [Line Items] | ||||
Fixed income securities (maturing within 1 year) | 19 | 26 | ||
Fixed income securities (maturing within 1-5 years) | 117 | 64 | ||
Fixed income securities | CAD 136 | CAD 90 |
RISK MANAGEMENT AND FINANCIA124
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses)/Gains (Details) - CAD CAD in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commodities | |||
Derivative [Line Items] | |||
Amount of unrealized gains/(losses) in the year | CAD 123 | CAD (37) | |
Amount of realized (losses)/gains in the year | (204) | (151) | |
Commodities | Derivative instruments in hedging relationships | |||
Derivative [Line Items] | |||
Amount of realized (losses)/gains in the year | (167) | (179) | |
Foreign exchange | |||
Derivative [Line Items] | |||
Amount of unrealized gains/(losses) in the year | 25 | (21) | |
Amount of realized (losses)/gains in the year | 62 | (112) | |
Foreign exchange | Derivative instruments in hedging relationships | |||
Derivative [Line Items] | |||
Amount of realized (losses)/gains in the year | (101) | 0 | |
Interest rate | Derivative instruments in hedging relationships | |||
Derivative [Line Items] | |||
Amount of realized (losses)/gains in the year | CAD 4 | CAD 8 | |
U.S. Northeast Merchant Power Assets | |||
Derivative [Line Items] | |||
Loss on cash flow hedge | CAD 49 | ||
Gain on cash flow hedge | CAD 7 |
RISK MANAGEMENT AND FINANCIA125
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - CAD | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Components of OCI related to derivatives | ||
Components of fair value hedge ineffectiveness, amounts excluded from assessment of hedge effectiveness, amount | CAD 0 | CAD 0 |
Cash Flow Hedges | ||
Components of OCI related to derivatives | ||
Change in fair value of derivative instruments recognized in OCI (effective portion) | 44,000,000 | (92,000,000) |
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion) | 71,000,000 | 144,000,000 |
Cash Flow Hedges | Commodities | Power | ||
Components of OCI related to derivatives | ||
Change in fair value of derivative instruments recognized in OCI (effective portion) | 39,000,000 | (92,000,000) |
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion) | 57,000,000 | 128,000,000 |
Cash Flow Hedges | Interest rate | ||
Components of OCI related to derivatives | ||
Change in fair value of derivative instruments recognized in OCI (effective portion) | 5,000,000 | |
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion) | CAD 14,000,000 | CAD 16,000,000 |
RISK MANAGEMENT AND FINANCIA126
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative – Asset | ||
Total Derivative Assets | CAD 509,000,000 | CAD 610,000,000 |
Amounts Available for Offset | (389,000,000) | (512,000,000) |
Net Amounts | 120,000,000 | 98,000,000 |
Derivative – Liability | ||
Derivative Instrument Liabilities: | (937,000,000) | (1,551,000,000) |
Amounts Available for Offset | 389,000,000 | 512,000,000 |
Net Amounts | (548,000,000) | (1,039,000,000) |
Cash collateral provided by the Company | 305,000,000 | 482,000,000 |
Letters of credit provided by the Company | 27,000,000 | 41,000,000 |
Cash collateral received by the Company | 0 | 0 |
Letters of credit received by the Company | 3,000,000 | 2,000,000 |
Credit Risk Related Contingent Features | ||
Aggregate fair value of derivative instruments in a net liability position | 19,000,000 | 32,000,000 |
Derivative liability, fair value of collateral | 0 | 0 |
Additional collateral required if credit-risk-related contingent features were triggered | 19,000,000 | 32,000,000 |
Foreign exchange | ||
Derivative – Asset | ||
Total Derivative Assets | 26,000,000 | 96,000,000 |
Amounts Available for Offset | (26,000,000) | (93,000,000) |
Net Amounts | 0 | 3,000,000 |
Derivative – Liability | ||
Derivative Instrument Liabilities: | (486,000,000) | (828,000,000) |
Amounts Available for Offset | 26,000,000 | 93,000,000 |
Net Amounts | (460,000,000) | (735,000,000) |
Interest rate | ||
Derivative – Asset | ||
Total Derivative Assets | 4,000,000 | 5,000,000 |
Amounts Available for Offset | (1,000,000) | (1,000,000) |
Net Amounts | 3,000,000 | 4,000,000 |
Derivative – Liability | ||
Derivative Instrument Liabilities: | (3,000,000) | (6,000,000) |
Amounts Available for Offset | 1,000,000 | 1,000,000 |
Net Amounts | (2,000,000) | (5,000,000) |
Power | Commodities | ||
Derivative – Asset | ||
Total Derivative Assets | 479,000,000 | 509,000,000 |
Amounts Available for Offset | (362,000,000) | (418,000,000) |
Net Amounts | 117,000,000 | 91,000,000 |
Derivative – Liability | ||
Derivative Instrument Liabilities: | (448,000,000) | (717,000,000) |
Amounts Available for Offset | 362,000,000 | 418,000,000 |
Net Amounts | CAD (86,000,000) | CAD (299,000,000) |
RISK MANAGEMENT AND FINANCIA127
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value Hierarchy | ||
Derivative Instrument Assets: | CAD 509 | CAD 610 |
Derivative Instrument Liabilities: | (937) | (1,551) |
Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 479 | 509 |
Derivative Instrument Liabilities: | (448) | (717) |
Foreign exchange contracts | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 26 | 96 |
Derivative Instrument Liabilities: | (486) | (828) |
Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 4 | 5 |
Derivative Instrument Liabilities: | (3) | (6) |
Recurring basis | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | (428) | (941) |
Recurring basis | Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 479 | 509 |
Derivative Instrument Liabilities: | (448) | (717) |
Recurring basis | Foreign exchange contracts | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 26 | 96 |
Derivative Instrument Liabilities: | (486) | (828) |
Recurring basis | Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 4 | 5 |
Derivative Instrument Liabilities: | (3) | (6) |
Recurring basis | Quoted Prices in Active Markets (Level I) | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | 32 | (68) |
Recurring basis | Quoted Prices in Active Markets (Level I) | Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 134 | 34 |
Derivative Instrument Liabilities: | (102) | (102) |
Recurring basis | Significant Other Observable Inputs (Level II) | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | (476) | (882) |
Recurring basis | Significant Other Observable Inputs (Level II) | Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 326 | 462 |
Derivative Instrument Liabilities: | (343) | (611) |
Recurring basis | Significant Other Observable Inputs (Level II) | Foreign exchange contracts | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 26 | 96 |
Derivative Instrument Liabilities: | (486) | (828) |
Recurring basis | Significant Other Observable Inputs (Level II) | Interest rate | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 4 | 5 |
Derivative Instrument Liabilities: | (3) | (6) |
Recurring basis | Significant Unobservable Inputs (Level III) | ||
Fair Value Hierarchy | ||
Assets and (liabilities), net | 16 | 9 |
Recurring basis | Significant Unobservable Inputs (Level III) | Commodity contract | Power | ||
Fair Value Hierarchy | ||
Derivative Instrument Assets: | 19 | 13 |
Derivative Instrument Liabilities: | CAD (3) | CAD (4) |
RISK MANAGEMENT AND FINANCIA128
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Energy Revenue | ||
Net change in the Level III fair value category | ||
Revenues include unrealized gains attributed to derivatives in the Level III category | CAD 7 | CAD 7 |
Commodity contract | Power | ||
Net change in the Level III fair value category | ||
Balance at beginning of year | 9 | 4 |
Total gains included in Net income | 13 | 3 |
Sales | (3) | (2) |
Settlements | (2) | (1) |
Transfers out of Level III | (1) | 5 |
Balance at end of year | 16 | CAD 9 |
Commodity contract | Power | Level III | ||
Net change in the Level III fair value category | ||
Decrease in fair value of outstanding derivative instruments included in Level III due to a 10% increase in commodity prices | 2 | |
Increase in fair value of outstanding derivative instruments included in Level III due to a 10% decrease in commodity prices | CAD 2 |
CHANGES IN OPERATING WORKING129
CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CHANGES IN OPERATING WORKING CAPITAL | |||
Increase in Accounts receivable | CAD (482) | CAD (65) | CAD (189) |
Increase in Inventories | (87) | (3) | (28) |
Increase in Assets held for sale | (13) | 0 | 0 |
Decrease/(increase) in Other current assets | 328 | (272) | (385) |
Increase/(decrease) in Accounts payable and other | 424 | (97) | 377 |
Increase in Accrued interest | 62 | 91 | 36 |
Increase in Liabilities related to assets held for sale | 16 | 0 | 0 |
Decrease/(increase) in Operating Working Capital | CAD 248 | CAD (346) | CAD (189) |
OTHER ACQUISITIONS AND DISPO130
OTHER ACQUISITIONS AND DISPOSITIONS (Details) CAD in Millions, $ in Millions | May 01, 2016USD ($) | Mar. 31, 2016USD ($) | Feb. 01, 2016USD ($)MW | Jan. 01, 2016USD ($) | Dec. 31, 2015CAD | Apr. 30, 2015USD ($) | Nov. 30, 2014CAD | Oct. 31, 2014USD ($) | Apr. 30, 2014CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2014CADfacility | Nov. 30, 2015 |
Business Acquisition [Line Items] | |||||||||||||
Gain (loss) on disposal | CAD (833) | CAD (125) | CAD 117 | ||||||||||
Contributions made to equity investments | 765 | 493 | 256 | ||||||||||
Proceeds from sale of assets, net of transaction costs | 6 | 0 | 196 | ||||||||||
Purchase price | CAD 13,608 | CAD 236 | CAD 241 | ||||||||||
Gas Pacifico and INNERGY | Disposal group, not discontinued operations | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Gain (loss) on disposal | CAD 9 | ||||||||||||
Ownership interest (percent) | 30.00% | ||||||||||||
Proceeds from sale of assets, net of transaction costs | CAD 9 | ||||||||||||
Proceeds from sale of assets, net of tax | CAD 8 | ||||||||||||
Cancarb Limited | Disposal group, not discontinued operations | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Proceeds from sale of assets, net of transaction costs | CAD 190 | ||||||||||||
Gain (loss) on disposition, gross | 108 | ||||||||||||
Gain (loss) on disposition, net of tax | CAD 99 | ||||||||||||
Natural Gas – Ironwood | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Purchase price | $ | $ 653 | ||||||||||||
Power plant capacity (in megawatts) | MW | 778 | ||||||||||||
Ontario solar projects | Energy | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Number of facilities acquired | facility | 4 | ||||||||||||
Purchase price | CAD 241 | ||||||||||||
Term of contract to sell solar power (in years) | 20 years | ||||||||||||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Disposal group, disposed of by sale, not discontinued operations | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Ownership interest before transaction, percent | 49.90% | ||||||||||||
Total consideration | $ | $ 223 | ||||||||||||
Cash received | $ | 188 | ||||||||||||
Assumption of debt by purchaser | $ | $ 35 | ||||||||||||
Iroquois | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Additional ownership acquired (percent) | 0.65% | 4.87% | |||||||||||
Ownership interest (percent) | 50.00% | 49.35% | |||||||||||
Contributions made to equity investments | $ | $ 7 | $ 54 | |||||||||||
Gas Transmission Northwest | Disposal group, disposed of by sale, not discontinued operations | Natural Gas | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Ownership interest before transaction, percent | 30.00% | ||||||||||||
Total consideration | $ | $ 457 | ||||||||||||
Cash received | $ | 264 | ||||||||||||
Assumption of debt by purchaser | $ | 98 | ||||||||||||
Gas Transmission Northwest | Disposal group, disposed of by sale, not discontinued operations | Natural Gas | Class B units | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Receipt of new units | $ | $ 95 | ||||||||||||
Bison LLC | Natural Gas | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Ownership interest before transaction, percent | 30.00% | ||||||||||||
Cash received | $ | $ 215 | ||||||||||||
Bruce Power | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Ownership interest (percent) | 48.50% | 48.50% | 48.50% | ||||||||||
Bruce Power | Energy | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Ownership interest (percent) | 48.50% | ||||||||||||
Bruce B | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Additional ownership acquired (percent) | 14.89% | 14.89% | |||||||||||
Ownership interest (percent) | 46.50% | 46.50% | 31.60% | ||||||||||
Contributions made to equity investments | CAD 236 | ||||||||||||
Bruce A | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Ownership interest (percent) | 48.90% | 48.90% | 48.90% |
COMMITMENTS, CONTINGENCIES A131
COMMITMENTS, CONTINGENCIES AND GUARANTEES - Operating Leases (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Minimum Lease Payments | |||
2,017 | CAD 129 | ||
2,018 | 122 | ||
2,019 | 106 | ||
2,020 | 69 | ||
2,021 | 69 | ||
2022 and thereafter | 621 | ||
Minimum Lease Payments | 1,116 | ||
Amounts Recoverable under Subleases | |||
2,017 | 5 | ||
2,018 | 4 | ||
2,020 | 2 | ||
2,020 | 2 | ||
2,021 | 1 | ||
2022 and thereafter | 3 | ||
Amounts Recoverable under Subleases | 17 | ||
Net Payments | |||
2,017 | 124 | ||
2,018 | 118 | ||
2,019 | 104 | ||
2,020 | 67 | ||
2,021 | 68 | ||
2022 and thereafter | 618 | ||
Net Payments | 1,099 | ||
Rent Expense | |||
Net rental expense on operating leases | CAD 145 | CAD 131 | CAD 114 |
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 | ||
Ravenswood | |||
Rent Expense | |||
Commitment decrease in 2018 | CAD 54 | ||
Commitment decrease in 2019 | 35 | ||
Commitment decrease in 2022 and thereafter | CAD 106 |
COMMITMENTS, CONTINGENCIES A132
COMMITMENTS, CONTINGENCIES AND GUARANTEES - Other Commitments and Contingencies (Details) CAD in Millions, $ in Billions | 12 Months Ended | |||
Dec. 31, 2016CAD | Dec. 31, 2015CAD | Jan. 06, 2016USD ($) | Dec. 31, 2014CAD | |
Contingencies | ||||
Amount accrued related to operating facilities for the estimated expenses to remediate the sites | CAD 39 | CAD 32 | CAD 31 | |
Recover amount under claim (more than) | $ | $ 15 | |||
Canadian Natural Gas Pipelines | Capital expenditures | ||||
Other Commitments | ||||
Commitment for capital expenditures | 800 | 500 | ||
U.S. Natural Gas Pipelines | Capital expenditures | ||||
Other Commitments | ||||
Commitment for capital expenditures | 100 | 200 | ||
Mexico Natural Gas Pipelines | Capital expenditures | ||||
Other Commitments | ||||
Commitment for capital expenditures | 2,100 | 200 | ||
Liquids Pipelines | Capital expenditures | ||||
Other Commitments | ||||
Commitment for capital expenditures | 200 | 800 | ||
Energy | Capital expenditures | ||||
Other Commitments | ||||
Commitment for capital expenditures | 500 | 600 | ||
Corporate | Capital expenditures | ||||
Other Commitments | ||||
Commitment for capital expenditures | CAD 200 | CAD 100 |
COMMITMENTS, CONTINGENCIES A133
COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) CAD in Millions | Dec. 31, 2016CAD | Dec. 31, 2015CADguarantee |
Guarantees | ||
Number of guarantees without a termination date | guarantee | 1 | |
Contingent financial obligation | ||
Guarantees | ||
Potential Exposure | CAD 980 | CAD 227 |
Carrying Value | 82 | 26 |
Contingent financial obligation | Sur de Texas | ||
Guarantees | ||
Potential Exposure | 805 | 0 |
Carrying Value | 53 | 0 |
Contingent financial obligation | Bruce Power | ||
Guarantees | ||
Potential Exposure | 88 | 88 |
Carrying Value | 1 | 2 |
Contingent financial obligation | Other jointly owned entities | ||
Guarantees | ||
Potential Exposure | 87 | 139 |
Carrying Value | CAD 28 | CAD 24 |
CORPORATE RESTRUCTURING COST134
CORPORATE RESTRUCTURING COSTS (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Restructuring Cost and Reserve [Line Items] | ||
Provision recorded for restructuring charges | CAD 99 | CAD 87 |
Total corporate restructuring charges | 44 | |
Restructuring costs capitalized | 8 | |
Employee Severance | ||
Restructuring Cost and Reserve [Line Items] | ||
Corporate restructuring costs incurred | 122 | |
Provision recorded for restructuring charges | 36 | 60 |
Total corporate restructuring charges | 0 | |
Restructuring costs recoverable through regulatory and tolling structures | 58 | |
Employee Severance | Regulatory asset | ||
Restructuring Cost and Reserve [Line Items] | ||
Total corporate restructuring charges | 22 | 44 |
Employee Severance | Plant operating cost and other | ||
Restructuring Cost and Reserve [Line Items] | ||
Total corporate restructuring charges | 22 | CAD 157 |
Lease Commitments | ||
Restructuring Cost and Reserve [Line Items] | ||
Total corporate restructuring charges | CAD 44 |
CORPORATE RESTRUCTURING COSTS -
CORPORATE RESTRUCTURING COSTS - Schedule of Change In Restructuring Liability (Details) CAD in Millions | 12 Months Ended |
Dec. 31, 2016CAD | |
Restructuring Reserve [Roll Forward] | |
Restructuring liability as at December 31, 2015 | CAD 87 |
Restructuring charges | 44 |
Cash payments | (32) |
Restructuring Liability as at December 31, 2016 | 99 |
Employee Severance | |
Restructuring Reserve [Roll Forward] | |
Restructuring liability as at December 31, 2015 | 60 |
Restructuring charges | 0 |
Cash payments | (24) |
Restructuring Liability as at December 31, 2016 | 36 |
Lease Commitments | |
Restructuring Reserve [Roll Forward] | |
Restructuring liability as at December 31, 2015 | 27 |
Restructuring charges | 44 |
Cash payments | (8) |
Restructuring Liability as at December 31, 2016 | CAD 63 |
VARIABLE INTEREST ENTITIES (Det
VARIABLE INTEREST ENTITIES (Details) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Variable interest entity ownership percentage | 100.00% |
VARIABLE INTEREST ENTITIES - As
VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Variable Interest Entity [Line Items] | ||||
Cash and cash equivalents | CAD 1,016 | CAD 850 | CAD 489 | CAD 927 |
Accounts receivable | 2,075 | 1,387 | ||
Inventories | 368 | 323 | ||
Other | 908 | 1,338 | ||
Total Current Assets | 8,084 | 3,918 | ||
Plant, Property and Equipment | 54,475 | 44,817 | ||
Equity Investments | 6,544 | 6,214 | ||
Goodwill | 13,958 | 4,812 | CAD 4,034 | |
Intangible and Other Assets | 1 | 0 | ||
Assets | 88,051 | 64,398 | ||
Accounts payable and other | 3,861 | 2,653 | ||
Accrued interest | 595 | 520 | ||
Current portion of long-term debt (Note 17) | 1,838 | 2,547 | ||
Total Current Liabilities | 7,680 | 7,362 | ||
Regulatory Liabilities (Note 10) | 2,121 | 1,159 | ||
Other Long-Term Liabilities | 1,183 | 1,260 | ||
Deferred Income Tax Liabilities (Note 16) | 7,662 | 5,144 | ||
Long-Term Debt (Note 17) | 38,312 | 28,909 | ||
Total Liabilities | 60,889 | 46,243 | ||
Variable Interest Entity, Primary Beneficiary | ||||
Variable Interest Entity [Line Items] | ||||
Cash and cash equivalents | 77 | 54 | ||
Accounts receivable | 71 | 55 | ||
Inventories | 25 | 25 | ||
Other | 10 | 6 | ||
Total Current Assets | 183 | 140 | ||
Plant, Property and Equipment | 3,685 | 3,704 | ||
Equity Investments | 606 | 664 | ||
Goodwill | 525 | 541 | ||
Assets | 5,000 | 5,049 | ||
Accounts payable and other | 80 | 74 | ||
Accrued interest | 21 | 21 | ||
Current portion of long-term debt (Note 17) | 76 | 45 | ||
Total Current Liabilities | 177 | 140 | ||
Regulatory Liabilities (Note 10) | 34 | 33 | ||
Other Long-Term Liabilities | 4 | 4 | ||
Deferred Income Tax Liabilities (Note 16) | 7 | 0 | ||
Long-Term Debt (Note 17) | 2,827 | 2,998 | ||
Total Liabilities | CAD 3,049 | CAD 3,175 |
VARIABLE INTEREST ENTITIES - Ca
VARIABLE INTEREST ENTITIES - Carrying Value of VIEs and Maximum Exposure (Details) - Variable Interest Entity, Not Primary Beneficiary - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Balance sheet | ||
Equity investments | CAD 4,964 | CAD 5,410 |
Off-balance sheet | ||
Potential exposure to guarantees | 163 | 227 |
Maximum exposure to loss | CAD 5,127 | CAD 5,637 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - CAD | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
Due from affiliates | CAD 2,392,000,000 | CAD 2,476,000,000 | |
Due to affiliates | 2,358,000,000 | 311,000,000 | |
Interest expense, related party | 22,000,000 | 28,000,000 | CAD 37,000,000 |
Discount Notes | |||
Related Party Transaction [Line Items] | |||
Due from affiliates | CAD 2,392,000,000 | CAD 2,376,000,000 | |
Effective Interest Rate (percent) | 0.90% | 0.90% | |
Demand Credit Facility | |||
Related Party Transaction [Line Items] | |||
Due from affiliates | CAD 100,000,000 | ||
Effective Interest Rate (percent) | 2.70% | 2.70% | |
Due to affiliates | CAD 2,358,000,000 | ||
Amount | 3,000,000,000 | ||
Affiliates | |||
Related Party Transaction [Line Items] | |||
Amount | 3,500,000,000 | ||
Unsecured Credit Facility | |||
Related Party Transaction [Line Items] | |||
Effective Interest Rate (percent) | 3.50% | ||
Due to affiliates | CAD 311,000,000 | ||
Transcanada | |||
Related Party Transaction [Line Items] | |||
Interest income, related party | 16,000,000 | 29,000,000 | 37,000,000 |
Accounts receivable, related parties | 0 | 13,000,000 | |
Accounts payable, related parties | 3,000,000 | 12,000,000 | |
Interest Related Party | |||
Related Party Transaction [Line Items] | |||
Interest paid | 20,000,000 | CAD 29,000,000 | CAD 37,000,000 |
Columbia Pipeline Partners LP | Affiliates | |||
Related Party Transaction [Line Items] | |||
Amount | CAD 1,800,000,000 |